IR 05000341/1998008
| ML20236Q926 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 07/14/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20236Q915 | List: |
| References | |
| 50-341-98-08, 50-341-98-8, NUDOCS 9807210123 | |
| Download: ML20236Q926 (21) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION lli Docket No:
50-341 License No:
NPF-43 Report No:
50-341/98008(DRP)
Licensee:
Detroit Edison Company Facility:
Enrico Fermi, Unit 2 Location:
6400 N. Dixie Hwy.
Newport, MI 48166 Dates:
May 4 through June 18,1998 Inspectors:
G. Harris, Senior Resident inspector C. O'Keefe, Resident inspector Approved by:
Bruce Burgess, Chief Reactor Projects Branch 6 l
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9907210123 990714 PDR ADOCK 05000341 G
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EXECUTIVE SUMMARY Enrico Fermi, Unit 2 NRC Inspection Report 50-341/98008(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection.
Operations
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e Centrol room operators were observed to respond in a controlled manner to identified problems with the feedwater and recirculation speed control systems. Operators also l
responded in a conservative manner to steam flow and reactor power oscillations, and facilitated replacement of the scram pilot solenoid valves. (Section 01.1)
The inspectors concluded that the licensee failed to conduct a 10 CFR 50.59 evaluation-e prior to defeating control room annunciators that were described in the Updating Final Safety Analysis Report (UFSAR). The 4censee's procedures allowed control room annunciators described in the UFSAR to be defeated by the operators without l
determining whether or not a safety evaluation was required. The inspectors concluded that the licensee's corrective actions were prompt, broad, and comprehensive. A no response violation was issued. (Section 01.2)
The inspectors observed good operator response in controlling unexpected steam flow e
and power oscillations in the primary coolant system. The condition was apparently caused by unstable steam flows in balance of plant equipment complicated by competing control system responses. Engineering assistance and vendor support resulted in timely investigation of the problems. The operators were provided with instructions on how to respond to the recurrence of power oscillations. (Section 01.3)
Maintenance o
Some weaknesses in the conduct of maintenance of activities was noted during the period, however, the majority of the activities were conducted in an acceptable manner.
Equipment problems with the recirculation and feedwater control systems had minor impact on normal plant operations. Investigation and repair of these systems continue.
(Section M1.1)
The inspectors concluded that the licensee successfully addressed several problems e
identified during a 1997 TBHVAC systtem outage. The licensee appropriately performed a safety evaluation and the UFSAR was revised to address elevated temperature effects on safety-related equipment during normal plant operation. (Section M1.2)
The inspectors identified that the licensee performed a hydrogen recombiner heater
resistance check before completing the heater and controller functional test. The Technical Specifications implied a test sequence to successfully complete the surveillance. The licensee agreed and reperformed all testing after completing corrective maintenance on the heater controller. (Section M1.3)
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e Two outages performed to replace control rod SSPVs were planned and executed in a highly coordinated manner. Maintenance teams from each work group performed a complex sequence of tasks on six control rods simultaneously in a quality manner.
Operations and radiation protection personnel provided close support, ensuring prompt equipment restoration and testing. The outages were scheduled so that experier.ce was gained during the first outage on peripheral rods, so that the subsequent work on inner rods, which were time-sensitive, could be performed more smoothly. (Section M1.4)
l Enoineerina Training for performing safety evaluations was significantly improved by providing a broad e
understanding of the licensing process and licensing basis for the plant. Trainee feedback was positive, resulting in many requests for the training from outside the group requiring the training. However, discussions indicated that the site was inconsistent in its implementation and documentation of the 10 CFR 50.5g process. (Section E5.1)
Plant SuDDori The spent fuel pool cleanout project was planned in detail, giving high priority to "As Low e
As Reasonably Achievable" considerations in the methods used. This led to several i
innovative techniques for handling and packaging the radioactive material. Supervision, contractor control, administrative controls, log keeping, and communications with operations personnel were significantly improved. Problems were promptly communicated and resolved in a formal manner. (Section R1.1)
Due to a conservative receipt inspection methodology, the licensee was able to identify e
that a shipping cask received from the disposal site contained a highly radioactive pin from a control rod blade which had been inadvertently overlooked during a previous shipment. The licensee did a good job in identifying the material and communicating with federal and state agencies to resolve the issue. (Section R1.1)
The emergency response organization received good training value from periodic site e
drills. Scenarios challenged all aspects of emergency response, although the inspectors identified one case where unrealistic simulation was provided for hydrogen generation inside containment as a result of simulated fuel damage. Engineering support personnel did not always question the reasons behind reports, and as a result spent time trying to understand unexpected plant conditions. Continued performance problems were observed with the post-accident sampling system. (Section P1.1)
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Rooort Details Summary of Plant Status Unit 2 began this inspection period at 96 percent power. On May 6, power was reduced briefly to about 25 percent to correct problems associated with the feedwater control system. Power was also reduced to between 60 and 70 percent on May 29 through June 2 to perform scheduled maintenance on the control rod drive hydraulic control units. Power was retumed to 96 percent on June 2 and remained at that level through the end of the inspection period.
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1. Ooerations
Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. Specific events and noteworthy observations are detailed in the sections below.
