IR 05000440/1998013
| ML20237D728 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 08/21/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20237D724 | List: |
| References | |
| 50-440-98-13, NUDOCS 9808270180 | |
| Download: ML20237D728 (17) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGIONlll Docket No:
50-440 License No:
NPF-58 Report No.
50-440/98013(DRP)
Licensee:
Centerior Service Company P.O. Box 97, A200 Perry, OH 44081 Facility:
Peny Nuclear Power Plant I
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Location:
Perry, OH 44081 Dates:
June 5 through July 22,1998 Inspectors:
C. Lipa, Senior Resident inspector D. Calhoun, Acting Senior Resident inspector J. Clark, Resident inspector Approved by:
Thomas J. Kozak, Chief Reactor Projects Branch 4 l
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9008270180 960821
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EXECUTIVE SUMMARY Perry Nuclear Power Plant NRC Inspection Report 50-440/98013(DRP)
This inspection report included resident inspectors' evaluation of aspects of licensee operations, engineering, maintenance, and plant support for a 7-week period.
Operations Operator performanc6 was good in response to the July 1,1998, scram and during the e
subsequent plant startup. The Unit Supervisor demonstrated good command and control of plant evolutions during the scram (Section 01.2 ).
The inspectors identified two instances where valves were not appropriately locked in a e
closed position as required by plant procedures. The inspectors concluded that this was a result of inattention-to-detail by non-licensed operators when they installed the valve locking devices. This was considered to be a minor violation of adherence to procedures (Section O2.1).
Maintenance e
After performing a risk assessment of an online electrical Division I outage, plant management rescheduled some of the planned activities to lower the risk associated with the work. The inspectors concluded that this was indicative of effective management involvement in plant activities and conservative decision-making (Section M1.2).
e The inspectors identified four instances where scaffolds were constructed by maintenance personnel closer to safety-related equipment than was allowed by plant procedures without the proper engineering review. The inspectors concluded that this was a result of inattention-to-detail by maintenance workers and was considered a minor violation of adherence to procedures (Section M1.3).
e Special turbine control valve testing was performed in a controlled and conservative manner. The testing personnel thoroughly evaluated data at each power level prior to increasing power and continuing with the test. Engineering department personnel provided good support throughout the test by completing a thorough safety evaluation l
and providing timely evaluation of the test results (Section M1.4).
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e On June 18,1998, the licensee held a site-wide standdown to emphasize the policies for procedural adherence. The inspectors considered the standdown to be an effective method of reinforcing expectations on procedural adherence (Section M4.1).
Plant Support
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e The inspectors identified that sleeving used to contain leakage from the "B" control rod drive pump was not properly secured and was not terminated within a controlled contamination area. This deficient condition did not result in the spread of contamination and was corrected by the licensee. The area of the plant was readily accessible and the condition should have been identified by plant workers who had performed work or tours
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in the area. The inspectors cor.cluded that this was an additional example of inattention-to-detail by plant workers (Section R1.1).
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Report Details Summarv of Plant Status The plant was being operated at 100 percent power at the start of this inspection period. On June 13,1998, operators reduced reactor power to approximately 80 percent for several hours to support scheduled activities. During the downpower the licensee conducted a control rod sequence exchange, turbine valve testing, main steam isolation valve testing, and control rod
drive (CRD) hydraulic control unit maintenance. On June 20,1998, operators reduced power to i
approximately 90 percent for several hours to perfo:m turbine control valve testing (see l
Section 01.2).
On July 1,1998, an automatic reactor scram occurred from 100 percent power. The licensee
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l determined the cause to be the failure of a Rosemount calibration unit and trip unit instrumentation board. On July 3,1998, operators commenced a reactor startup after completing the appropriate repairs. The generator was synchronized to the grid on July 4,1998, and the plant was retumed to full power on July 5,1998. On July 7,1998, operators reduced power to (
80 percent for a short duration to adjust the control rod pattems. On July 19,1998, operators (
reduced power for a short duration to 60 percent to investigate a potential condenser leak. The plant was operated at approximately 100 percent power for the remainder of this period.
1. Operations
Conduct of Operations l
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01.1 Caneral Comments The inspectors followed the guidance of Inspection Procedure (IP) 71707 and conducted l
frequent reviews of plant operations. This included observing routine control room activities, reviewing system tagouts, attending shift tumovers and crew briefings, and performing panel walkdowns. The inspectors observed the operator's response to the July 1,1998, reactor scram and observed the subsequent restart activities. The conduct of operations was professional. Overall, emergent equipment issues were promptly addressed. The inspectors concluded that the overal! conduct of operations continued to be professional, with appropriate safety focus.
