IR 05000254/1997011
| ML20216D065 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 08/26/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20216D048 | List: |
| References | |
| 50-254-97-11, 50-265-97-11, NUDOCS 9709090206 | |
| Download: ML20216D065 (30) | |
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h U. S. NUCLEAR REGULATORY COMMISSION REGION lli Docket Nos:
50 254, 50-265 License Nos:
50 254/97011(DRP), 50 265/97011(DRP)
j Licensee:
Commonwealth Edison Company (Comed)
Facility:
Quad Cities Nuclear Power Station, Units 1 and 2 Location:
22710 206th Avenue North Cordova, IL 61242 Dates:
June 17 - July 28,1997 Inspectors:
L. Collins, Resident inspector K. Walton, Resident inspector R. Ganser, Illinois Department of Nuclear Safety Approved by:
Wayne Kropp, Chief -
Reactor Projects Branch 1 9709090206 970826 DR ADOCK 05000254 PDR
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EXECUTIVE SUMMARY Ouad Cities Nuclear Power Station, Units 1 & 2 NRC Inspection Report 50-254/9701 1 (DR P), 50-265 /9701 1 (DR P)
This inspection included aspects of licensee operations, surveillance, maintenance, engineering, and plant support. The report covers a 6 week period of resident inspection.
Ooerations Although equipment problems occurred during the Unit 2 startup from the 02R14 refueling outage, operator performance was generally good. One poor operating practice was revealed pertaining to operators using an alarm to prompt a change in the electro-hydraulic control (EHC) system pressure setpoint. This operating practice was not observed during previous startups and appeared to be isolated to one operating crew (Section 01.1).
While the open areas in the plant were kept clean, there was a buildup of debris in less accessible areas. This posed the potential for foreign material to migrate to drains, sumps and possibly to other more critical plant equipment. In some cases, maintenance areas were left without adequate restoration of cleanliness. This indicated a tolerance for uncontrolled loose materialin the plant that could lead to foreign materialintrusion problems (Section 01.2).
Plant equipment was not functioning as intended which resulted in additional compensatory measures or actions by operators. These operator workarounds were not identified and included on the licensee's operator workaround list. The frequently alarming annunciator for the core spray discharge header pressure was of particular concem because operators tolerated the increased alarm frequency, but did not have any explanation for the abnormal condition (Section 01.3).
Generally, operators initiated Problem improvement Forms (PlFs) as required by plant procedures. However, the inspectors identified four instances this report period that met the threshold criteria for generating PlFs, but none were initially written (Sections 01.4, M3.2 and M4.1).
-Two shifts of control room operators failed to detect increased offgas activity resulting from a leak in a Unit 2 fuel element. Once detected, the licensee took appropriate action to identify the location of the leak and suppress reactor power in the area of the affected fuel bundle (Section 01.5).
Poor work planning and coordination of on-line maintenance activities resulted in both the high pressure coolant injection (HPCI) system and the low pressure coolant injection (LPCI)
systems being inoperable on two occasions for less than one hour. The licensee improperly entered shutdown action statements voluntarily which was contrary to guidance provided in the bases of Technical Specification 3.0.A (Section 01.6).
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The inspectors did not find any evidence of operators exceeding GL 82-12 overtime limits.
The inspectors concluded, based on commitments made by department managers in response to Quality and Safety Assessment department audit findings and commitments to upper station management, that the licensee's overtime program was in compliance with GL 8212 (Section 04.2).
Maintenance The inspectors, based on a review of residual heat removal service water (RHRSW)
Technical Specifications (TS) surveillance requirements, identified that four valves were not included in the surveillance procedure. The licensee's followup to the inspectors'
concern was thorough and resulted in the licensee identifying eleven additional valves that required position verification (Section M3.1).
Rescheduling a High Pressure Coolant injection surveillance resulted in unplanned additional exposure to, station personnel and expenditure of additional resources previously planned for other work. A problem with the turning gear did not present a direct safety concern, however, the licensee elected to use procedures to compensate for equipment that did not work reliably as designed; and in this case, the failure also resulted in an additional radiation exposure to operators at higher dose levels (Section M3.2).
The expanded role of OC inspectors providing overview during maintenance activities appeared to be a good initiative. The inspectors concluded the planned scheduling and execution of the safe shutdown pump (GSMP) system outage was good. The outage restored the remote operation capability of the SSMP. However, maintenance activities resulted in some rework. Two rework issues were not initially documented on PlFs (Section M4.1).
Enaineerina Print reading training for engineering staff was effective. The instructor appeared to be highly qualified and demonstrated a high level of skillin teaching the course material.
However, the licensee failed to follow the administrative control process for documenting the instructor's certification (Section E5.1).
Two examples of failing to incorporate design requirements into operational procedures were identified from reviews of licensee event reports (LER). The inspectors found a similar example where the procedure update for post accident operation of the RHRSW system was delayed although system modifications were completed in early 1997 (Sections E8.2 and E8.4).
Plant Sucoort The inspectors identified a posted locked high radiation area (LHRA) that was not locked or attended as required by TS 6.12.B. The licensee did not maintain proper control of the reactor building basement locked high radiation area during Unit 1 high pressure coolant injection (HPCI) system testing on two occasions (Section R1.2).
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Radiation protection and chemistry department personnel effectively coordinated their efforts with the operations department during activities in response to indications of the Unit 2 fuelleak (Section R1.1).
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i Report Details Summarv of Plant Status Unit 1 entered the inspection period at full power, and operated at reduced power routinely
.each night to reverse circulating water flow through the main condenser. Unit 1 otherwise remained at or near full power throughout the inspection period.
Unit 2 main generator was synchronized to the grid on June 22,1997, ending refuel-outage 02R14. A forced outage began later on June 22,1997, when the main turbine was tripped to investigate high bearing vibration. On June 23,1997, the generator was closed to the grid ending the forced outage._ The unit load was slowly increased to full
. power while observing planned hold points during power ascension testing. Once at full power, Unit 2 operated at near full power until July 14,1997, when power was reduced to facilitate testing to locate a suspected leaking fuel assembly. The degraded assembly was identified, and three control rods were inserted to suppress the local flux in the region of the affected fuel cell. Subsequently, Unit 2 load was slowly restored to near full power and remained there at the end of the inspection period.
1. ooerations 01-Conduct of Operations 01.1 Unit 2 Startun Observations a.-
Insoection Scone (71707)-
The inspectors observed Unit 2 startuo Sfter the 02R14 refueling outage. The inspectors monitored control room ahu in plant activities.
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Observations and Findinas -
Throughout the startup operators encountered a number of equipment problems which required repair. Failed equipment included: gland _ seal condenser level g
control valve, 28 booster air ejector pressure control valve, and 28 drywell equipment drain sump pump. Also, several leaks were identified during hydrostatic
- testing which required repair or evaluation prior to continuing the startup. In general, operators performed _well as evidenced by the identification of excessive vibrations on the main turbine bearing #4 and subsequent action taken to trip the
- turbine when the vibration levels exceeded the pre-established trip criteria.