Plant operations personnel continued to provide prompt response to identified operator work arounds. The appropriate priority was placed on work arounds with higher safety significance. Also, operations personnel continued to identify work arounds that could impact normal plant operations.
On May 15, operations personnel recognized and responded to an electrical ground which necessitated removal of control power for the general service water pump house.
The removal of control power caused a loss of all components in the pump house,
l including the diesel and electric fire pumps. Control room personnel coordinated repair efforts with electrical maintenance and system engineering. Repairs were completed in a I
timely manner and control power was restored, re-instating control of all components within the pump house.
Operators were attentive to control board parameters during this inspection period. Off
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normal indications were consistently identified and reported. For example, a licensed
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operator promptly identified an unexpected reactor recirculation pump speed reduction before power changed significantly. The transient was terminated when the operator locked the scoop tube positioner and reduced speed on the unaffected reactor recirculation pump. Also, operators identified numerous small feed flow transients that resulted in reactor water level changes up to three inches below normal. The licensee installed temporary monitoring instrumentation in the feedwater controller in order to identify the source of the problem. A project managerwas assigned, on a ful'-time basis, to lead the effort to identify and correct this problem. The cause of the feedwater transients and the unexpected reactor recirculation pump speed reduction has not yet
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01.2 Procedure Allowed Annunc:ators to be Defeated Without 10 CFR 50.59 Review a.
Inspection Scope (37001. 71707)
The inspectors reviewed technical documentation, the Updated Final Safety Analysis Report (UFSAR), alarm defeat procedures, safety evaluation reports (SER), alarm defeat log, temporary modifications, and jumper control procedures. The inspectors also conducted interviews with operations and engineering personnel.
b.
Observations and Findinas The inspectors questioned the process used to defeat a number of annunciators for control board indications, which facilitated achieving a " black board" status (no annunciators being continuously actuated in the control room). Operators indicated that System Operating Procedure (SOP) 23.621, " Main Control Room Annunciators and Sequence Recorder," contained a procedure for defeating alarms. The inspectors reviewed the defeated alarms and noted that some of the defeated alarms were desdbed in the UFSAR. The inspectors further determined that each had been removed from sewice without performing a 10 CFR 50.59 screening evaluation to determine the remcval constituted a change to the plant as described in the UFSAR. The inspectors reviewed SOP 23.621 and noted it did not contain a requirement to perform a screening evaluation before defeating an annunciator.
The inspectors reviewed Deviation Event Report (DER) 96-1863, that had previously addressed whether a 10 CFR 50.59 screening evaluation was required when jumpers were used to defeat annunciators. The DER stated that the use of the annunciator defeat procedure resulted in a limited review prior to defeating a field input. The DER response concluded that no screening evaluations were necessary since the installation of the jumpers was conducted using en approved procedure. The inspectors determined that the licensee's evaluation of this issue was performed by the wrong organization (operations), resulting in missing an opportunity to identify and correct procedures that did not require a screening evaluation prior to removal of control room annunciators.
The inspectors noted that Operations Department Instruction 009, Revision 3, " Control Room Response to Annunciators," stated that efforts should be taken to eliminate nuisance alarms. The options provided in the procedure to remove a nuisance alarm included the issuance of a work request, defeating the alarm function, or initiating a change in equipment lineup or plant status. The instruction, however, did not refer to the need to perform an screening evaluation prior to removing the alarm from service.
The inspectors concluded that the failure to conduct a 10 CFR 50.59 screening evaluation prior to the defeat of control room annunciators described in the UFSAR was considered a violation of 10 CFR 50.59. The inspectors noted that the licensee had initiated an investigation and that corrective actions were taken to resolve the issue. The licensee's corrective actions included revising the procedure to require an evaluation for annunciators that will be taken out of service for an extended period of time, reactivating defeated annunciators, review of jumper control procedures, issuance of required training, and the circulation of night orders to communicate the problem to plant staff.
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The inspectors concluded that the licensee's corrective actions were prompt, broad and comprehensive. Based on completion of these corrective actions, no response to the violation is required. This item is closed. (VIO 50-341/98008-01)
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Conclusions The inspectors concluded that the licensee failed to conduct a 10 CFR 50.59 evaluation prior to defeating control room annunciators that were described in the UFSAR. The licensee's procedures allowed control room annunciators described in the UFSAR to be defeated by the operators without determining whether or not a safety evaluation was required. The inspectors concluded that the licensee's corrective actions were prompt, broad and comprehensive. A no response violation was issued.
01.3 Power and Steam Flow Oscillations Observed at Intermediate Power Levels a.
Inspection Scope (93702. 71707. 37551)
The inspectors responded to the control room to observe operators respond to unexpected reactor steam flow and power oscillations on May 31. The licensee's investigation into the source of the power oscillations and on assessment of plant response were also observed. The results of an engineering evaluation and root cause determination for the steam flow and reactor power oscillations were discussed with system engineering supervisory personnel.
