IR 05000341/1997013
| ML20212F435 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 10/27/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20212F411 | List: |
| References | |
| 50-341-97-13, NUDOCS 9711040284 | |
| Download: ML20212F435 (24) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGIONlli
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Docket No.:
50 341 License No.:
NPF 43 Report No.:
50 341/97013(DRP)
Licensee:
Detroit Edison Company (DECO)
Facility:
Enrico Ferml. Unit 2 Location:
6400 N, Dixie Hwy.
Newport, f.11 48168 Dates:
August 11 through September 22,1997 x
Inspectors:
G. Harris, Senior Resident inspector C O'Keefe, Resident inspector
Approved by:
Michael J. Jordan, Chief Reactor Projects Branch 5 M 41 K
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EXECUTIVE SUMMARY Enrico Fermi, Unit 2 NRC Inspection Report No. 50-341/97013(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 5-week period of resident inspection.
Operations Operators on rounds were effective in identifying potential equipment problems. (01.1)
e Operations personnel coordinated effectively with other onsite and offsite organizations to
execute a power reduction to correct a switchyard problem. (01.1)
Activities associated with local operation of the reactor recirculation pumps during the
adjustment of the high speed stops were well coordinated and reflecteel an appropriate attention to safety. (01.1)
The effectiveness of syrtem walkdowns by system engineers and operators improved, e
which resulted in improved material condition for some piant equipment. (02.1)
On-the job training for non licensed operators was not conducted in accordance with e
licensee training procedures. A non cited violation was identified. (O5.1)
The licensee self assessment of progress in implementing the Operational Excellence e
Plan concluded that the majority of site improvement initiativos were effective in improving operational performance. The inspectors' independent assessment agreed with the conclusions of the self assessment initiative. The inspectors also concluded that the Nuclear Quality Assurance department was conducting better quality assessments and making more specific recommendations. (07.1)
Maintenance Several personnel errors occurred rV.ng conduct of work activities. Site management e
promptly recognized the adverse trend and implemented corrective actions. (M1.1)
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Personnel errors caused an inadvertent isolation of the torus water management system.
- Inadequate reviews of wiring drawings, inadequate supervisory oversight, ineffective communications, and non compliance with the requirements of the work control process contributed to the event. A non-cited violation was identified. (M1.2)
The licensee identified a potential problem in the 345 k/ switchyard. Coordination among
onsite and offsite organizations was effective and resulted in prompt resolution of the problem. (M2.1)
The licensee self assessment of maintenance programs concluded that additional
improvement was needed in work package documentation and preventive naintenance work scope and frequency. The contribution from the Maintenance Effectiveness Group engineers was considered a strength. However, the inspectors noted that Audit Report
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97 0120 lacked sufficient detall to support some of the assessment conclusions, rooucing the effectiveness of the report. The inspectors' independent assessment agreed with the report conclusions. (M7.1)
Enoineerina The Reactor Core Isolation Cooling system was rendered inoperable for 3 days due to e
incorrectly specified oil levels, and untimely corrective actions from a previous event.
(E2.1)
Station management recognized an adverse trend in solenoid operated valve failures and e
applied resources to conduct a thorough and comprehensive evaluation of the issue.
(E2.2)
The effects of abnormally high temperatures on environmentally qualified and safety.
e related equipment in the areas of the turbine building following a ventilation system outage were evaluated. The licensee determined that resistance temperature detectors used for main steam line isolation had been adversely affected but were operable. (E2.3)
The nuclear fuel vendor informed the licensee that criticality monitoring was required for e
RA 3 containers with unirradiated fuel when removed from the wooden shipping containers. The licensee had not met this requirement at times in the past. (E2.4)
A review of surveillance testing and preventive maintenance for the hydrogen recombiner
system showed that adequate testing and preventive maintenance was being performed.
The basis for not implementing several vendor manual recommended preventive
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maintenance tasks was not documented. (E2.5)
Plant Supop.d The inspectors observed professional and prudent Fire Brigade response to fire alarms e
and a Halon injection in the computer room. The inspectors identified a number of Fire
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Protection Pre Plan and Abnormal Operating Procedure weaknesses. (F1.1)
Fire Protection Audit findings were in agreement with NRC observations. (F7.2)
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Report Details Summary of Plant Statug Unit 2 operated essentially at 96 percent power throughout the inspection period. Power was reduced for a period of two days to correct an overheating problem in a switchyard breaker connection. The licensee continued to monitor a failed fuel assembly in the core. The licensee also continued to correct d.ficiencies with the Combustion Turbine Generator 11 1.
1. Operations
Conduct of Operations 01.1 General Comments (71707)
Using Inspect.on Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. Specific events and noteworthy observations are detailed in the sections baibw.
The intpectors observed operations personnelin support of corrective maintenance to the 345 kV "CM" breaker. Operators conducted a thorough briefing that included reviewing actions for several contingencies. Preparations were observed to be conservative by the inspectors. Self checks and peer checks were observed to be excellent, The evolution was completed without incident.
The inspectors noted that operators on rounds were more effective than previously noted in identifying potential problems, exhibiting a lower threshold and better questioning attitudes. In one instance, a non licensed operator identified that Emergency Diesel Generator (EDG) 11 had a broken compression fitting connection on a fuel oil overflow line from one injector. The EDG was declared inoperable. The fitting was repaired expeditiously. The inspectors determined that the operating shift reacted to the situation in an appropriate manner. Assistance from maintenance, work cor. trol, and system engineering personnel was promptly obtained. The licensee r,ubsequently determined that the broken fitting did not impact EDG operability.
The inspectors observed local control of reactor recirculation motor generator sets while maintenance personnel reset the high speed stops. This evolution required local control of core reactivity. Operators conducted a thorough briefing. Communication equipment appropriate for a high-noise environment was utilized. Each reactivity manipulation was properly communicated to the control room so another licensed operator could closely monitor reactor indications.