Operators also identified abnormally high drywell temperatures which required a power reduction, drywell de-inerting, and drywell entry to install temporary alterations to pin open three drywell cooler backdraft dampers.
One operator error occurred during the startup which revealed a poor operating practice. During pressurization and heatup of the reactor, a bypass valve unexpectedly opened. Operators took actions to reclose the bypass valve and
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generated problem identification form (PlF) 97-02692 to document the anomaly.
Later, it was determined that the setpoint alarm was being used in lieu of more frequent panel monitoring to alert operators of the need to increase the pressure setpoint of the electro-hydraulic control (EHC) system. The alarm was normally l
received when reactor pressure came within 50 psl of the estabiished setpoint.
When the pressure setpoint alarm failed to activate to alert operators, the bypass valve unexpectedly opened.
Operations management provided immediate feedback to the operating crews via an entry in the shift orders and a training item that the practice of using alarms to
initiate actions instead of monitoring plant parameters was not acceptable. The inspectors noted that during past startups this practice was not observed and concluded that these actions were not standard operating practice b(1 rather isolated to one operating crew, in general, shift and pre-evolution briefings were thorough. On several occasions the inspectors observed good communication and involvement of the nuclear station operators (NSOs) in the decision making process when equipment problems were encountered. The inspectors noted good command and control by the shift engineers as evidenced by enforcing three way communication, self check, and
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peer check, c.
Conclusions Although equipment problems occurred during the Unit 2 startup from the 02R14 refueling outage, operator performance was generally good. One poor operating practice was revealed when operators were using an alarm to prompt operators to chance a pressure setpoint. When the alarm failed to work, the operators did not increase the setpoint, and a turbine bypass valve unexpectedly opened. This operating practice did not appear to be widespread; however, operations management reenforced the expectations that operators monitor plant parameters to prompt action rather than waiting for alarms.
01.2 Gens-tal Area Plant Insoections a.
insoection Scone (71707)
The inspectors performed general walkdown inspections of plant areas. Specific areas inspected included:
main control room
Unit 1 and 2 high pressure coolant injection (HPCI) rooms
Unit 1 and 2 recirculation system motor generator (MG) areas
Unit 1 and 2 reactor and turbine buildings general areas
safe shutdown makeup pump room
emergency diesel generator rooms
auxiliary electrical equipment room
control room heating ventilation and air conditioning (HVAC) room
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safety _related batteries and battery charger rooms
. safety related switchgear
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Observations and Findinas
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' The inspectors observed that fire doors installed in a new fire wall, constructed on
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shift engineer what the requirements were for posting these doors.' The shift engineer was uncertain and requested the station fire marshall to address this item.
The station fire marshall had proper labeling placed on the doors. Subsequently, the inspectors verified that the fire doors were properly labeled.
Equipment deficiencies throughout the plant were properly identified and tagged.
One exception noted by the inspectors was that the handwheel for a pressure-i gauge isolation valve on the 1 A reactor feedwater pump, 13299141 A, had vibrated loose and no action request tags had been placed on the equipment.
Housekeeping was generally acceptable. Some exceptions were accumulated debris under the safety related batteries, on ledges above floor levels, and on top of bus 23 switchgear near the cooling louvers. The cooling louvers on the top of the E
4 KV switchgear could allow intrusion of foreign materialinto internal mechanisms.
There were some metal shavings on the bedplate of the 2B reactor feedwater
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-pump. The inspectors also noted a number of other loose items and debris that had accumulated throughout the plant.
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Conclusions While the open areas in the plant were kept clean, there was a buildup of debris in
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less accessible areas. This posed the potential for foreign matellal to migrate to drains, sumps and possibly to other more critical plant equipment, in some cases, maintenance areas were left without adequate restoration of cleanliness. This indicated a tolerance for uncontrolled loose materialin the plant that could lead to foreign materialintrusion problems.
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01 3 Operator Workarounds
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Insoection Scone (71707)
The inspectors reviewed the current list of operator workarounds. The inspectors reviewed operator logs, rounds sheets, turnover sheets and spoke with control room operators regarding the status, compensatory actions, and problems
associated with the Unit 1 stator water cooling (SWC) system and the Unit 2 core spray (CS) system.
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Observations and Findinos The inspectors identified the following two plant conditions which appeared to be operator workarounds that were not included on the licensee's list.
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Unit 1 Stator Water Conductivity (SWC) Meter The su 1 stator water conductivity meter was broken which required weekly sampling by the Chemistry department to determine conductivity. This condition prevented the periodic swap of the stator water cooling pumps.
The inspectors reviewed how the Unit 1 SWC system was operated without indication (local or remote) of cooler conductivity. The inspectors identified that control room operators were not sensitive to the condition, and the operators were not taking compensatory actions. Monitoring of stator water conductivity was important to detect any leakage of river water into the closed SWC system.
The inspectors confirmed the Unit 1 SWC system conductivity meter was unavailable since April 29. The condition was not documented on either Unit 1 reactor operator turnover sheets or on the Unit 1 senior reactor operator (SRO)
turnover sheets. The inspectors spoke to both the unit SRO and operations management about the situation. The inspectors determined the unit SRO was not
aware of any compensatory actions for this condition. However, chemistry had already increased sampling frequency of the system from monthly to weekly.
The inspectors noted that operators identified this condition during a routine i
rotation of stator water cooling pumps per QCOP 5300-02, " Stator Cooling System Pump Change-Over." The inspectors noted the operators did not complete this
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procedure since the procedure required monitoring of conductivity. Operator logs l
adequately documented the deficient condition and an action request was written l
on both the SWC conductivity trend meter and the conductivity meter. The trend
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meter was given a higher priority for repair. The trend meter was repaired and operators swapped SWC system pumps. The conductivity meter problem was under review by engineering.
Core Sorav Discharoe Header Pressure The inspectors also noted that the Unit 2 annunciator, "CS [ Core Spray 1 Discharge Header Hi/Lo Pressure" was frequently alarming with a high pressure condition. A high pressure condition in the low pressure core spray system piping could be caused by leakage back from the reactor. However, the high pressure condition was also occurring with the reactor shutdown and depressurized. The inspectors questioned the shift engineer about the cause of the high pressure on June 18.
The shift engineer did not know why the condition was occurring and generated PIF 97-2679. The inspectors noted that the annunciator alarmed several times during the Unit 2 startup. One time the condition occurred during HPCI testing. At that time operators were involved in the HPCI test and could not attend to the CS discharge header high pressure alarm. The condition existed until the HPCI run was completed.