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Observations and Findinas Operators reduced reactor power during the weekend of May 29 - 31, to perform scheduled maintenance on control rod hydraulic control units (HCUs). While at about 70 percent power on May 31, reactor power and steam flow oscillations were observed following the insertion of a high-worth control rod for scram time testing. Additional reactor power and steam flow oscillations occt'rred later in the day, one of which also followed control rod insertion. The amplitude of the observed oscillations were measured at approximately 10 percent power peak to peak with a 6-second period. The duration of the oscillations varied between 1 minute and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
Control room operators quickly identified the occurrence of the power oscillations and verified that the plant was not operating near the instability region of the power to flow curves. During the first two occurrences, operators attempted to reduce power and restore a more symmetric control rod pattem by inserting control rods. However, in both cases operators observed that the oscillations grew worse following control rod insertions.
On June 2, the licensee proposed increasing reactor power back to 96 percent during a conference call with Region 111 and the Office of Nuclear Reactor Regulation. Without
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having identified a specific cause by that time, the licensee concluded that the problem was caused by unstable flow conditions in the steam system due to multiple control j
system interactions. The reactor was ruled out as the source of the oscillations because j
the observed period of oscillation was much longer than those characteristic of reactor power oscillations. The licensee stated that the interactions would be eliminated at normal high power conditions. Subsequent to the conference call, reactor power was
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increased in steps to 96 percent on June 3, while closely monitoring system performance.
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The problem did not recur during power ascension.
. A licensee investigation team evaluated the available data and concluded that a check valve in an extraction steam line between the high pressure turbine and the 6N feedwater heater was malfunctioning. The air line that assisted in the operation of this valve had been found to be broken several weeks earlier. A system perturt>ation, such as the pressure spike caused by scram time testing a relatively high-worth control rod, was postulated to start oscillating steam flows between the equalizing header, the turbine, and
- the moisture separator reheater seal tanks. - Multiple control systems were affected with the combined response resulting in a relatively stable oscillation. This was believed by the licensee to be limited to power levels between about 65 and 70 percent. Outside this band, the affected check valve was expected to stay either fully open or fully closed and not change state in response to small pressure changes.
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The inspectors responded to the control room to observe operator response to the event.
Control room operators discussed plant response with reactor engineers and reviewed
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available guidance on power oscillations. The decision to attempt to reduce power in an attempt to retum the plant to a stable condition appeared appropriate. Operations management promptly obtained engineering assistance to help assess the cause of the problem, including a request from the fuel vendor to evaluate the power oscillations.
The inspectors observed that operatois were given instructions on how to respond should
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method to reduce reactor power through the region of concem (65 to 70 percent). Also, the operators were instructed to scram the reactor if power oscillations exceeded 10 percent. At the conclusion of the inspection, the licensee continued to evaluate when j
corrective maintenance to the check valve should be performed.
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Conclusions The inspectors observed goed operator response in controlling unexpected steam flow and power oscillations in be primary system. The condition was apparently caused by unstable steam flows in balance of plant equipment complicated by competing control system responses.' Engineering assistance and vendor support resulted in timely investigation of the problems. The operators were provided with instructions on how to respond to the recurrence of power oscillations.
Operational Status of Facilities and Equipment O2.1 Enoineered Safety Feature (ESF) System Walkdowns (71707)
The inspectors used inspection Procedure 71707 to walk down accessible portions of the following ESF systems:
e Emergency Diesel Generator (EDG) 11 e
Reactor Core Isolation Cooling System o
Emergency Equipment Cooling Water System e
24/48 VDC Chargers and Battery High Pressure Coolant Injection System e
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Division 1 Non-Interruptible Air Supply System o
Division 1 and 2 Ultimate Heat Sink and Mechanical Draft Cooling Towers e
EDG Fuel Oil Transfer System e
Division 2 Hydrogen Recombiner System
Division 2 Standby Gas Treatment System Equipment operability, material condition, and housekeeping were acceptable in all cases. Several minor discrepancies were brought to the licensee's attention and were corrected. The inspectors identified no substantive concems as a result of these walkdowns. Equipment operability was verified through system and valve lineup and
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parameter verifications.
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Miscellaneous Operations issues (92700)
08.1 (Closed) Deviation 50-341/98003-01: Licensee commitments to Regulatory Guide 1.78,
" Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room
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During a Postulated Hazardous Chemical Release," were not met for some training issues and did not comply with the single failure crHeria for respirators in the control room. The inspectors determined that the licensee 4.ad not performed training for operators to ensure they could distinguish the smells of hazardous chemicals peculiar to the area of the plant or that operators can don respirators within the required time. The licensee added these aspects to their operator training program. Training will be conducted during the next annual requalification.
The inspectors also determined that the licensee had not provided spare respirators in the control room to ensure compliance with the single failure criterion. The licensec corrected this condition by staging two additional respirators in the control room.
Licensee corrective action appeared to be adequate. This item is closed.
11. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Inspection Scope (62707)
The inspectors observed all or portions of the following work activities:
Drywell Cooling Fans 1 and 2 Operability Test
Reactor Protection System-Scram Discharge Volume High Water Level Functional
Test e
Turt>ine Generator Electrical Overspeed Trip Test e
Reactor Flow Unit "A" Functional Test Nuclear Steam Supply Shutoff System-Reactor Cora isolation Cooling Steam Line
Pressure Division 1, Functional Test e
24 Volt Battery Charger Calibration -
Operable Control Rod Functional Check e~
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e Channel Functional Test of Division 14160 Volt Bus 64B and Bus 11EA Undervoltsge Circuits e
Division 1 Control Air Compressor Leak Repairs Division 1 Control Air System Room Cooler Controller Calibration e
e Division 1 Residual Heat Removal (RHR) Surveillance l
e Reactor Building Equipment Drain Sump D073 Pump Check Valve Replacement
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e Division 2 Standby Gas Treatment System Heater Controller Calibration l
e EDG 14 Slow Start Surveillance
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Observations and Findinas
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I in general, work was performed in accordance with work instructions and site practices.
Work instructions were observed to be adequate to accomplish the specified tasks.
Applicable TS actions were verified to be performed and documented properly. Safety tagging was verified to be performed in accordance with station instructions and j
adequate work boundary isolation was established by maintenance personnel.
On May 1, the inspectors observed the work activities performed to replace the "B" sump
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pump discharge check valve for the Reactor Building Equipment Drain Sump D073. The
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inspectors observed that the work site was inside a high contamination area. Appropriate controls were used to monitor for airbome contamination. Sheets of plastic were installed
to avoid contact with contamination inside the sump. The wo* was closely coordinated
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with operations personnel to monitor sump water level and to keep the sump manually pumped down. A radiation protection technician was continuously present and provided excellent support. The system engineer was present to assist in assessing sump equipment condition. During the work, the sump was pumped and workers identified that the discharge line on the "A" pump was spraying water from a flanged connection. This was judged to be the source of the sump problem, rather than the check valve that was under repair. Workers promptly reported this to operations personnel, the system engineer, and work planners.
l The inspectors identified concems about industrial safety, dose minimization, and foreign material exclusion practices. The inspectors observed a worker grinding a part removed from the check valve while inside the sump, allowing debris to fallinto the sump. This was a 30 mr/hr radiation area, while a low dose area was a few feet away. The worker was holding the loose part and the grinder instead of using a holding device or getting assistance. When the inspectors questioned these practices, the worker climbed out of the sump to a low background area, was assisted by.a co-workerin holding the part, and used a high efficiency particulate air filter unit to collect grinding debris.
During the inspection period, some minor system oscillations caused by equipment problems with feedwater and recirculation controller components complicated normal plant operations. In addition, plant operators observed reactor power oscillations caused by secondary equipment degradation. The inspectors noted that investigation and repair i
efforts were conducted in a thorough and coordinated manner. Management involvement in the issues was extensive with frequent briefings and discussions. Maintenance and engineering personnel coordinated efforts to ensure repair activities were performed in a
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thorough manner. Maintenance personnel coordinated extensively with engineering personnel to provide support to repair efforts. Engineering efforts to resolve the I
feedwater and recirculation controller problems were not entirely successful, however, I
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e monitoring equipment was installed in a effort to further identify the component deficiencies.
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Conclusions Some weaknesses in the conduct of maintenance of activities was noted during the period, however, the majority of the activities were conducted in an acceptable manner.
Equipment problems with the recirculation and feedwater control systems had minor impact on normal plant operations. Investigation and repair of these systems continue.
M1.2 Hiah Temperature Conditions Durina Turbine Buildina Heatino Ventilation and Air Conditioning (TBHVAC) System Outaaes Evaluated a.
Inspection Scope (62707)
The inspectors reviewed work week manager reports, the UFSAR, SOPS, DERs, and i
I TSs. In addition, the inspectors interviewed operations and work control personnel, as well as system and component engineering persrnel.
b.
Observations and Findinas The inspectors reviewed system outage reports and noted that a recent May 13-15 turbine building outage was terminated when steam tunnel temperatures limits were approached. Elevated temperatures in the turbine building affected the proper operation of the off gas chillers. In addition, the need to supply the temporary cooling required for the process computer was not identified prior to the start of the outage. The outage co:ncided with a period of unseasonably high ambient temperatures, which was not specifically addressed during outage pir..uung.
The inspectors noted that the previous TBHVAC outage that occurred during September 15-17,1997, had also been terminated due to elevated temperatures.
Operators observed that steam tunnel temperatures had approached the setpoint for autcmatic isolation of main steam isolation valves. At that time it was determined that elevated temperatures in the turbine building steam tunnel can rodeco N environmentally qualified life of the gasket material used in safety-relate resistance temperature detectors, i
As a result of the earlier TBHVAC outage, the licensee developed a sequence of events procedure that required steam tunnel tempem'.ures to be monitored hourly. Elevated building temperatures were addressed by a s<fety evaluation, and the UFSAR was revised to reflect the effect of elevated turbine building temperatures on safety-related resistance temperature detectors. Tlie qualified life for the resistance temperature detectors were adjusted far operating in a higher temperature environment, and as a result were scheduled for replacement during the next refueling outage. In addition, a temperature limit of 190'F in the turbine building steam tunnel was established as a criteria to restore cooling.
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Conclusion The inspectors concluded that the licensee successfully addressed several problems identified during a 1997 TBHVAC system outage. The licensen appropriately performed an SE and the UFSAR was revised to address elevated temperature effects on safety-related equipment during normal plant operation.