Operators also exNbitea a good questioning attitude when they noted that residual heat removal (RHR) system flow rate was slightly lower than normally expected during system operation. The system was declared operable after more accurate instrumentation was installed and adequate flow had been demonstrated.
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. Operational Status of Facilities and Equipment 02.1 Enaineered Safety Feature System Walkdowns The inspectors used inspection Procedure 71707 to walk down accessible portions of the following Engineered Safety Feature systems:
Control conter heating, ventilation and air conditioning system (CCHVAC), both o
divisions e
Reactor core injection cooling (RCIC) system o ~
Division 2 EDG service water system o
Division 1 RHR
Emergency equipment cooling water both divisions e
Standby gas treatment Divls;on 1 and 2130/260 VDC battery chargers and batteries e
e EDG 13 The inspectors identified no substantive concerns during the walkdowns. The licensee continued to make lighting improvements in the reactor building, noticeably improving working conditions for operations and maintenance personnel, The inspectors noted that system engineers and operators continued to identify equipment deficiencies during system walkdowns. The inspectors concluded that the effectiveness of system walkdowns by system engineers and operators improved, which resulted in improved material condition for some plant equipment,
Operator Training and Qualification 05.1 Operator On The-Job Trainina Not in Accordance With Proaram Reautrements a.
Inspection Scope (71707)
The inspectors conducted a review of the licensee's deviation event report (DER) process and specifically DER 96-1741, On November 21,1996, the licensee discovered that nine nuclear power plant operators (NPPO) undergoing training had received on-the job
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'tremnts as outlined in Nuclear
Training Conduct Manual (MNT04), Chapter 4,
-a Evbluation," Revision 3. The inspectors interviewed the operations personne, d and discussed the licensee's training program requirements with training supervision.
b.
Observations and Findinas The licensee was conducting a training audit of all recently completed operator qualification cards when a discrepancy was discovered on November 21,1996. On October 9,1996, nine NPPO trainee qualification cards had been signed off as complete without meeting the requirements of MNT04," Trainee Evaluation." Two OJT evaluators (licensed operators) had performed a number of evaluation sessions for groups of two to three trainees, Section 4.4.2 of MNT04 requires that the ratio of one trainee to one evaluator be maintained unless prior approval has been granted by the nuclear training supervisor, Contrary to this requirement, the OJT evaluators failed to obtain the appropriate approval before deviating from the approved evaluation process The
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trainees were also required to independently locate then discuss as a group a pre-selected component's location and function. The trainees located pre-selected components as a group in lieu of independently. The OJT evaluators recognized that a deviation from the approved process had occurred but justified the change as an efficient means to reduce man rem exposure since the components were located in a high radiation area. Section 4.4.6.1.b of MNT04 requires that if a perforr nce item can not be completed due to extenuating circumstances, then a pcrformance level variance form-must be processed.- Contrary to this requirement, the OJT evaluators failed to submit and obtain approval for a performance level variance before signing off the qualification cards as complete.
Based upon a review of the licensee's investigation report and proposed corrective actions, the Inspectors determined that no attempt was made to falsify records or shortcut the qualification process. The licenses took prompt corrective action to revise the OJT evaluator process and train the required personnel on the revisions. The man rem -
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savings realized by the methods actually used were evaluated by the licensee and the i;censee intends on incorporating these methods into qualification cards in the next revision.
The failure to obicin management approval before deviating from the prescribed OJT evaluation process was a violation of 10 CFR Part 50, Appendix B, Criterion V,
" Instructions, Procedures and Drawings." However, this non repetitive, licensee-identified, and corrected violation is not being cited, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NUREG 1600). (NCV)(50 341/97013 01),
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Conclusions The inspectors concluded that two OJT evaluators failed to follow station training program requirements. The evaluators did not obtain management approval for two deviations from the prescribed training process for nuclear power plant operators. The inspectors concluded that no attempt was made to falsify records or shortcut the qualification process.
Quality Assurance in vperations 07.1 Licensee Self Assessment Activities in (Verctiona 40500_)
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Scope (40500)
The inspectors reviewed " Nuclear Quality Assurance (NQA) Special Surveillance Report 971009 for Assessing Operational Excellence."
b.
Observations and Findinas The ongoin; NOA assessments were considered by licensee management to be one of the primary tools used to assess the effectiveness of Operational Excellence Plan improvement initiatives The NQA report concluded that the majority of site improvement initiatives were effective in improving operational performance. The following specific conclusions were contained in the subject report:
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Maintenance personnel continued to experience work delays associated with e
tagouts by operators.
Operator briefings were improved and detailed, although lacking in discussion of
expected alarms.
The new work control nuclear assistant shift supervisor (NASS) and shift foreman e
positions were effective in relieving some administrative burden from the operating NASS and control room nuclear supervising operator, lack of a questioning attitude and self checking contributed to personnel errors e
during this period, although at times self check and peer checks were observed to
- be a strength, Improvements were noted in shift tumover briefs with havhg eacn watchstander e
providing status updates.
- Control room log entries had improved, in some areas.
The inspectors noted that the report included all supporting observations upon which the conclusions were based. This was somewhat in contrast to the maintenance audit discossed in Section M7.1.
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Conclusions The licensee self assessment of progress in implementing tbs Operational Excellence Plan concluded that the majority of site improvement initiatives were effective in improving operational performance. The inspectors' independent assessment agreed with the conclusions of the self assessment initiative. The inspectors also concluded that the Nuclear Quality Assurance department was conducting better quality assessments and making more specific recommendations.