The inspectors reviewed the completed PIF and apparent cause evaluation (ACE)
and spoke with the system engineer. The ACE found that the problem first occurred on June 8 following the increase in reactor pressure for the vessel
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pressure test. After the test the frequency of the alarm decreased, but during.
startup the frequency increased to approximately once per hour. A drywell entry on June 22 discovered that the equalizing valves around the injection check valve 21402 98 were not completely closed as required. _ After the valves were closed, the high discharge pressure condition continued to occur but not as frequently. On June 26 the CS injection valve 2-1402-25B was cycled which
significantly reduced the frequency of the high pressure condition. Therefore, the system engineer concluded that the injection valve was not seated properly and allowed a small amount of leakage to pass by pressurizing the discharge header, c.
Conclusions
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In both of these examples, plant equipment was not functioning as intended which resulted in additional compensatory measures or actions by operators. These
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operator workarounds were not identified and included on the licensee's operator
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workaround list. The frequently alarming annunciator for CS discharge header l
pressure was of particular concem because operators tolerated the increased alarm frequency, but did not have any explanation for the abnormal condition.
l 01.4 Failure to Document Instrumentation Problems a.
Insoection Scone (71707)
The inspectors observed followup residual heat removal (RHR) pump in-service I
testing after detection of instrumentation problems.
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Observations and Findinas l
The 2A RHR pump exhibited low flow during quarterly testing on July 10. The flow was measured at approximately 4000 gpm which was in the required ::ction range.
The inspectors questioned the unit supervisor (US) about operability of the pump because normally, with flow in the required action range, the pump is required to be declared inoperable. However, the US told the inspectors that the flow discrepancy.
appeared to be the result of an instrumentation problem. This conclusion was based on a second RHR pump also exhibiting low flow while another flow element measured adequate RHR flow and previous testing had not indicated any pump--
degradation. The US had discussed the issue with the station inservice test (IST)
coordinator and referenced NUREG 1482, " Guidelines for Inservice Testing at Nuclear Power Plants." Appendix A, Question Group 46 stated that if it was
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obvious that the gauge was malfunctioning that the test may be halted and the instruments promptly recalibrated; otherwise, the licensee should attribute the problem to pump perform:nce and declare the pump inoperable.
Instrument maintenance technicians immediately began calibrating the instruments and the pump was run with satisfactory results. The inspectors observed the
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second run and concluded that in this particular instance it was acceptable to
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follow the guidance given by the NUREG to not declare the pump inoperable since a second gauge was available and it was unlikely that a second pump had also degraded to the same point.
However, the inspectors noted that the licensee did not generate a PlF to document this instrument failure. Since an operability deterrnination was made and an
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instrument problem was encountered, the inspectors concluded that this met the I
licensee's criteria for generating a PlF per Nuclear Station Work Procedure (NSWP) A 15, " Comed Nuclear Divisian Integrated Reporting Program." The licensee subsequently generated a PIF in order to trend instrumentation problems, c.
Conclusions Generally, operators initiated PIFs as required by plant procedures. However, the inspectors identified four instances this report period that met the threshold for generating PIFs, but none were initially written. The additional examples are covered in M3.2 and M4.1.
01.5 increased Offaas Activity Due to Leak in Fuel Element a.
Insoection Scone (71707)
The inspectors reviewed operator logs, attended briefings, and witnessed chemistry f
technicians sampling offgas activity associated with a leak in a Unit 2 fuel element, b.
Observations and Findinos On July 13 operators decreased Unit 2 power to perform routine weekly surveillances. After completion of turbine testing, at about 4:20 a.m. central
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standard time (CST), activity in the Unit 2 offgas system started to increase. By the time operators started increasing power, the offgas activity had approximately doubled. Two shifts of operators, monitoring offgas activity twice a shift, did not detect the condition until about 11:50 p.m. CST that evening. Indication included two independent digital indicators and one redundant trend recorder. All three indicators were located adjacent to each other on a back panel. The offgas activity levelincrease was high enough to have been detected, but below the alarm setpoints of the indicators.
Subsequent sampling by chemistry confirmed an increase in recirculation system activity by about 10 times normal activity. The licensee subsequently reduced power and tested the core te determine the approimate location of the leaking fuel bundle. Control rods near the affected bundle were inserted into the core in an attempt to reduce stress and release rates from the affected bundle. The licensee planned to opers% the core at full power until fuel repair activities could be planned.
The licensee identified operators missed an opportunity to have identified the condition earlier. Operstors took logs on both of the digital offgas indicators twice
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per shift. A redundant offgas trend monitor showed an increase in offgas activity, but was not checked by the operators. Operations management believed off gas activity increased by a tactor of 10 and operators did not detect the adverse trend because operators did not log the exponent portion of the digitalindicator readout.
The offgas activity indicator provided a digital readout with an exponent. Operators logged a two digit number, but did not log the exponential portion of the read out.
The inspectors consider this to be a violation of 10 CFR Part 50, Appendix B, Criterion V. " Instructions, Procedures and Drawings." The licensee considered this
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to be a personnel performance issue. For corrective actions the licensee documented this condition on PlF 97-2867, counseled the individuals involved, and discussed this event with operators. The licensee planned to submit an LER for a missed surveillance test. This licensee-identified and corrected violation is being treated as a Non-Cited Violation (50 254:265/97011-01), consistent with Section Vll.B.1 of the NRC Enforcement Policy.
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Conclusions The inspectors concluded two shifts of control room operators did not pay attention to detail when logging offgas indication. Additionally, a redundant indicator was not monitored by operators. Subsequent actions taken by the licensee to identify and mitigate the leaking fuel assembly were good.
01.6 Inadvertent Entrv Into a Technical Soecifications Shutdown Action Statement Due to Poor Work Plannina a.
Insoection Scone (71707)
The inspectors followed up on a control room log entry which recorded entry into a 12-hour shutdown action statoment for a short period to perform surveillance testing on the HPCI system. The inspectors discussed the issue with operators, licenses management, and the Office of Nuclear Reactor Regulation. The inspectors reviewed the TS.
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Observations and Findinas On two occasions the Unit 1 HPCI system was mada inoperable with the low pressure coolant injection (LPCI) subsystem already inoperable. Lack of adequate work planning to assess scheduled corrective maintenance and scheduled surveillances resulted in both emergency core cooling subsystems (ECCS) being inoperable.
The 1D RHR pump was removea from service on June 23 to perform scheduled corrective maintenance. Previous surveillance testing and oil analysis indicated upper motor bearing degradation. The pump was planned to be out of service for about 4 days. Technical Specification Action Statement 3.5.2 provided an allowed outage time of 30 days for one LPCI pump. The licensee processed an on-line maintenance approval form per Quad Cities Administrative Procedure
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I (OCAP) 2200-08, Revision 4, which ' approved the work and assessed the risk
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aspects of removing the ID RHR pump from service. The risk assessment considered other scheduled corrective maintenance for the time the pump would be
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out of service, but did not consider any scheduled routine surveillance activities which could either affect plant risk or Technical Specifications limiting conditions for operation (LCO).