01.2 Automatic Turbine Trio and Reactor Scram Due to Reactor Core Isolation Coolina (RCIC)
System initiation
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Inspection Scope (71707)
The inspectors observed an automatic reactor scram on July 1,1998, and assessed the effectiveness of operators' actions, communications, and use of plant procedures. The inspectors also observed startup activities on July 3 and 4,1998.
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Observations and Findinas On July 1,1998, at 8:05 a.m., with the reactor at 100 percent power, the RCIC system inadvertently initiated. An automatic turbine trip and reactor scram were initiated after the RCIC initiation. The plant responded as designed. The inspectors were in the control room at the time of the event and observed control room personnel's response to the scram. The Unit Supervisor demonstrated good command and control of the event and effectively coordinated activities required to be performed by the integrated operating -
instructions. The inspectors observed appropriate actions by the operators in accordance with plant procedures.
Due to the transient caused by the reactor scram, reactor water level dropped to 129. 8 inches above the top of active fuel (Level 2) and the high pressure core spray system automatically initiated as designed. Water level was promptly restored to the l
normal level (201.1 inches) and was subsequently controlled by the operators with the
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motor driven feedwater pump. The inspectors reviewed tha Post Scram Restart Report, j
which documented the apparent cause of the event and the parameter changes during
' the transient. The inspectors did not have any concems with the report. As a result of the scram, the licensee began a root cause evaluation, and had preliminarily determined that the cause was a RCIC initiation. The licensee will issue their root cause report within 30 days.
. The licensee determined that a RCIC initiation required two independent divisional trip signals. The first divisional signal was caused by a short circuit on a Rosemount calibration unit and trip unit circuit instrumentation board. The short circuit also caused a voltage spike and the inadvertent operation of the optical isolator between the two divisions. The y '.ical isolator operation produced the second RCIC initiation signal which automatically initiated RCIC. The licensee subsequently retumed the instrumentation board to service after repair and testing. The licensee conducted a plant startup on July 3,1998, and the plant was returned to full power on July 5,1998.
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Conclusions Operations department personnel's performance was good in response to the scram and during the subsequent plant startup. The unit supervisor demonstrated good command and control of plant evolutions in response to the scram.
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Operational Status of Facilities and Equipment O2.1 General Plant Tours and System Walkdowns a.
InsDection Scope (71707)
The irispectors followed the guidance of IP 71707 in walking down accessible portions of several systems and areas.
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Observations and Findinas The inspectors walked down accessible portions of several systems and areas, including:
e emergency diesel generators e
safety-related switchgear rooms e
emergency core cooling systems e
electrical distribution systems Equipment operability, material condition, and housekeeping were acceptable in all cases. During a walkdown of emergency core cooling systems on June 19,1998, the inspectors identified two "T" handle valves that were required to be locked c;osed that were closed but not locked. These valves were 1E22F619, high pressure core spray water leg pump test connection valve and 1E21F530, low pressure core spray water leg pump discharge vent valve. Plant Administrative Procedure (PAP) 0205, " Operability of Plant Systems," Revision 8, (June 14,1996), required that the locking devices be applied in a tight " figure-8" pattem to prevent operation. The locking device on each valve was not properly installed per this instruction. The inspectors informed the licensee of the deficient condition. The licensee subsequently locked the valves in the proper manner.
Technical Specification (TS) 5.4.1.a requires, in part, that procedures be implemented covering applicable procedures recommended in Regulatory Guide (RG) 1.33, Revision 2.
Maintenance procedures that may affect safety-related equ[nment are outlined in RG 1.33 recommendations. The licensee's failure to properly lock the valves constitutes a violation of minor significance and is not subject to formal enforcement action (EA).
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Conclusions i
l The inspectors identified two instances where valves were not appropriately locked in a l
closed position as required by plant procedures. The inspectors concluded that this was a result of inattention-to-detail by non-licensed operators when they installed the valve
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locking devices. This was considered to be a minor violation of adherence to procedures l
Operations Procedurew and Documentation 03.1 Operators' Response for Tomado Wamina l
a.
Inspection Scope (71707)
The inspectors reviewed the actions taken by the licensee in response to the issuance of a tomado waming for Lake County, Ohio, by the National Weather Service (NWS) from 3:53 p.m. until 4:55 p.m. on May 31,1998. The inspectors reviewed the licensee's i
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procedures, policies, and notification process for tornado warnings or high wind conditions.