Miscellaneous Operations issues 08.1 (closed) Unresolved item 50-341/96016 03 and apparent violation identified in Inspection Report No. 50-341/97002: Operations personnel did not recognize unexpected indications with the containment oxygen monitors in April 1996. Additionally, an error was introduced when oxygen monitor calibrat!on was performed with the containment de-inerted. A pre decisional enforcement conference was held with licensee management on August 6,1997. As a result of the conference, the NRC determined that this issue involved a violation. The licensee's engineering conduct manual, Chapter MLS02, requires that a Deviation Event Report (DER) be initiated to ensure that adverse conditions are addressed and properly resolved. However, station personnel did not initiate a DER and consequently the issue regarding erroneously calibrated oxygen monitors was not resolved for several months. An opportunity to correct a condition that was adverse to quality was missed and the failure to follow Chapter MLS02 is a violation of 10 CFR, Part 50, Appendix B, Criterion V. (VIO) (50-341/97013-02)
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II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Inspection Scope (62707. 61726)
The inspectors observed all or portions of the following work activities:
Weekly control rod drive operability test
CO, fire suppression system functional testing zone 9A e
Division i low pressure coolant injecthn and suppression pool cooling / spray e
pump and valve operability test EDG service water, diesel fuel oil transfer, and starting air operability test, EDG 13
"CM" breaker disconnect thermography and repair
Resetting reactor recirculation motor-generator "A" high speed stops e
e Troubleshooting of low division 1 RHR flow indication Reactor protection system average power range monitor channel"A" calibration e
Nuclear steam supply shutoff system - RCIC steam line flow, division 1 functional e
test RCIC system pump and valve operability test e
e EDG 13 start and load test Division 1 and 2 control center chilled water pump and valve operability test e
b.
Observations and Findinas During the inspection period, plant personnel committed several significant errors during the conduct of work activities. These events were recorded in station DERs. The events included conducting work activities on the wrong division of the control center makeup air radiation monitor (DER 971208), manipulating the wrong valve causing an off gas flow alarm in the control room (DER 971226), performing inadequate drawing reviews and working outside the scope of a work package which resulted in the unexpected closure of containment isolation valves (DER 971247), and not landing lifted leads properly causing a ground condition in a portion of the annunciator system (DER 971253).
The inspectors reviewed documentation associated with the events and noted that they were caused by several deficiencies that included poor self checking, inadequate verification techniques, poor supervisory oversight, and inadequate procedure training.
- /he inspectors and licensee immediately recognized that a negative trend was developing in human performance errors affecting work activities. As a result, the licensee promptly conducted a work standdown. The ceasing of allwork activities allowed all site organizations to review the recent events, the root causes for the events, and the proposed corrective actions. The inspectors noted that the licensee prepared and distributed comprehensive packages containing relevant information concerning the events and human performance error prevention techniques. The inspectors attended various sessions and observed good participation by both employees and management.
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Conclusions The inspectors concluded that human performance errors continued to affect the proper conduct of station work activities. Station management promptly recognized the adverse trend in personnel performance and implemented corrective actions. The work standdown involved all organizations et the station and the licensee effectively emphasized human performance error prevention techniques and management expectations.
M1.2 Work Outside the Planned Scope Results in an inadvertent Torus Water Mansaemtal
System Containment isolation Valve Clis'At a.
Inspection Scope (92902)
The inspectors reviewed control room logs and maintenance e" work control
procedures. The inspectors also interviewed eppropriate supervisory and maintenance personnel, b.
Observations and Findinga On August 14,1997, an autornatic isolation of the four primary containment outboard isolation valves for the torus water management system occurred during repairs to a turbine building sump level switch. The isolation occurred as maintenance wnrkers were removing wires during the repair of a cracked terminal board identified while troubleshooting the level switch. The maintenance workers determined that the terminal board had to be replaced so that the lifted leads could be properly re-landed. The technicians identified a cluster of wires on the opposite side of the terminal block.
Drawings contained in the current work package did not show the presence of these wires. The maintenance workers reviewed some additional drawings prior to repairing the termhal board and were convinced that repairs could be conducted without incident.
The maintenance workers also determined that the replacement of the terminal board was within the scope of the current work package and that no revision was necessary.
The maintenance workers did not inform their supervisor of the problem and their intentions. The supervisor was also not present to overview the work. While attempting to replace the terminal board, an isolation of the torus water management system occurred because the wiring of the terminal board was associated with the reactor building sump system.
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The inspectors reviewed work control conduct manual MWCO2, " Work Control,"
Section 4.8, "Wo.k Request Revisions." The inspectors determined that the replaceme nt of the terminal board was a change in the job scope because it did not meet the criteria for a minor change es specified in Step 4.8.2.c. A revision to the work package to include the additional work was required. The failure to revise a work package as required b/
work control manual MWC02 is considered a violation. The inspectors concluded that the licensee's corrective actions were broad and comprehensive. Corrective actions in'.;luded a site wide stand down to review this event and other recent personnel errors. Thi3 non-repetitive, licensee identified and corrected violation is being treated as a non citeJ violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy.
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Conclusions Workers did not initiate a work package revision as required by station procedures. The inspectors also concluded that poor communications, inadequate wiring drawings, and deficiencies in supervisory oversight of work activities contributed to the event. The licensee's corrective actions were acceptable.
M2-Maintenance and Material Condition of Facilities and Equipment M2.1 345 kV Switchyard Hot Soots identified Durina Predictive Maintenance Monitorina a.
Inspection Scope (92903)
The inspectors observed thermographic monitoring of the 345 kV (Division 2) switchyard.
Preventive and predictive maintenance scheduling and results were discussed with the system engineer, an energy marketing and distribution supervisor, and a performance engineer. Sequence of Events Test 97 013 and associated Safety Evaluation 97-0114 were reviewed and discussed with the nuclear shift supervisor and the applicable system engineers. The inspectors observed briefings for operations personnel associated with the temporary removal and restoration of two turbine trip functions and switchyard manipulations, as wt/l as inspection and repair work in the switchyard, b.