M1.3 We_,3kness in Performance of Hydrooen Thergml Recombiner Surveillance
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Ospection Scope (71707)
The inspectors reviewed the Technical Specifications (TS), the UFSAR, control room logs, Surveillance Procedures 24.409.01, * Post Loss of Coolant Accident Thermal Recombiner Functional Test," and 42.220.03, " Division 1 Thermal Hydrogen Recombiner Heater integrity Test and Visual Inspection," work requests, and interviewed operations and maintenance personnel.
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Observations and Findinos The inspectors mviewed control room logs and noted the performance of a surveillance test for hydrogen recombiners. Technical Specifications Surveillance Requirement 4.6.6.1, required that tests be performed at least once every 6 months to verify during a recombiner system functional test that the heater outlet temperature increased to greater than 1150*F within 75 minutes and was maintained for at least 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Due to what was subsequently determined to be controller problems, the heaters could not maintain this temperature for the specified time period.
In addition, the TS, Section 4.6.6.1.b.2, required that the integrity of all heater electrical circuits be verified by performing a resistance to ground test within 60 minutes following the above required functional test. The inspectors noted that the licensee had performed this portion of the test without first successfully completing the system functional test.
The inspectors pointed out that the wording in the TS implied completion of the functional test prior to conducting the resistance to gound test. In addition, technical personnel were not consulted on whether to proceed with the surveillance subsequent to the determination that the functional test could not be successfully performed. Later, the inspectors noted that both procedural and work request instructions advised personnel that the surveillance was to be performed in sequence. The inspectors discussed their observation with the shift technical advisor, shift supervisory personnel and maintenance personnel, who agreed that the entire surveillance should be reperformed once repairs were made to heater enntroller circuit.
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Conclusions The inspectors identified that the licensee performed a hydrogen recombiner heater resistance check before completing the heater and controller functional test. The TS implied a test sequence to successfully complete the surveillance. The licensee agreed and reperformed all testing after completing corrective maintenance on the heater controller, j
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M1.4 Scram Solenoid Pilot Valve (SSPV) Replacement Project Performed in a Coordinated Manner a.
Inspection Scope (62707)
l The inspectors observert preparations for the work, briefings, equipment tagging and restoration, individual control rod scram time testing, and various phases of the work activities A review of completed documentation was also performed to ensure compliance with TS requirements.
b.
Observations and Findinas The licensee performed SSPV replacements for 30 control rod drive HCUs (two SSPVs per HCU) on May 18 - 19, and for 39 HCUs May 29 - 31. The SSPVs were replaced to install an improved elastomer with a significantly longer lifetime. This complex evolution i
was performed with close coordination among operations, reactor engineering and various maintenance work groups.
l The licensee achieved very good coordination of activities by assigning a dedicated multi disciplined team to provide around-the-clock support. Operators manned a work control desk at the work site to handle all tagging, testing and equipment alignment work.
Maintenance groups set up workbenches at the work site to minimize total equipment out-of-service time. Radiation protection personnel supported work activities on a full time basis. These efforts facilitated the efficient replacement, rewiring and testing of six SSPVs simultaneously. The first outage was for peripheral rods, so the work was done without reducing power. Yhis scheduling provided experience in preparation for the more time-sensitive second outage for inner rods, which required reducing power to near 60 percent. Work was completed ahead of schedule in both cases due to the efficient planning and coordination of work.
The inspectors observed that while the work was completed in a timely fashion, the work was also performed in a quality manner. The inspectors observed that some mechanical joints required repeated adjustments to pass the required leak tent due to awkward locations, but the adjustments were made with proper care. Supervisory oversight was evident. Operators and radiation protection personnel provided excellent support of work activities.
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Conclusions Two outages performed to replace control rod SSPVs were planned and executed in a highly coordinated manner. Maintenance team.s from each work group performed a complex sequence of tasks on six control rods simultaneously in a quality manner.
Operations and radiation protection personnel provided close support, ensuring prompt equipment restoration and testing. The outages were scheduled so that experience was gained during the first outage on peripheral rods, so that the subsequent work on inner rods, which were time-sensitive, could be performed more smoothly.
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M8 Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) Licensee Event Reoort (LER) 50-341/98002-00: Inadvertent load shed of Safety Bus 72E during surveillance testing. This resulted in deenergizing one division of the reactor protection system and multiple engineered safety feature actuations. The surveillance procedure had been revised to match equipment labeling, and had received minimal technical reviews. The change made one step unclear, but workers performing the test were satisfied they understood what was required. As a result, workers opened the wrong knife syvitch, and the load shed occurred several steps later. Inspection Report 50-341/98003, discussed the event in detail, and issued Violation 50-341/98003-04 for an inadequate test procedure. Short term corrective actions included field verification of similar bus undervoltage test procedures. This corrective action appeared adequate. This item is closed.
M8.2 (Closed) Violation 50-341/98003-04: Inadequate procedure caused inadvertent load shed of Safety Bus 72E during surveillance testing. Corrective actions included replacing the confusing switch label with a more user-friendly label, and reviewing similar equipment labels and test procedures to ensure they were suitable from a human factor standpoint.
Corrective actions appeared adequate. This item is closed.