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On June 23, the operating shift rendered HPCI inoperable by closing the turbine steam supply valves in order to support planned surveillance test Quad Cities i
instrument Surveillance (OCIS) 2300-4, Revision 9, "HPCI Analog Trip High Steam
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Flow." Operators concluded that with LPCI already inoperable and HPCI
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subsequently rendered inoperable, that TS action statement 3.5.3 applied and that the plant should be in hot shutdown in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The HPCI system was returned to
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j, service 36 minutes later. The operators generated PlF 97 2727 since the LCO
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j ontry had not been included on the work schedule or discussed at the shift briefing.
The PlF stated that the unit supervisor did not recognize the LCO entry until after
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j-On June 24, HPCI was again rendered inoperable to support the performance of another surveillance, QCIS 2300-9, Revision 0, " HPCl Pump Discharge Flow
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l Switch Functional Test." Operators concluded again that TS 3.5.3 was applicable and a 12-hour shutdown action statement was entered. The HPCI system l
operability was restored within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
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-The inspectors reviewed the events and were concemed that the licensee was -
l voluntarily entering shutdown action statements to support online maintenance.
Technical Specification 3.0.A bases clearly stated that it is not intended that the
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shutdown action requirements be used as an operational convenience which p
permits (routine) voluntary removal of a system (s) or components (s) from service in j-lieu of other alternatives that would not result in redundant systems or components being inoperable.
The inspectors discussed the concems with licensee management. Opere lons
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management acknowledged that the process for approving on-line mainte:mce did not properly review all other activities and planned to change the procedure. Also, l
the licensee acknowledged that entry into shutdown action statements as a result
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of planned maintenance was inappropriate and conflicted with the bases for
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Conclusion i
h Poor work planning and coordination of on-line maintenance activities resulted in
, both HPCI and LPCI being rendered inoperable on two occasions for less than
one hour. The licensee improperly entered shutdown action statements voluntarily
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which was contrary guidance provided in the bases of TS 3.0.A.
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Operator Krwwledge and Performance 04.1 Failure to Reoort Hioh Pressure Coolant inlaction Svatem Inlaction Within 90 Dayt On February 27,1kg7, the Unit 2 high pressure coolant injection (HPCI) pump was inadvertently started end injected less than 300 gallons of water into the core. The licensee determined on Ane 19,1997, that a special report of the incident was not submitted to the NRC with.' 90 days as required by Technical Specification (TS) 3.5.A, Action 7. The licunsee documented this condition on PlF 97+2687.
The inspectors consklar the failure to submit the special report within 90 days as a violation of TS 3.5.A. For corrective actions the licensee submitted a revision to LER 50 265/97001 and planned to submit the 90 day special report. Other corrective actions included implementing a document for TS required special and periodic twporO. Individuals involved in this event, including the plant operations review committee, planned to be briefed about this event. The licensee planned to revise Quad Cities Technical Procedure (OTP) 050010, " Reactor Vessel Designed Cycles * procedure to include TS reporting requirements. This licensee identified and corrected violation is being treated as a Non Cited Violation (50 254;265/9701102) consistent with Section Vll.B.1 of the NRC Enforcement Policy.
" ~ int,pectors concluded plant operations review committee previously had a psnce to identify the required reporting when the original LER was reviewed. In
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addition, the licensee did not adequately track the requirement to report the HPCI
injection event even when engineering staff were aware of the reporting
requirements, 04.2 Review of Ocarations Overtime j
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insoection Scone (71707)
i The inspectors reviewed payroll and accounting records and security records to j
determine the extent of overtime worked by operators for the first 6 months of j _
1997.
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Observations and Finding 1 i
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The inepectors reviewed overtime reports for operators during the first 6 months of 1997. A review of tumstile reports for four operators with the most overtime revealed one individual had approached the overtime limits in Generic Letter (GL) 8212, Nuclear Power Plant Staff Working Hours." However, the inspectors determined, including turnover time, no overtime limits were exceeded by any of the four individuals.
Previously, an audit by the quality and safety assessment (OSA) group in early 1997 documented three corrective action records (CARS) for 18 occurrt,nces in 2 months where lower level managers in operstions, maintenance, and engineering
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departments were not adhering to overtime guidelines. The OSA group identified monitoring and controlling of overtime of lower level managers was weak. Each affected department responded to the CARS with methods to prevent recurrence, in addition, upper site management committed to OSA that nine departments would perform quarterly sample checks on department managers ta ensure department overtime did not exceed limits, c.
Conclusions The inspectors did not find any evidence of operators exceeding GL 8212 overtime limits. The inspectors concluded, based on commitments mede by department managers in response to OSA audit findings and commitments to upper station management, that the licensee's overtime program was in compliance with OL 8212.
Miscellaneous Operations issues 08.1 (Closed) Violation 50 254:265/94016-02: Operators Attempt to Start a RHR Pump Without a Suction Path. Operators failed to follow the RHR operating procedure for starting an RHR pump. Since the interlock prevented the pump from starting, no adverse consequences occurred as a result of this event. Management counseled personnel involved and discussed this event with operations staff. Several months later, management shut down both co'ts due to human performance and other issues. The Inspectors reviewed the licensee's corrective actions. In addition, the licensee better tracks adverse human performance trends in an attempt to identify and correct these weaknesses. The inspectors noted operator performance and adherence to procedural requirements had improved since this event occurred. This item is closed.
08.2 1Clg.End) Licensee Event Reoort (LER) 50 265/97001. Revision 1: Instrument Maintenance Surveillance Caused inadvertent Actuation and injection of Unit 2 HPCI. The licenseo submitted a revision to the LER since a TS requirement to report inadvertent HPCI injections was not complMed within 90 days. The inspectors documented the corrective actions ano NRC enforcement in Section 04.1 above. The inspectors reviewed the corrective actions. This item is closed.
I;. Maintenance M3 Maintenance Procedures and Documentation M3.1 Residual Heat Removal Service Water System Review a.
lagtttetion Scone (71707,61726)
The inspectors reviewed several surveillance procedures, walked down the residual heat removal service water system (RHRSW) pump vaults and observed a quarte ly RHRSW pump operability test. The inspectors reviewed the following procedures:
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OCOS 1000 26, Revision 2 Monthly RHR Valve Position Verification OCOS 1000 04, Revision 12 Quarterly RHR Service Water Pump Operability Test OCOP 1000 30, Revision 5 Post Accident RHR Operation b.
Observations and Findinas System Descriotion and Backaround The RHRSW system provided cooling to the RHR system heat exchangers and to various auxiliary equipment including the RHRSW cubicle room coolers and the safety related control room emergency ventilation (CREV) refrigeration condenser.