Observations and Fjdirigt The licensee begm thermographic monitoring of major switchyard components in July 1997 for predictive maintenance purposes. Based on the results of initial monitoring, the licensee identified that some components had elevated temperatures, so an increased monitoring schcoule was implemented. Monitoring of the main generator "CM" output breaker cable connection revealed en increasing temperature trend, indiertive of a high i
resistance condition.
l On September 4,1997, temperature readings for the connection indicated that the l
recommended operating conditions were being exceeded, necessitating prompt repair, in response, the licensee opened the CM" breaker to remove current flow through the -
problem connection. However, through continued monitoring, the licensee identified that the reroeted power flow path created high temperature conditions at several other locations. As a result, the CM breaker was reclosed to redistribute current. Power was then reduced to 77 percent.
System engineers evaluated the potentialimpact of performing corrective maintenance on the connection. A 1993 event was reviewed in detail because a switchyard manipulation had caused an invalid generator / turbine trip Licensee management conservatively decided to temporarily defeat the affected trip logic while manipulating the maintenance discoronects in the switchyard. Sequence of Events Test 97 013 was written and approved to control the evolution. The licensee initiated Safety
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Evaluation 97 0114 to assess the impact of removing the generator / turbine trips.
The inspectors observed that the briefing held prior to the work was detailed. The briefing included operator actions for several possible contingency scenarios. Coordination among operations, system engineering l and maintenance groups was observed to be
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good Work was stopped several times to disc iss and resolve questions that arose.
Self checking and peer checking by operators wn.s observed to be excellent.
The evolution was completed without incident on fleptember 9,1997. The licensee determined that the affected connection did not make full electrical contact because a lug was not completely flat. The licensee had experienced several acute failures at other licensee owned facilities. However, thermographic monitoring was conducted at only one other plant owned by the licensee. Therefore, the extent of this problem was not known.
The licensee staff's response to these switchyard issues was prompt and effective compared to the *CM" breaker failure event in January 1997. The licensee's staff had become more involved in the scheduling of switchyard maintenance. Also, the staff requested re evaluation of the periodicity and scope of preventive maintenance in the switchyards. Additionalinspections of switchyard equipment by offsite personnel were scheduled for the upcoming midcycle outage based on the results of this event.
c.
Conclusions The licensee identified a potential overheating problem in their 345 kV switchyard, and responded to the situation in a controlled, conservative manner. The inspectors observed that coordination among onsite and offsite groups was timely and the licensee effectively implemented corrective actions. Power was reduced promptly to control conditions in the switchyard. The work was conducted only when all plant safety considerations had been addressed.
M7 Quality Assurance in Maintenance Activities M7.1 Nuclear Quality Assessments in Work Control. Preventive and Corrective Mainienance, and Measurina and Test Eauipment Proarams a.
Inspection Scope (40500)
The inspectors reviewed portions of " Nuclear Quality Assurance (NQA) Special Surveillance 97-1009 for Assessing Operational Excellence," and NQA Audit Report 97 0120, " Preventive and Corrective Maintenance, Measuring and Test Equipment, and Work Control Programs."
b.
Observations and Findinas The licensee concluded that each of the programs reviewed was effective. Tha preventive maintenance program was reviewed using outside contractors. Mh I le goa' d bench marking the program against industry practices. This was done by Wr:ct.ng several systems. The licensee's assessment concluded that the preventive m intsnance program was acceptable. Several recommended improvements were identified. Outside technical specialists from other nuclear plants were also used in assessing other audit areas,
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l Specific findinfjs included:
Maintenance personnel continued to experience work delays related to tagouts.
e Improved supervisory involvement in maintenance activities were observed.
- Weaknesses were identified in system engineers' knowledge of the basis, scope,
and offectiveness associated with preventive maintenance activities.
There was a need to clarify system engineering personnel's responsibilities in the
preventive maintenance program.
Pre job briefings for maintenance workers had improved overall, although
l confusion existed regarding management expectations due to six different sources of requirements for briefing content. The quality of briefings varied considerably. The report recommended developing a single document for briefing expectations, as well as conducting training in this area.
Work documentation and post work reviews were observed 17 be inadequate at
times, Continued problems were noted with planning personnel ordering wrong parts or o
not ordering required parts.
The measuring and test equipment program was adequate although action on
previously identified program improvements was still pending.
Audit Report 97 0120 concluded that additionalimprovement was needed in work package documentation and preventive maintenance work scope and frequency. The contribution from the maintenance effectiveness grcup engineers was considered a strength.
The inspectors concluded that the results of the subject assessments were generally in agreement with the findings by the NRC and other outside organizations that had performed assessments of licensee performance. However, the inspectors noted that Audit Report 97 0120 lacked sufficient detail to support some of the assessment conclusions, reducing the effectiveness of the report. Senior plant management informed the inspectors that they were satisfied with the level of detail and support information provided at the NQA exit meeting. Feedback was sa > provided at the time of the observations. In a discussion with the inspectors, the Director of NQA agreed that this audit report lacked detail and was therefore less useful to those personnel that did not attend the NQA exit meeting.
c.
Conclusions The inspectors cencluded that the results of the NQA assessment were in agreement with recent NRC findings (as documented in Inspection Reports No. 50-341/97003, 97005,97007, and elsewhere in this report). However, the inspectors concluded that Audit Report 97-0120 did not contain adequate supporting information for some of its conclusions.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Inspection Followup Item 50 341/97003-06: Followup on Transmitter Shipping Plugs. During plant walkdowns, the inspectors observed that plastic shipping plugs were installed in some transmitters in the plant. The inspectors were concerned that these plugs should have been removed and replaced with metal plugs, especially for
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environmentally qualified (EQ) applications. The shipping plugs were originally installed during construction to prevent dust, debris and moisture from entering the transmitter.
Deviation Event Report 93 0282 provided corrective actions for this condition that included installing metal plugs in EQ transmitters. Procedure 35. CON.012, " Fabrication and Erection of Conduit and Conduit Supports," was also revised to ensure that, for new transmitters, all shipping plugs were replaced with metal plugs regardless of service environment. However, the ccrrectiva actions did not address existing transmitters that had plastic plugs installed. In addition to the inspectors' observations, a recent licensee foreign matenal exclusion self assessment concluded that additional guidelines were needed concerning electrical openings. As a result, the licensee plans to revise Conduct of Maintenance Manual Procedure MMA10," Foreign Material Exclusion and Plant Housekeeping," to provide better guidance on measures to ensure better sealing of electrical openings, in eddition, the licensee plans to replace the p!astic shipping plugs during scheduled work activities. The inspectors determined that no EQ transmitters remained with plastic shipping plugs installed and that no operability concerns existed.