M8.3 (Closed) Violation 50-341/97007-06: Failure to conduct the required post maintenance testing (PMT) to ensure adequate battery capacity following cell replacement. The violation was caused by a change in the work scope (from performing a battery charge to the replacement of battery cells) without a proper review of the PMT requirements.
Battery capacity was subsequently evaluated by performing a successful battery capacity test. Training for maintenance instructors was conducted on the event to stress the need to assess the impact of work scope changes on PMTs. The inspectors verified that training was completed. The inspectors reviewed work packages during routine inspections to ensure that appropriate PMT for the work accomplished was performed, and identified no additional deficiencies. This item is closed.
Ill. Enaineerina ES Engineering Staff Training and Qualification E5.1 License Basis Trainino and Safety Evaluation Qualification a.
Inspection Scope (37001)
The inspectors attended portions of a week long training course given by the licensee the week of May 11. The course was an improvement to periodic requalification training given for personnel qualified to perform or review 10 CFR 50.59 safety evaluations, b.
Observations and Findinas The training was intended to improve the quality of 10 CFR 50.59 safety evaluations by providing a broad understanding of the licensing basis and licensing process for the plant.
The development of the Standard Review Plan, USAR, SERs, as well as licensee
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commitments were discussed in some detail.
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The inspectors noted that the training was viewed as valuable by those attending, resulting in requests for the training by many site personnel outside the original target group. The training target group was expanded to included members of the Onsite Review Organization, Nuclear Safety Review Group, and contractors working on the USAR review and validation project. The addition of the background information provided insight into uses of SEs and source documentation beyond the USAR to be checked while performing the evaluations.
The inspectors noted that many of the questions from trainees, most of whom were currently qualified to perform SEs, indicated a lack of site policy for the level of detail for SE content and inconsistent application of the process. This observation was consistent with inspectors' observations of inconsistent quality in SEs reviewed during routine inspections, c.
Conclusions inspectors observed that training for performing SEs was significantly improved by providing a broad understanding of the licensing process and licensing basis for the plant.
Trainee feedback was positive, resulting in many requests for the training from outside the group requiring the training. However, discussions indicated that the site was inconsistent in its implementation and documentation of the 10 CFR 50.59 process.
E8 Miscellaneous Engineering issues (92903)
E8.1 (Closed) Inspection Followuo item 50-341/97013-05: Excessive steam tunnel temperatures during turbine building ventilation system outages. The licensee identified that the UFSAR implied that TBHVAC would be in operation during plant operation, which could imply that system shutdowns for online maintenance were not permitted. Also, the inspectors were concemed that high temperatures resulting from shutting the system down during plant operation, exceeded the design temperatures of some environmental qualification equipment in the turbine building steam tunnel.
As discussed in inspection Report 50-341/97013, the licensee was able to raise the environmental qualification temperature for the affected temperature detectors by reducing the component life. The inspectors reviewed the analysis, and confirmed that the components were scheduled for replacement prior to exceeding the new lifetimes.
Additionally, the licensee concluded that the USAR discussion was not intended to limit the system such that it could not be periodically shutdown for maintenance.
I During the TBHVAC system outage on May 13 - 14, the licensee conducted steam tunnel temperature monitoring houriy to ensure that the bulk turbine building steam tunnel temperatures remained within the analysis temperature band. This was performed using a formal Sequence of Events Test 98-02. Based on it a completion of appropriate analyses and successful completion of a TBHVAC system outage, this item is closed.
E8.2 (Closed) Inspection Followuo item 50-341/95012-07: Combustion Turbine (-
Generator 11-1 did not meet committed reliability of 95 percent. The licensee performed a 7-month refurbishment and equipment upgrade in 1996. However, this did not improve reliability of this generator, which also serves as the station blackout generator, so a second refurbishment was performed in 1997 with a focus on identifying potential age
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related failures. At the completion of the second refurbishment in November 1997, 50 consecutive start-load cycles were performed without a failure. The system continued to perform well, operating without a failure during the subsequent 7 months. The system was scheduled to continue monitoring as a Maintenance Rule (a)(1) system until November 1998 to ensure consistent performance. This item is closed.
E8.3 (Closed) LER 50-341/96022-00: Technical Specification required shutdown due to inoperable safety relief valve (SRV) position indication. Operators noted intermittent open indication when testing SRV "A" during a plant startup. The open position indication was provided by a pressure switch connected to the SRV tailpipe. The licensee determined through testing and computer modeling that under some conditions, sonic flow could exist in the portion of the SRV "A" tailpipe where the pressure tap was located. This resulted in a sensed pressure slightly less than that required to cause a steady open indication. The plant was modified to move the pressure tap out of the area susceptible to sonic flow, which corrected the indication problem. The other SRV tailpipes were determined to be unaffected by both the analysis and a historical record review. The licensee complied with TS requirements during this event and subsequent testing. This item is closed.
E8.4 (Closed) LER 50-341/96020-00 and -01: Loss of shutdown cooling due to invalid ESF actuation. With the plant in cold shutdown, shutdown cooling was lost for 24 minutes when the shutdown cooling suction valve received an isolation signal. The brief loss of cooling resulted in a minor (3*F) temperature increase in the reactor due to decay heat.