The system consisted of two subsystems with two pumps per subsystem.
Historically, the RHRSW pump performance was poor; cavitation and high vibrations would occur when the pumps were operated at the design basis flow rate. From 1986 to 1997, modifications were performed to all eight pumps which improved pump performance and lowered vibrations.
Valve Position Verification Technical Specification Surveillance Requirement 4.8.A required a monthly valve position verification for all valves that were not locked or otherwise secured in position. The inspectors reviewed the monthly valve position verification surveillance and identified several valves in the flow path that were not listed on the surveillance procedure and were not locked or otherwise secured in position.
The heat exchanger flow reversal valves (1(2) 10014A(B),185A(B),186A(B)
187A(B) were not included in the surveillance. All four valves operated from one switch in the control room to reverse flow through the RHR heat exchanger. Valve position indication was provided on the contrci panelin the control room.
The licensee reviewed the surveillance requirement af ter the inspectors identified the discrepancies mentioned above and found that the positions of the flow reversing valves are checked monthly during the performance of an operating procedure to reverse flow through the heat exchangers. Procedure OCOP 1000 27, Revision 5, " Flushing Service Water Side of RHR Heat Exchanger or Discharge Valves * referred operators to OCOP 1000 4, Revision 8, "RHR Service Water System Operation." After performing the flushing, QCOP 1000 4, Step F.3 instructed operators to verify the positions of the heat exchanger flow reversal valvas. Although this operational activity provided assurance that the valve positions were checked,it did not satisfy all administrative requirements for a TS required surveillance.
The licensee then identified another 11 RHRSW valves that were not locked or secured and were not regularly verified to be in the correct positions. Operators generated PlF 97 02951 to document that RHRSW isolation valves to RHR pump oil and seal coolers were not included in the surveillance. The failure to complete the surveillance for all the valves in the flow path was considered to be a Violation (50 254:265r97011-03) of TS 4.8 A. Operators subsequently verified the correct
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position of the valves. The licensee considered this to be a missed TS surveillance and planned to submit an LER Additionally, the licensee began a review of all similar TS surveillance requirements to ensure the valve position verification I
surveillance procedures for other systems were complete and accurate.
l Post Accident Operatina Procedutg Quad Cities Operating Procedure 1000 30 stated in the precautions that RHRSW pumps should not be operated at flows greater than 3500 gpm, and that some RHRSW pumps undergo a small amount of cavitation at flows greater than 3300 gpm. The procedure referenced a study that was performed and concluded that 3500 gpm was necessary for the first 11.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after an accident and that if accident conditions allowed, flow should be reduced below 3300 gpm as soon as possible or another pump started. The inspectors questioned operators and the system engineer about this precaution and found that it dated back to before all the pump modifications were completed when vibration levels were higher and approached unacceptable levels at the design basis flow rate. The system engineer had submitted a change to the procedure af ter the final pump modification was completed on February 17,1997. The inspectors found that the procedure was in final review awaiting Operations department approval prior to implementation.
The delay in removing the precaution af ter completing the pump modifications was similar to the failures to incorporate design information into procedures as doscribed in Sections E8.2 and E8.4. However, the inspectors did not consider this example to be a violation because the updated procedure was in final review and implementation was imminent.
c.
Conclusions The inspectors, based on a review of residual heat removal service water (RHRSW)
technical specification (TS) surveillance requirements, identified that four valves were not included in the surveillance procedure. The licensee's followup to the inspectors' concern was thorough and resulted in the licensee identifying eleven additional valves that required position verification.
M3.2 HPCI Surveillance Observation a.
insoection Scooo (71707,61726)
The inspectors attended the briefing and observed the Unit 1 Quarterly HPCI Pump Operability Test, QCOS 2300 05, in the control room. This test had been performed during the previous week: however, vibration readings needed to satisfy in service test (IST) program requirements were not obtained due to a failure of the vibration test instrument.
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Qbservations and Findinos Th6 pre briefing was thorough. During the pre briefing, a radiation protection technician questioned when the next " hydrogen free" day was scheduled. The main portion of this test had been performed the previous week, during a time when the hydrogen in}ection system was shutdown. Since then, the hydrogen injection system had been restored to operating status. With the hydrogen in}ection system shutdown, dose rates in the steam piping were much lower resulting in less radiation exposure to test personnel. The next scheduled " hydrogen ftee" period was not until September 17,1997. This was after the critical deadline for
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completion of the test, so the dose savings from coordinating these efforts would not be realized for the remaining portion of the test. The inspectors noted that the licensee did not generate a problem identification form (PIF) to identify this retest as a problem condition, even though the retest required considerable resources and resulted in unplanned exposure. The licensee eventually generated a PIF.
When the HPCI turbine was started, the turning gear did not disengage far enough to satisfy the " disengaged" light indications in the control room. Operators had to enter the HPCI toom to disengage the turning gear, resulting in increased radiation exposure. This malfunction had previously occurred on the Unit 1 HPCI but has not been a problem on Unit 2. Operating procedures included direction to operators to monitor tuming gear indication and take corrective action should this failure occur.
The licenses had an action request submitted to correct this condition and previously attempted to fix the problem. However, the licensee did not effectively correct the problem. The HPCI surveillance test was successfully completed, c.
Conclusions Rescheduling the surveillance resulted in unplanned additional exposure to station personnel and expenditure of additional resources previously planned for other work. Since no PlF was initially written to identify re-performance of the surveillance test during a higher dose condition, documentation of the cause and prevention of recurrence could not be programmatically achieved. In this example, the licensee failed to effectively employ the use of the corrective action program.
The problem with the turning gear did not present a direct safety concern, however the licensee elected to use procedures to compensate for equipment that did not work reliably as designed; and in this case, the failure resulted in an additional radiation exposure to operators at higher dose levels.
M4 Maintenance Staff Knowledge and Performance M4.1 Work Reauests and Surveillance Observations a.
insoection Scooe (61726. 62707)
The inspectors reviewed and/or observed the following maintenance activities and assessed the workers performance and compliance with plant requirements:
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l WR 970059868 Work 1D Residual Heat Removal Pump Upper Motor Bearing WR 960068504 Modify, Clean, and inspect Motor Operated Actuator for Valve % 29016.
I WR 960107219 Perform Hot Short Modification for Valve % 29017.
WR 970025496 Replace Safe Shutdown Makeup Pump [SSMP) Inboard and Outboard Bearings.
WR 970077507 Align the SSMP breaker into Bus 31.
WR 970107227 Motor Operated Valve 2 2901 8 Functional Test.
The inspectors reviewed and/or observed the following surveillance activities listed below. The inspectors verified the surveillances were in conformance with the design basis of the facility and the surveillances were in compliance with TSs. The inspectors verified deficient N AM M identified during testing were properly documented.