The inspectors concluded that the licensee's corrective actions were acceptable. This item is closed.
Ill. Enoineerina E2 Engineering Support of Facilities and Equipment E2.1 Feactor Core Isolation Coolina (RCIC) System inoperable for Three Days Due to Delav in Assessina Cause of Previous Oil Leak e
a.
Inspection Scope ( 92902. 61726)
The inspectors reviewed the procedure for and observed performance of Surveillance 24.206.01, "RCIC System Pump and Valve Operability Test." The RCIC system was walked down. Findings were discussed with the system engineer.
b.
Observations and Findinas On September 9,1997, the RCIC system was started as part of a scheduled quarterly surveillance test. Following system atart, the system engineer and an operator noted lowering oillevel in the turbine bearing oil sight glass. Oil was found to be leaking from the top of the governor end turbine bearing casing through several fittings. The system engineer and Nuclear Assistant Shift Supervisor (NASS) discussed the situation and decided to shut down the system when oillevel reached the bottom of the sight glass.
When the licensee stopped the turbine upon completion of the surveillance test, oillevel retumed to one inch below the scribe mark in the sight glass. Approximately three quarts of oil had leaked out before the turbine was tripped.
The system engineer determined that the operator had added oil to the system shortly before the surveillance test in preparation for the subsequent oil sample. Oil was added to raise the indicated level from the scribe mark (half scale) to one inch above the scribe mark. This was within the range prescribed on the operator rounds sheet (1/2 to 3/4 scale).
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i The system engineer had been assigned an action item from DER 97-0448 which had been initiated after an oilleak from the same location during the previous RCIC system surveillance test in June 1997 (refer to inspection Report No. 50 341/97007). The system engineer was tasked with investigating whether high oillevels could potentially cause oil leaks and with assessing this impact of the oilleak. No action had been taken at the time of the current surveillance test because the action did not have to be completed for another month.
The system engineer discussed the problem with engineering representatives from Terry Turbines and General Electric, who stated that high oil level would result in oil aeration in the bearing and improper draining. This would cause the bearing to pressurize and leak from the yper fittings. The condition was believed to be self correcting; eventually enough oil would leak out that the bearing would begin to drain properly.
Based on this understanding, the licensee restored oil to the level of the scribe mark and attempted to rerun the surveillance test. However, the leak recurred. This was discussed between the system engineer and the vendors and it was concluded that a bubble in the drain line was impeding flow. The system was draineo and refilled and the surveillance test was successfully run without incident. The system was declared operable on September 13,1997.
The inspectors discussed their findings with the system engineer. The inspectors questioned whether the system was capable of restarting without bearing damage after having lost oil in this manner, since the system was designed to restart repeatedly during an event. The system engineer confirmed with the vendor that no bearing damage would have occurred if the pump were restarted.
The licensee, with vendor assistance, determined that the correct oil level range was from the existing scribe mark to 3/8 inch below the mark. Thus, the incorrectly specified level on the operator rounds sheets contributed to the oilleak. The operator rounds sheets were revised accordingly, and a work request to properly scribe the sight glass was written.
The inspectors noted that inspection Report 50-341/97005 documented NRC concerns that the licensee did not adequately specify and understand oil levels for major equipment. The licensee's corrective action for that finding was not completed at the time of this event.
c.
Conclusions The inspectors concluded that the RCIC system was rendered inoperable for 3 days to correct an oil level control problem that could have been prevented by more timely corrective action for a similar previous event. While the licensee initiated an investigation and all appropriate assistance was obtained, the event could have been prevented. The inspectors concluded that the scheduling of corrective actions for the earlier DER 97-0448 could have been completed before any subsequent system testing.
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E2.2 Solenoid Operated Valve (SOV) Failures a.
Inspection Scope (92903)
The inspectors reviewed vendor documentation, interviewed system and maintenance engineering personnel, attended progress meetings of the SOV failure team, and reviewed applicable DERs, design basis documentation, and the Final Safety Analysis Report.
b.
Observations and Findinas On August 4,1997, during the performance of Surveillance Procedure 24.406.001,
" Nitrogen inerting System Valve Operability and Timing Test," the Division 2 drywell pneumatics supply, outboard containment solenoid operated isolation valve failed to stroke in the required time. The licensee terminated the surveillance procedure, declared the valve inoperable and entered the appropriate TS action statements.
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l A second failore of an SOV occurred on August 5,1997. Control room operators received alarm 8070, "DIV l/II Pneumatic Supply Pressure High/ Low." Based on initial investigation by operations personnel, the licensee discovered that another isolation valve had closed, isolating Division i drywell pneumatics. Further investigation revealed that the logic for the solenoid operated valve had not been properly reset while restoring the system from a surveillance test.
l As a result of these failures, the licensee initiated a review of past SOV failures. The analysis showed that the SQVs were falling at a higher than expected rate. There are approximately 1500 quality & _ SOVs installed in the plant. After further analysis, the licensee identified that at lent 14 of the 17 solenoid valve failures involved normally l
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energized safety-related valves with the same model number.
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The licensee formed an SOV Failure Team to evaluate the failures and propose l
corrective actinn. The inspectors observed selected meetings and activities of the team.
The licensee determined that the cause of the failures was contamination in the i
pneumatics system. This contamination resulted from the use of Loctite 580 pipe thread sealant. The sealant did not properly cure when used cn stainless steel. The contamination migrated to SOV valves and caused the cores to stick in the open position when deenergized. Similar contamination was discovered in at least five other valves that had failed in the past two years. However, the licensee could not conclude that this was the root cause for all past failures since a failure analysis was not performed on many of the previously failed valves.