Troubleshooting was unable to duplicate the condition, but analysis indicated the problem could have been caused by one of four relays. All four relays were then replaced. The licensee noted that high resistance connections resulting from contact oxidation of similar normally open contacts have been identified to produce similar indications which were difficult to reproduce. The problem did not recur. This item is closed.
E8.5 (Closed) Inspection Followup item 50-341/96201-05: High pressure coolant injection (HPCI) suction strainer calculations did not account for strainer differential pressure. The licensee performed calculations which concluded that the HPCI system had a substantial margin in net positive suction head available. The inspectors reviewed Design Calculation 501, *HPCI System Hydraulic Analysis," and verified that it was updated to account for strainer head loss, with adequate margin available. This item is closed.
IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 Imoroper Shipment of Radioactive MaterialIdentified Durino Spent Fuel Pool (SFfPJ Cleanout Project a.
Inspection Scope (71750. 86700)
The inspectors observed portions of the SFP cleanout project, which was conducted from February until June. The licensee characterized and packaged five liners full of control rod blades, in-core detectors, filters, and other highly radioactive material for shipment and disposal. The licensee's response to several routine problems and an event, were
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evaluated and corrective actions were discussed. Administrative controls for the project were evaluated for adequacy.
b.
Observations and Findinos The inspectors observed SFP cleanout project work during numerous periods since the work began in February. The work was consistently performed in a deliberate manner as planned. Work was stopped whenever problems were identified, and formal resolution was obtained. For example, when a control rod blade was cut to the wrong length, the technique used was thoroughly reviewed and improved upon; work was continued only after workers were trained on the new method and a revision was made to the SE to permit a second cut to the control rod blade.
The work was closely supervised, and control room operators were kept informed of the progress of work. Permission was obtained to begin work on a daily basis, which was logged both in the control room and on the refueling floor. These improvements were made in response to deficiencies identified in Inspection Report 50-341/98004, and appeared to have been adequately addressed in preparing for this evolution.
Radiation worker practices were observed to be excellent during the work. Radiation protection personnel provided close support of all work, and "A Low As Reasonably Achievable," considerations were given high priority in the methods used. Planning was detailed, and led to several innovative techniques for handling and packaging the radioactive material.
On May 10, the licensee received a shielded shipping cask from Bamwell. The cask was to be used to ship liners filled with low level radioactive waste for burial. The cask was filled with water and opened for inspection when the licensee identified paint chips inside.
When the water was drained to remove the paint chips, radiation protection personnel identified an unexpectedly high radiation levelinside the cask. The source was traced to an object in the bottom. Radiation and contamination levels were normal on the outside of the cask.
Work was stopped, Operations personnel were notified, and the event was evaluated for deportability. Condition Assessment Resolution Document 98-13223 was written to document the event. The cask was posted as a locked high radiation area because the object was 35 R/hr on contact. A plan was created for retrieval and identification of the object, which was determined to be a boron pin from a control rod from another facility, i
i Fermi personnel worked with Bamwell to identify the cause of the event and the source of the material. Bamwell acknowledged responsibility for potentially improperly shipping the
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radioactive material. The issue was being investigated for possible shipping violations by l
the State of South Carolina.
The inspectors considered that Fermi personnel acted appropriately in response to the discovery of the highly radioactive material. Work was carefully performed within the limits of the radiation work permits, and plans were appropriately revised before additional investigations were performed. Station procedures were conservative in specifying cask l
inspection prior to placement in the SFP, and allowed identification of the material, which i
otherwise might have been overlooked. The licensee did an excellent job communicating
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with all parties involved. This was notable because the delay caused by resolving this l
issue prevented the licensee from shipping any of the liners that were prepared for
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shipment until after the upcoming refueling outage, c.
Conclusions The SFP cleanout project was planned in detail, giving high priority to "As Low As Reasonably Achievable" considerations in the methods used. This led to several i
innovative techniques for handling and packaging the radioactive material. Supervision, l
contractor control, administrative controls, log keeping, and communications with
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operations personnel were significantly improved. Problems were promptly communicated and resolved in a formal manner.
Due to a conservative receipt inspection methodology, the licensee was able to identify that a shipping cask received from the disposal site contained a highly radioactive pin from a control rod blade which had been inadvertently overlooked during a previous shipment. The licensee did a good job in identifying the material and communicating with federal and state agencies to resolve the issue.
P1 EP Activities P1.1 EP Drill Performance a.
Inspection Scope (82301)
Inspectors observed Emergency Preparedness drills conducted on March 4 and May 19, as well as the FERMEX 98 exercise. Observations from FERMEX were documented in Inspection Report 50-341/98010. The inspectors observed selected activities in the simulator (control room), Technical Support Center, Operations Support Center, and Emergency Operations Facility, as well as in the plant.
b.
Findinos and Observations:
The inspectors found site emergency responses to be well coordinated. Players were knowledgeable of their responsibilities and generally good communications were observed. Operators effectively followed emergency operating procedures in responding to simulated accidents. Scenarios were challenging and exercised all aspects of onsite emergency response, as well as limited offsite responses.
The inspectors observed that at times in the Technical Assistance Center, engineering support personnel accepted reports of plant information which was not understood, but the engineers did not question the reasons behind the reports. This resulted in spending time trying to create the reasoning rather than just asking the source of the report.