OCOS 1100-07 Standby Liquid Control Quarterly Flow Test t
OCOS 662010 Unit 1 Station Bleckout Diesel Sesquiannual Endurance and Full Load Reject Test b.
Obsetyations and Findinas The licensee voluntarily removed the safu shutdown rnakeup pump (SSMP) from service in an attempt to improve the system performance and availability.
Previously, the licensee did not complete a hot short modification to three motor-operated valve actuators. As compensatory action the licensee removed the capability of operating the system remotely. During this outage, three valves were rewired to eliminate the possibility of the valves changing position without command during a postulated fire and remote capability was restored. in addition, the licensee identified that the flow control valve (FCV) actuator was not properly sized and needed to be modified. Higher than anticipated pump vibrations were also addressed during the planned maintenance outage.
The inspectors observed various work items associated with the system outage.
The inspectors noted the work was well planned and addressed most of the deficiency tags written on the system. Work procedures were present at the job site and were adhered to by workers. The inspectors noted good support to the workers from supervisors and engineering. Not all work activities were worked around the clock. Unanticipated problems caused the system outage to exceed the planned schedule.
The licensee utilized two engineers to ensure the work progressed smoothly. One engineer was responsible for ensuring technicalissues were properly addressed.
The second engineer was designated the project manager who ensured maintenance activities were in adherence to the planning schedule and ensured issues were properly addressed. Previously, the system engineer was designated both as the outage manager and tasked to address technicalissues which arose during maintenance. Both the inspectors and licensee noted that performing both functions frequently resulted in schedule slippage as the system engineer became
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q involved with technicalissues. The usa of two engineers to oversee work activities and address technicalissues was an improvement from previous scheduled system
outages.
The inspectors noted quality control (OC) inspectors were in the field more frequently than previous system outages. The QC inspectors were not only signing quality hold points in the work packages, but were also performing overviews of work activities. This was a change from typical OC functions.
However, during post-maintenance testing, several deficient conditions were identified. Two of these deficient conditions were not documented on PlFs until prompted by licenseo management and the inspectors. These deficiencies included FCV problems identified during post maintenance testing, and documentation problems associsted with coupling the pump and motor.
Two rework issues were identified. A motor operated valve (MOV) was not wired properly and a FCV required an additional adjustment not identified during initial system outage planning. The MOV (2 29018) was wired in accordance with instructions. However, during post maintenance testing, the MOV did not operate properly. The work instructions were changed to wire the MOV properly.
Additionally, during post maintenance testing, the system FCV behaved erratically.
The FCV gain was adjusted to correct this condition. Work done to the SSMP did not decrease pump vibrations as much as expected. However, pump vibrations were within code allowable limits. By the end of the planned system outage, the SSMP was considered available for use. The system was declared operable after various technical issues were resolved, c.
Conclusions The expanded role of OC inspectors providing overview during maintenance activities appeared to be a good initiative. The inspectors concluded the planned scheduling and execution of the SSMP system outage was good. The outage restored the remote operation capability of the SSMP. However, maintenance activities resulted in some rework. Two rework issues were not initially documented on PlFs.
M8 Miscellaneous Maintenance issues M8.1 (Closed) LER 50-254/91027. Revision 2: Unit Shut Down due to Heating Steam Leak Deluging Bus 14-1. Operators shut down Unit 1 to determine if the safety-related electrical bus was damaged by water. The affected piping was capped.
Additional walkdowns identified susceptible piping above safety-related Bus 231.
In lieu of removing the piping, the licensee performed a stress analysis of the piping above Bus 231. The analysis determined the pipe was adequately supported. The inspectors reviewed the licensee's calculation and toured the affected area. The inspectors consider this item closed.
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l M8.2 (Closed) LER 50 254/95009: Inspectors identified HPCI Solenoid Valve improperly Mounted. The inspectors cited the licensee in Inspection Report 50 254;265/95010 for iniling to meet 10 CFR Part 50, Appendix B, " Design Control" for this issue. The licensee ensured other solenoid operated valves were mounted in accordance with vendor instructions. This event was discussed with various licensee personnel. The inspectors reviewed the licensee's corrective actions. This item is closed.
Ill. Enalneerina E5 Engineering Staff Training and Qualification E5.1 Observation of Trainina on Print Readina a.
Insoection Sggpa The inspectors observed the conduct of a engineering training class on print reading. The inspectors reviewed the licensee's administrative controls for certifying subject matter expert (SME) instructors, b.
Observations and Findinas The instructor was the lead electrical system engineer and taught the class under the training department's subject matter expert (SME) certification program. This program was used by the training department to certify persons who were not part of the training staff as SME instructors for specialized courses.
The instructor's presentation of the material was effective. Use of good classroom techniques, handouts with appropriate example problems, and sequential development of the basic building blocks to print reading skills contributed to the instructor's effectiveness. The SME instructor appeared qualified and demonstrated a high level of skill in teaching the course material.
Following observation of the classroom presentation, the inspectors asked to review the instructor's certification documents. The documents were not readily retrievable. The file containing the instructor evaluation was a satellite file for the operations program lead instructor, who was away from the station when the licensee initially tried to locate the documentation. Some time later this file was accessed and the course instructor evaluation form, which was thought by members of the trainv.g department staff to be the complete documentation was presented to the inspector as the certification documentation for the SME instructor. This instructor evaluation form documented that the SME's initial course presentation was evaluated by the training department as satisfactory.
In reviewing the administrative control document, training instruction OTI-116 Revision 14, the inspectors noted that Section E of this training instruction
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specified that forrn OTI 116 S8 must be completed to certify an SME instructor.
This form was developed as the administrative tool to document, not only the satisfactory instructor evaluation, but also to document the required SME approved
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lesson plan (s), the SME's technical qualifications, and a list of the topics that the
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SME instructor was authorized to teach. The inspectors asked the training department for the completed QTI 116 S8 to verify the SME instructor's certification and was informed that the form S8 had not been completed for this instructor.
The inspectors obtained a copy of the approved lesson plan and found it to be
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satisfactory. The training department subsequently completed form QTI 116 S8, as
required by the training instruction, to document that all of the requirements were
met. These included documenting the SME's technical qualifications and list of authorized topics. The inspectors reviewed this form and verified that all the
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certification requirements for SME instructor's qualifications were satisfied. The inspectors spoke to the acting training manager concerning the issue of
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documentation and administrative controls. The acting training manager generated a PlF (97 2955) to address the weaknesses in the administrative controls related to this issue.
c.
Conclusions
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The licensee failed to follow the administrative control process by not completing form OTI 116 S8 as directed by the training instruction. Consequently, the requirements to document the SME instructor's technical quellfications and list the
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topics authorized to be taught by this SME instructor were not met. When training
department personnel forwarded the instructor evaluation document to the
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Inspectors, they were not cognizant of the requirements for SME certification and
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failed to check the OTl to ensure that all of the requirements were met. This
indicated a lack of attention to administrative detailin assuring that requirements were met as directed by the administrative control process.