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l The inspectors reviewed the licensee's corrective action immediate corrective action included restricting the use of pipe thread sealant in pneumatic systems. The licensee also developed a list, using probabilistic safety assessment and maintenance rule guidance, of "At Risk" solenoid operated valves. As a result, initially, eight valves were identified for replacement during upcoming plant and system outages and through normal
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plant work scheduling. Othr*r planned corrective actions included training of maintenance personnel, a review of the control of consumable materials, evaluation of the preventive and corrective maintenance programs in order to more effectively evaluate component performance, and revising current procedures to include consumable lists.
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The inspectors will review the use of pipe thread sealant compound on pneumatic supply for other plant systems, the adequacy of controls for other consumable material, licenset response to industry recommendations, and adequacy of replacement scope. These issues will be tracked as an Unresolved item pending completion of additionalinspection.
(URI)(50-341/97013 04).
c.
Conclusions The inspectors determined that the licensee's analysis of solenoid valve failures was thorough and comprehensive. The inspectors noted that station management reco0nized and applied resources to resolve the issue in a timely manner. Vendor involvement was evident. The inspectors agreed with the licensee's conclusion that inadequate controls on the use of the pipe thread sealant and other consumable materials, inadequate followup on industry generic recommendations, and the inadequate use of equipment performance data to establish or modify preventive maintenance frequencies, contributed to the observed failures. The inspectors determined that the licensee's immediate corrective action to restriu the use of the sealant was acceptable.
E2.3 Excessive Turbine Buildino Temperature Effects on Safety Related Eauipment a.
Inspection Scope (37551)
The inspectors interviewed engineering personnel and reviewed EQ data, the Updated Final Safety Analysis Report (UFSAR), Technical Specification, training manuals, applicable DERs, and operator rounds sheets, b.
Observations and Findinas The inspectors noted that control room log entries stated that the turbine building heating ventilation air conditioning (TBHVAC) outage was terminated due to high temperatures in the turbine building, particularly in the steam tunnel area. The inspectors questioned control room operators and learned that steam tunnel'emperatures had reached approximately 190 degrees Fahrenheit (*F). The inspectors were concerned that equipment located in the stearn tunnel or other parts of the Turbine Building could be impacted by the high heat 'oads. The inspectors further questioried whether some of the
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equipment *vas environmentally qualified or safety related. The inspectors reviewed control board indications, questioned control room operators, and discovered that the normal operating temperature of the turbine building steam tunnel was 150 to 175 'F.
The inspectors reviewed technbal documentation and noted that the maximum design temperature for the Turbine Building was 125 'F.
Resistance temperature detectors (RTDs) located in the steam tunnel area provide signals for Group 1 main steam isolation valve (MSIV) closure on high temperature caused by a main steam line break. An EQ evaluation showed that the RTDs had an EQ qualified life of 41 years at 140 'F, An analysis of the effects of elevated steam tunnel temperatures showed that RTD EQ life would be shortened to 5.9 years when exposed to temperatures in excess of 180 'F. The effect of excessive temperatures during TBHVAC system outages was determined by the licensee not to be significant. The licensee determined that the resistance tempert.ture detectors were operable.
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e The inspectors reviewed the operability evaluation and concluded that additional analysis was needed to validate the licensee's findings. This additional analysis includes further
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evaluation of the RTD EQ life at elevated temperatures, the licensee operability detennination that the material does not degrade at 180 'F, and the effect of the turbine building ismperatures during normal operations which are in excess of design temperatures. The inspectors will further review the effects of operating with elevated temperatures in the Turbine Building on other safety-related equipment and the licensee's scheduling practices for TBHVAC system outages. This issue will be tracked as an Unresolved item pending determination of operability of the RTDs.
(URI)(50 341/970013 05).
c.
Donclusions
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The inspectors concluded that the licensee's operability determination required further review.
E2.4 Criticality Monitorina of Shiopina Containers a.
Inspection Scope (92902)
The inspectors reviewed licensee Procedure 82.000.01, " Receipt, inspection, Channeling, and Handling of Unirradiated Fuel," Revision 31; Technical Specifications (TS), special nuclear material and operating licenses; vendor information letters; and interviewed nuclear engir,eering specialist and supervisory personnel.
b.
Qbservations and Findinas On August 1,1997, the licensee was informed by the reactor fuel vendor that unirradiated fuel shipped in RA 3 containers must be monitored for criticality once removed from the primary shipping container. Typically, unirradiated fuelis transported in an inner RA-3 container with an outer wooden box. The letter stated that only the combination of both the wooden and the RA 3 shipping container was an approved method to transport unirradiated fuel. Therefore, the transport of unirradiated fuelin only RA 3 containers required criticality monitoring in accordance with 10 CFR Part 70.24. The inspectors reviewed licensee Procedure 82.000.01, " Receipt, inspection, Channeling, and Handling
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of Irradiated Fuel." The procedure instructed personnel to remove the RA 3 container from the wooden box and place it in the honzontal position on another truck, trailer, or transfer cart. This transport process is not monitored for criticality. In addition, to preclude criticality, RA-3 containers are not permitted to be stacked more than four containers in height. The fuel is then transported to the refueling floor where criticality monitors are installed.
The inspectors reviewed the licensee Special Nuclear Material License, SNM 1097, and noted that the licensee had been previously exempted from the requirements of 10 CFR 70.24. However, the exemption was not included in the operating license. The licensee's planned corrective actions included obtaining the appropriate criticality instrumentation, modifying existing fuel handling procedures to correct the discrepancy and submitting a license amendment. The inspectors will further evaluate the licensee's
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e plans to correct this discrepancy. This will be tracked as an unresolved item pending determination if the licensee's practices for transporting fuel without monitoring for v
criticality constitutes a violation of 10 CFR Part 70.24. (URI)(50-341/97013-06),
c.