The Operations Support Center was observed to be well staffed and organized.
However, the noise level was observed to be somewhat high at times, and communications were hampered as a result. Field repair teams were briefed in detail on the radiological conditions expected and the job to be performed.
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During the May 19 drill, simulated equipment failures necessitated sampling the primary l
containment atmosphere. This was initially miscommunicated, but corrected after some l
delay. Further delays were encountered! while taking unnecessary radiological i
precautions, attempting to unlock the defective post accident sampling room door, and l
obtaining unnecessary security support required by a restrictive procedure. The system did not operate as expected during the sample, but sample results appeared to be representative of actual conditions inside the containment. The licensee was
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After completing the containment atmosphere sample analysis, the simulated results for l
containment atmosphere were 46 percent hydrogen and 2 percent uxygen. Site perscnnel calculated that more than a day would be required to reduce the hydrogen to acceptable levels with the hydrogen recombiners. The inspectors pointed out that there was insufficient oxygen to recombine most of the hydrogen. The Emergency Preparedness Director subsequently stated that the results were not realistic, but were selected to obtain the desired emergency operating procedure flow chart actions.
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Conclusions:
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The emergency response organization received good training value from periodic site drills. Scenarios challenged all aspects of emergency response, although tha inspectors identified one case where unrealistic simulation was provided for hydrogen generation inside containment as a result of simulated fuel damage. Engineering support personnel
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i did not always question the reasons behind reports, and as a result spent time trying to understand unexpected plant conditions. Continued performance problems were l
observed with the post-accident sampling system.
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V. Manaaement Meetinas X.
Exit Meeting Summary l
The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on June 18,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any rnaterials examined
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during the inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED Licensee S. Booker, Maintenance Superintendent D. Cobb, Operations Superintendent R. Cook, Compliance Supervisor, Nuclear Licensing R. DeLong, Superintendent, System Engineering R. Eberhardt, Superintendent, Outage Management P. Fessler, Plant Manager E. Heitzenrater, NSS, Operations K. Hlavaty, Assistant Superintendent, Operations T. Hsieh, Nuclear Fuels Supervisor K. Morris, Emergency Preparedness Director W. O'Connor, Manager of Nuclear Assessment N. Peterson, Acting Director, Nuclear Licensing
- J. Plona, Technical Director T. Schehr, Operating Engineer S. Stasek, Supervisor, independent Safety Engineering Group J. Thorson, Nuclear Engineering Supervisor W. Tucker, Supervisor Nuclear Fuels and Reactor Engineering Group l
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INSPECTION PROCEDURES USED IP 37001:
10 CFR 50.59 Safety Evaluation Program IP 37551:
Onsite Engineering IP 62707:
Maintenance Observation IP 71707; Plant Operations IP 71750:
Plant Support Activities IP 82301:
Evaluation of Exercises for Power Reactors IP 86700:
Spent Fuel Pool Activities IP 92903:
Followup - Engineering IP 92902:
Followup - Maintenance IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED AND CLOSED Opened and Closed 50-341/98008-01 VIO Failure to Conduct 10 CFR 50.59 Evaluation Prior to the Defeat of Control Room Annunciators Closed 50-341/95012-07 IFl Combustion Turbine Generator 11-1 Did Not Meet Committed Reliability of 95 Percent 50-341/96020-00 LER Loss of Shutdown Cooling Due to Invalid ESF Actuation 50-341/96020-01 LER Loss of Shutdown Cooling Due to Invalid ESF Actuation 50-341/96022-00 LER Technical Specification required shutdown due to inoperable SRV Position Indication 50-341/96201-05 IFl High Pressure Coolant injection Suction Strainer Calculations Did Not Account for Strainer Differential Pressure 50-341/97007-06 VIO Failure to Conduct Required PMT to Ensure Adequate Battery Capacity following Cell Replacement 50-341/97013-05:
IFl Excessive Steam Tunnel Temperatures During Turbine Ventilation System Outages 50-341/98002-00 LER Inadvertent Load Shed of Safety Bus 72E During Surveillance Testing 50-341/98003-01 DEV Licensee Commitment to Regulatory Guide 1.78 Not Met 50-341/98003-04 VIO Inadequate Procedure Caused inadvertent Load Shed of Safety Bus 72E During Surveillance Testing i
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LIST OF ACRONYMS USED l'
CFR Code of Federal Regulation i
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DER Deviation Event Report EDG Emergency Diesel Generator ESF Engineered Safety Feature
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HCU Hydraulic Control Unit
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HPCI High Pressure Coolant injection l
LER Licensee Event Report
LPCI Low Pressure Coolant Injection System l
PMT Post Maintenance Testing L
RHR-Residual Heat Removal SE Safety Evaluation l
SER.
Safety Evaluation Report SFP Spent Fuel Pool SOP System Operating Procedure SR Surveillance Requirement SRV Safety Relief Valve l
SSPV Scram Solenoid Pilot Valve l
TBHVAC Turbine Building Heating Ventilation Air Conditioning Center TS Technical Specification UFSAR Updated Final Safety Analysis Report VIO Violation i-
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