E8 Miscellaneous Engineering issues E8.1 (Closed) Violation 50-254:265/95002-02: Design Control Data Base not
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Maintained for Three Pressure Switch Applications. The inspectors previously
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Identified drywell pressure switches were replaced, but the design control data base
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was not updated within the required 30 days. Secondly, the inspectors determined the RHR discharge pressure switches were set outside the band specified by the
i vendor. Thirdly, the inspectors identified the reactor low pressure permissive loop select logic pressure switch setpoints were changed in the facility, but the design data base had not been updated yet.
The inspectors determined the licensee updated the design data base for the first two instances. However, in the third instance, the inspectors identified the design data base was still not updated for 5 of 8 pressure switches. Due to resource restraints and a large number of outstanding design change requests (DCRs), the
licensee assigned priorities to inputting DCRs into the design data base. The
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licensee continued to work off the DCR backlog, of which, the reactor low pressure permissive loop select logic pressure switches were included. Additiona!Iy. tne inspectors were concerned that the design data bas 6 did not clearly identify that some information needed to be updated. The licensee then ensured that backlogged items were identified as having DCRs still pending. The licensee completed their commitments for this violation. This item is closed.
i E8.2 (Onen) LER 50 254/97011: Merlin Gorin 4 Kilovolt (kV) Breakers inoperable due to Cracked Auxiliary Contact Assemblies. The inspectors previously documented the licensee's response and short term corrective actions to this event in Inspection Report 50 254/265 97006. The licansee performed a temporary repair to the 4 kV l
breaker auxiliary switches. The breakers were tested and qualified to 150 cycles i
and 18 breaker discharges. Engineering documented the breaker qualifications in Addendum #1 in the Modification Approval Letters to Design Change Pack. ages (DCP) 0700134, L700141, and 9700144. The licensee logged breaker cycles and discharges in accordance with OCOP 6500-04, * Racking Out a 4160 Volt Horizontal Type Circuit Breaker" and OCOS 6500-08, " Weekly 4 kV Breaker Monitoring." However, the inspectors determined the licensee did not include the DCP qualifications for the breakers in either of the procedures. This was considered an example of a Violation (50 254:265/97011-04a) of 10 CFR Part 50, Appendix B, Criterion Ill, Design Control.
Similarly, the inspectors identified the logs were not reviewed to ensure the number of cycles for which the breakers were qualified, were not exceeded. The licensee documented the deficient log keeping condition on PlF 97 2036. The inspectors reviewed the logs and determined no breakers had exceeded their operating limits.
This LER remains open pending review of the licensee's long term corrective actions.
E8.3 (Closed) LER 50 254/91003, Revision 2.! Specific Points in Atmospheric Containment Atmosphere Dilution (ACAD)/ Containment Atmospheric Monitoring (CAM) Piping Exceeded Allowable Stress. The licensee identified various ACAD piping penetrating Mark I containment were not in compliance with UFSAR allowable stresses. The licensee placed a modification to repair the condition on hold pending installation of a nitrogen containment atmosphere dilution (NCAD)
system. The licensee submitted supplemental information to address long term corrective actions for this issue. Once the NCAD system was installed, the licensee decided to remove from service the ACAD system. The licensoo cut and capped eight (four por unit) ACAD penetrations into both units primary containments. The inspectors witnessed the eight piping penetrations were capped. This item is closed.
E8,4 1 Closed) LER 50 265/90001: Unit 2 HPCI System Procedures Allowed Turbine Operation with Exhaust Vacuum Breakers Isolated. The inspectors identified, and the licensee concluded, that the HPCI system was not operable with exhaust vacuum breakers isolated. The licensee retumed the valves to their normal positions within the time allowed by the TS limiting condition for operation allowed outage time and declared the system operable. Operations and Engineering
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personnel were trained on the significance of thta event. The modification process was reviewed and the licensee determined the>
ss no need to change the process as a result of this event. Similarly,25 4 vdifications were reviewed.
Engineering determined there was no need to cnange any procedures as a result of the modification review. The inspectors recently observed performance of OCOS 230018, *HPCI Steam Exhaust Vacuum Breaker Line Check Valves IST Functional Test." The inspectors noted operators declared the HPCI system
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inoperable for the time the exhaust vacuum breaker valves were isolated as required i
by OCOS 2300 20, *HPCI Turbine Exhaust Vacuum Breaker Outage Report."
i Documentation for Modification MO-41(2) 91-013B indicated that operation of the HPCI system with the vacuum breakers isolated would result in a degraded condition and administratively inoperable HPCI system. This configuration would not prevent HPCI from starting, but could result in damage to HPCI piping from a water hammer on a HPCI restart. Also, the modification letter stated that the HPCI system should be declared administratively inoperable. As followup to the LER, the licensee determined there was both a licensing basis and regulatory requirement for l
HPCI to restart post accident. The inspectors consider the failure to incorporate the l
modification's impact on the HPCI system with the exhaust vacuum breakers shut
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into the applicable HPCl operating procedures is considered as another example of Violation (50 254/265 97011-04b) of 10 CFR Part 50, Appendix B, Criterion Ill,
" Design Control."
EU.5 Closed (Licensee Event Reoort 50 265/970041: Drywell Equipment Dr6in and Drywell Floor Drain Sumps Were not Constructed in Accordance with Design Drawings. The drywell equipment drain sump (DWEDS) had a cover with grating that allowed in leakage to be collected and the drywell floor drain sump (DWFDS)
had a solid cover. This was the reverse condition frota what was expected. The licensee determined that the covers were not reversed since the covers were fabricated to fit only their respective sumps. The as found condition affected the ability to monitor reactor coolant system unidentified and identified leakage. The DWEDS was consSiered to contain the identified leakage and the DWFDS, the unidentified leakage. With the open sump cover, the DWEDS would actually collect some unidentified leakage and so unidentified leakage (limited to less than 5 gpm and less than a 2 gpm increase in any 24-hour period) would have been under estimated. The licensee collected and reviewed ten years' of drywell sump leakage data, assumed that all but recirculation pump sealleakage (known) was really unidentified leakage. This data was tabulated and graphed and showed that the leakage did not exceed the TS limits for unidentified leakage. The inspectors reviewed portions of the data and the graphs produced by the licensee and also concluded that no TS violation occurred. The licensee changed the sump covers for Unit 2 and verified that correct sJmp Covers Were installed for Unit 1 via existing videotape of the drywell. This LER is closed.