Conclusions The inspectors concluded that when unirradiated fuel was handled and transported without monitoring for criticality upon removal from the wooden shipping containers, the licensee could potentially have been in non-compliance w'th 10 CFR Part 70.24.
~15 Hydroaen Recombiner Maintenance and Testino Reviewed a.
Inspection Scope (92902. 71707)
j The inspectors conducted a detailed review of surveillance testing and preventive i
maintenance performed on the hydrogen recombiner system. This review included (
vendor recommendations, TS surveillance requirements, and design basis documentation.
b.
Observations and Findinas r
The inspectors determined that the hydrogen recombiners were generally maintained and tested in a manner consistent with the system design and technical requirements, g
However, the inspectors identified that several vendor manual recommended actions had not been implemented. No documentation was available to provide a basis for not performing the act;cns. Also, the vendor manual and design basis document required that the RHR system supply 10 gpm cooling water to the spray cooler at 100 psig, yet the flow rate was not periodically measured to ensure proper flow was available.
The inspectors discussed these issues with the involved system engineers. Through consultations with the vendor, the system engineers were able to determine the basis for
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the vendor's recommendations and explairi how actions being taken satisfiej the intent of the vendor's recommenddions. Although, the RHR cooling water flow rate was not currently being monitored, the flow rate had been measured to be well above the minimum required flow and pressure during construction testing. Historical system operating temperature data was used to show that no declining trend in operating temperatures existed.
c.
Conclusions
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The inspectors concluded that d'e hydrogen recombiners were adequately maintained and tested. The basis for not h9plementiag some vendor manual recommended preventive maintenance tasks was not documented. Trending of system performance appeared adequate to ensure RHR cooling flow was not degrading.
E8 Miscellaneous Engineering issues (92902)
E E8.1 (Closed) Inspection Followun item 50-341/96010-08: Reactor Coolant Isolation Cooling (RCIC) System 10 Year Pump inspection Results. The licens9e's inspection identified that the pump shaft thiottle sleeve split retaining rings had come out-of-position, allowing
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i the sleeve to move a short distance along the shaft and cause mir,% $ lage. in addition, the sleeve had a through wall crack along its fulllength. W 9 nsee determined that the crack was probably caused by thermal fatigue, r sobir>ed with the use of a more brittle material than is currently recommended. The licensse determined that the thermal fatigue was caused by operating the pump at minimum flow for long periods of time and then running the pump up to full flow. The licensee added the RCIC pump to its vibration monitoring program as part of the corrective actions from this inspection.
While no pump degradation was observed prior to the inspection, vibration monitoring would have detected the abnormal conditions inside the pump. The RCIC system operating procedure was changed to limit the time spent running the pump under minimum flow conditions. The rotating element of the pump was also replaced, which included a throttle sleeve made with the improved material.
The inspectors concluded that the licensee's corrective _ actions wero appropfiate for the assumed cause of the as found conditions, although the exact cause and the time of occurrence could not be deiermined. Vibration monitoring, coupled with the existing instrumented monitoring of RCIC system testing, should adequately detect system performance anomalies in the future. Based on this assessment, this item is closed.
IV. Plant Support F1 Control of Fire Protection Activities F1.1 Fire Briaade Response Excellent. But Fire Response Pian Concerns identified a.
Inspection Scope (64704. 93702)
The inspectors observed the licensee's Fire Brigade and operator response to indications of a fire in the computer room, located inside the main control room complex. Actions and indications were later discussed with members of the Fire Brigade, control room staff, and the Fire Protection Supervisor. The inspectors reviewed and walked down the alarm response procedures for plant fire, smoke and chlorine in the control room, and the fire protection pre-plans (FPPPs) for each zone in the control room complex. The UFSAR and training materials for Control Center Heating, Ventilation and Air Conditioning (CCHVAC), fire detection and suppressm systems, and emergancy breathing air were reviewed and compared. A walkdown of the affected area and affected fire equipment was conducted in company with the Fire Protection Supervisor.
b.
F ndinas and Observations On September 17,1997, control room operers received indication of a fire in the computer room adjacent to the controi room. An operator was dispatched and saw no smoke or fire, but Halon discharged before the activation signal cou!d be overridden. The operator evacuated the roon and the fire brigade was mustered in accordance with station fire precedures. A fire brigade team entered the computer room through an outside door and each member wore a self contained breathing apparatus. Two fire detectors located under the false floor had activated the Halon discharge. No evidence of fire or damage was identified. The computer was verified to be working properly. The
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fire detectors were checked for proper calibration and sensitivity, and no problems were identified, The cause of the alarm was not determined at the completion of this inspection.
The inspectors concluded that the fire brigade reacted to the situatien in an appropriate and prudent manner. Direction from the fire brigade leader was observed to be exce!! ant, and communications were clear and formal throughout the event, Control room personnel were kept fully informed by the fire brigedc. The decision to enter the computer room through a normally !ccked external access door was prudent in that any potential smoke would not enter the main part of the control room.
The inspectors identified a number of procedural weaknesses and inconsistencias.
Several statements in the UFSAR and the fire zone 13 FPPP i.uorrectly indicated that CCHVAC automatically shifts into purge mode in response to a fire in the computer room.
The inspectors' review indicated that FPPPs were irconsistent in content and level of detail. Iri addition, each FPPP contained the statement, "Do not enter the area without proper respiratory equipment." This appeared to conflict with the new station practice of not mustering the fire brigade until a fire alarm was investigated to confirm smoke / fire.
The inspectors identified that station procedures provided no guidance or direction for donning breathing masks in the control room, nor were the conditions that make the control room uninhabitable defined. These conditions could necessitate shutdowa of the plant from outside the control room, but were not included in training on remote plant shutdown. Additionally, the inspectors identified that the chlorine alarm response procedures called for donning masks if chlorine was detected in the control room, but no method of chlorine detection was available. The licensee wrote Condition Assessment Resolution Document 97-13077 to document these concerns and track corrective actions.