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IV. Piant Suooort
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R1 Radiological Protection and Chemistry (RP&C) Controls (71707,71750)
R 1.1 Coordination of Activities in Resoonse to Unit 2 Fuel Leak During the licensee's activities in response to an indication of degraded fuel l
cladding, the inspectors observed that radiation protection and chemistry l
department personnel effectively coordinated their efforts with the operations I
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department. The procedure for flux suppression testing to locate the suspected l
degraded fuel bundle required that control rod movements and sample activities be precisely executed. All testing proceeded without problems due to the diligence with which the two departments worked as a team to accomplish the activity.
R 1.2 Locked Hiah Radiation Area Gate Found Unlocked and Unattended a.
insoection SCADA (71750)
The inspectors toured the facility and checked various eccessible posted locked I
high radiation area (LHRA) doors to ensure actual conditions were in adherence with posted radiological requirements.
b.
Observations and Findinas On July 2 radiological protection technicians (RPT) posted the gate to the Unit 1
- B" RHR room frorn the reactor building ground floor as a LHRA in preparation for operating the HPCI pump. During operation of the HPCI pump with hydrogen water chemistry on, radiation levels on the HPCI exhaust piping to the torus (in the reactor building basement overhead) were expected to increase to greater than 1000 mrem /hr at one foot. This condition met the requirements for posting the Unit 1 reactor building basement as a LHRA. The RPTs also put a seal on the door and placed a red flashing light at the foot of the door to warn people not to enter the area during the operation of the HPCI pump. This was in accordance with guidance in the radiation work permit (RWP 97 3023).
However, the inspectors identified the LHRA gate was neither locked nor attended during the operation of HPCI which was required by TS 6.12.B. and Quad Cities Administrative Procedure OCAP 0620-01, Rev. 7, "High Radiation Area Access."
The inspectors notified other RPTs who attended the gate until HPCI testing ended and the a;ea was deposted. The RPTs identified the seal on the gate was broken.
(Later invcstigation revealed the NRC inspector most probably broke the seal when checking if the gate was locked.)
Radiological supervisors acknowledged the practice of sealing the gate and piacing a red flashing light at the foot of the gate was not in accordance with requirements of locking or attending LHRAs as specified in TS and the licensees' administrative procedure. The licensee documented this condition on PlF 97 2801. The licensees'
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investigation concluded that no unauthorized access into the reactor building basement occurred.
The inspectors reviewed radiological work permit 97 3023 and identified the RPTs followed the written guidance provided for posting the Unit 1 reactor building basement area for the operation of HPCI. The guidance was issued May 9,1997.
Since that date, HPCI was previously operated on May 31 with hydrogen being injected into the feedwater system. The inspectors considered this practice to be a Violation (50 254/265 9701105) of Technical Specification 6.12.8 which required LHRAs be locked or attendod.
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Conclusions The inspectors concluded the licensee had not maintained proper control of the reactor building basement LHRA during the operation of Unit 1 HPCI pump with hydregen water chemistry operating on two occasions. The inspectors noted the HPCI discharge piping to the torus was in the overhcad of the reactor building basement. Based on the location of the piping, the periodic presence of RPTs in the vicinity, radiological postings on the torus, and the belief that there was no inadvertent access to the area during the ope,tation of the Unit 1 HPCI, the inspectois concluded there was no significant potential for anyone to have received a radiation over exposure from this or previous events durinc the operation of the Unit 1 HPCI pump.
V. Mannaement Meetinas i
X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on July 25,1997. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED pcensaa l
B. Pearce Station Manager R. Cook Maintenance Support Supervisor T. Houzenge Shift Operations Supervisor F. McDougall Design Engineering Supervisor C. Peterson Regulatory Affairs Manager
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INSPECTION PROCEDURES USED IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 62703:
Maintenance Observation IP 64704:
Fire Protection Program IP 71707:
Plant Operations
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IP 73051:
Inservice Inspection - Review of Program IP 73753:
Inservice inspection IP 83729:
Occupational Exposure During Extended Outages IP 83750:
Occupational Exposure i
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
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i Facilities IP 92902:
Followup Engineering IP 92903:
Followup Maintenance IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED
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Opene_d 50 254:265/97011-01 NCV increased offgas activity due to leak in fuel element 50-254;265/97011-02 NCV failure to report HPCI injection within 90 days 50 254:265/97011 03 VIO valve position verification 50 254:265/97011-04a,04b VIO design control 50 254:265/97011 05 VIO LHRA gate found unlocked and unattended Closed 50 254:265/94016-02 VIO operators attempt to start a RHR pump without a suction path 50 265/97001, Revision 1 LER instrument maintenance surveillance caused inadvertent actuation and injection of Unit 2 HPCI 50 254/91027, Revision 2 LER unit shut down due to heating steam leak deluging Bus 141 50-254/95009 LER inspectors identified HPCI solenoid valve improperly mounted 50-254:265/95002-02 VIO design control data base not maintained for three pressure switch applications 50-254/91003, Revision 3 LER specific points in ACAD/ CAM piping exceeded allowable stress 50-265/96001 LEr, Unit 2 HPCI system procedures allowed turbine operation with exhaust vacuum breakers isolated
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l Discussed 50 254/97011 LER Merlin-Gerin 4 kV breakers inoperable due to cracked auxillary contact assemblies l
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LIST OF ACRONYMS AND INITIAllSMS USED ACAD Atmospheric Containment Atmosphere Dilution ACE Apparent Cause Evaluation CAM Containment Atmospheric Monitoring CAR Corrective Action Records CFR Code of Federal Regulations Comed Commonwealth Edison Company CREV Control Room Emergency Ventilation CS Core Spray CST Central Standard Time DCP Design Change Packages DCR Design Change Request DWEDS Drywell Equipment Drain Sump DWFDS Drywell Floor Drain Sump ECCS Emergency Core Cooling System EHC Electro Hydraulic Control FCV Flow Control Valve GL Generic Letter HPCI High Pressure Coolant injection System IDNS lilinois Department of Nuclear Safety IFl Inspector Followup item IST Inservice Test Kv kilovolt LCO Limiting Condition for Operation LER Licensee Event Report LHRS Locked High Radiation Area LPCI Low Pressure Coolant injection MOV Motor Operated Valve NCAD Nitrogen Containment Atmosphere Dilution NSO Nuclear Station Operator NSWP Nuclear Station Work Procedure PDR Public Document Room PlF Problem !dentification Form OC Ouality Control OCAP Ouad Cities Administrative Prr.cedure OCIS Quad Cities Instrutnent Surveillance OCOP Ouad Cities Operating Procedure OCOS Quad Cities Operating Surveillance Procedure OSA Quality and Safety Assessment OTP Ouad Cities Technical Procedure RG Regulatory Guide RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RPT Radiological Protection Technician SRO Senior Reactor Operator SSMP Safe Shutdown Makeup Pump SWC Stator Water Cooling
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TS Technical Specification UFSAR-Updated Final Safety Analysis Report US Unit Supervisor VIO Violation WR Work Request
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