This will be tracked as an inspection Followup Item pending inspector review of licensee actions regarding these procedural weaknesses (IFI)(50-341/97013-07).
c.
Conclusions The inspectors concluded that Fire Brigade performance in this instance was prudent and appropriate to the situation. Licensee staff followup on the cause of the alanns was still in progress at the conclusion of this inspection, but appeared to be thorough in scope and depth. However, a number of proceduralinconsistencies and weaknesses were identified with fire response procedures and supporting UFSAR sections. The inspectors were concerned with the apparent lack of training and procedural direction / guidance on the use of air masks by control room personnel in situations with the potential to make the control room atmosphere hazardous.
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F7.1 Fire Protection Audit Recommended Additional Assessments a.
Inspection Scope (40500)
The inspectors reviewed the most recent Nuclear Quality Assurance (NOA) Fire Protection Program Audit Report 97-0122. The results were assessed based on NRC observations.
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Observations and Findinrn The licensee conducted a Fire Protection Audit with NQA personnel supplemented by an outside expert, in fulfillment of the triennial audit required by Technical Specification 6.5.2.8. This included plant walkdowns to determine the condition of fire protection systems. The audit concluded that the Fire Protection Program was effective, with the following deficiencies identified:
Paint was identified on a fire damoer which could have impacted proper damper o
operation. The condition was promptly corrected. A number of minor fire door discrepaticles were also identified and corrected.
Auditort identified an inappropriate location for oil sampling equipment.
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Failures in emergency lights in administrative support spaces were identified, Numerous minor fire protection pre-plan deficiencies were identified, including e
incorrect equipment identification numbers, ncmenclature, and locations.
The audit report recommended additional self assessment in the area of 10 CFR Part 50, Appendix R, design and implementation program. The inspectors discussed the audit with the NQA audits supervisor and with the fire protection supervisor. Both supervisors were satisfied with the scope c4 the audit and both were enthusiastic about the recommendation to perform an additional detailed system review.
c.
Conclusions The inspectors concluded that the audit findings were in agreement with less-detailed NRC observations. As discussed in Section F1.1 above, the inspectors identified additional concems with FPPPs. The recommended vertical slice self assessment was considered to be a prudent response to recent industry experience.
V. Manaaement Meetinns X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on September 22,1997. The licensee acknowledged the
. findi1gs presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information war.
Identified.
X3 Management Meeting Summary On September 16-17,1997, G. Grant, Director, Division of Reactor Projects, Region lil, visited the site and met with senior licensee personnel to discuss plant performance and site improvement initiatives in preparation for the upcoming Systematic Assessment of Licensee Performance.
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PARTIAL LIST OF PERSONS CONTACTED Licensee P, Borer, Vice President, Nuclear Generation D. Cobb, Superintendent, Operations
- R. Cook, Supervisor, Compliance R. DeLong, Superintendent, System Engineering B. Eberhardt, Superintendent, Outage Management
- P. Fessler, Plant Manager D. Gipson, Senior Vice President,- Nuclear Generation H. Higgins, Nuclear Shift Supervisor-
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D. Holland, Fire Protection Supervisor K. Howard, Plant Gupport Engineering, Director E. Kokosky, Supenntendent, Radiation ProtecDon and Chemistry J. Korte, Director, Nuclear Security R. Matthews, Superintendent, I&C Maintenance-J. Moyers, Director, Nuclear Quality Assurance N. Peterson, Director, Licensing
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T, Schehr, Operations Engineer J. Sweeney, Audits Supervisor, NQA J. Thorson, Supervisor, Nuclear Engineering NRC
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A. Kugler, Fermi 2 Project Manager, NRR
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t INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 61726:
Surveillance Observations IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 92902:
Followup - Engineering IP 92901i Followup - Operations IP 92903:
Followup - Maintenance IP 64704:
Fire Protection Program IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 93702:
Prompt Onsite Response te Events at Operating Power Reactors ITEMS OPENED AND CLOSED Opened 50-341/97013-01 NCV Failure to Obtain Management Approval Prior to Performing a Deviation from the Prescribed OJT 50-341/97013-02 VIO Failure to Follow Procedure to initiate DER 50 341/97013 03 NCV Failure to Revise a Work Package as Required by Procedures-50-341/97013-04 URI Use of Compound in Pneumatic Systems and Adequacy of Consumable Material Controls 50-341/97013-G%
URI Excessive Steam Tunnel Temperatures Affect on Safety Related Equipment 50-341/97013-06 URI Criticality rAonitoring of Shipping Containers 50-341/97013-07 IFl Lack of Training and Procedural Direction / Guidance in the Use of Air Masks by Control Room Personnel Closed 50-341/96010-08 IFl RCIC System 10 Year Pump inspection Results 50-341/97003-06 IFl Followup on Transmitter Shipping Plugs 50-341/96016-03 URI Oxygen Analyzer Calibration with Containment De-inerted
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LIST OF ACRONYMS USED
'CCHVAC-Control Center Heating, Ventilation, and Air conditioning CFR Code of Federal Regulations
. DECO Detroit Edison Company DER Deviation Event Report EDG; Emergency Diesel Generator EQ Environmentally Qualified FPPP Fire Protection Pre-Plans GPM-Gallons per Minute IFl inspection Followup item MSIV Main Steam isolation Valve NASS Nuclear Assistant Shift Supervisor NCV.
Non-Cited Violation-NPPO Nuclear Pcwer Plant Operators i
NQA Nuclear Quality Assurance NRC Nuclear Regulatory Commission
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OJT On-The Job Training RCIC Reactor Coolant isolation System RHR 1. 3sidual Heat Removal RTD-Resistance Temperatui. uetector SOV Solenoid Operator Valve TBHVAC Turbine Building Heating Ventilation Air Conditioning TS -
--Technical Specifications UFSAR
. Updated Final Safety Anaysis Report URI Unresolved item VIO Violation i
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