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Observations and Findinas
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In 1997, the licensee submitted a licensing amendment request to adopt a probabilistic j
method for tomado missile protection. As part of the licensing amendment, the i!censee committed to shift the suctions of the RCIC and high pressure core spray pumps from the condensate storage tank (CST) to the suppression pool upon issuance of a tomado
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waming for the vicinity of the Perry Plant. To determine the conditions that would lead operators to take these actions, the inspec'.ms questioned operators on their interpretation of what area the word vicinhy referred to. The various operators'
interpretation ofin the vicinity of the Perry Plant ranged from a tomado waming in Lake County, Ohio to siting a tomado onsite, in response to this information, the licensee issued a Standing Instruction which defined plant vicinity to mean Lake Countyr The area load dispatcher is located in the System Control Center (SCC) in Wadsworth, Ohio. A verbal agreement was established between the SCC and Ferry Nuclear Power
- Plant (PNPP) such that the SCC would notify control room personnel when a tomado waming was issued for Lake County. On May 31,1998, the NWS issued a tomado waming for Lake County; however, the SCC did not notify the control room personnel of the waming. Oncoming operators informed the Shift Supervisor (SS) of severe weather in the area. The SS stationed security officers around the perimeter of the plant and contacted SCC personnel to inquire if a tomado watch or waming had been issued. The SCC personnelinformed the SS that a tomado waming had been issued based on SCC personnel's assessment of the weather conditions using their weather monitoring equipment and a review of their data link with NWS.
Due to the failure of SCC personnel to notify PNPP of the tomado waming, the licensee took the following actions: 1) installed an emergency weather radio in the Primary Access Control Point; 2) trained control room personnel to obtain intemet access to the Cleveland NWS site; and 3) reinforced to SCC personnel that they have agreed to notify PNPP control room personnel of a tomado waming.
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Conclusions The licensee improved the likelihood that plant personnel would be notified of a tomado waming in the vicinity of the plant so that appropriate actions could be taken by operators in preparation for severe weather, ll. Maintenance M1 Conduct of Maintenance M1.1 General Commen_t1 a.
Inspection Scope (62707. 61726)
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The inspectors observed or reviewed all or portions of the following work activities:
o Post Test Instruction, PTI E22-P0006, " Division 3 HPCS (high pressure core
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spray] Diesel Generator (DG) Auxiliary System Monitoring," Revision 4 e
. PTI-C11-P004, "CRDM [CRD mechanism) Stall Flow Recording," Revision 0 e
Surveillance Instruction SVI-C71-T0039, " Main Steam isolation Valve Closure L
- Channel Functional," Revision 4
e SVI-N31-T1153, " Main Turbine Control Valve Testing," Revision 0 e
SVI-E22-T1319, " Diesel Generator Start and Load Division 3," Revision 8 I
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e SVI-R45-T1326, " Division 3 Diesel Generator Day Tank Fuel Oil Water Test,"
Revision 3 e
SVI-M51-T2003A, " Combustible Gas Mixing System A Operability Test,"
Revision 0 o
Work Order (WO) 98432, Replace DG expansion joint gaskets e
WO 892960, Calibrate Govemor Time Delay
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e WO 982185, Add Tubing Support Brackets for DG j
e WO 973239, Replace Broken Fasteners on DG Cam Covers e
WO 981543, Replace DG Fuel Oil Filter Element e
SVI-B21-T1176, " Reactor Coolant System Heatup and Cooldown Surveillance, "
Revision 5 The itispectors did not identify any concerns with the performance of these activities.
M1.2 Good Use of Risk Assessment Durina Online Maintenance a.
Inspection Scope (62707)
The inspectors reviewed the licensee's plans to perform extensive maintenance on Division 1 equipment during the week of June 22,1998. As part of the scheduling process, the licensee performed a work impact review and risk assessment..The inspectors reviewed the schedule, TS, and results of the risk assessment.
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Observations and Findinas The licensee's planned maintenance affected six systems and resulted in 12 separate limiting conditions for operation. The licensee's risk assessment showed that the original scope of work resulted in a "high risk" category for core damage frequency due to stacked work activities. After further review and discussion with plant management, work management personnel sequenced some of the activities and removed one item from the schedule. The licensee determined that the revised schedule resulted in a " medium risk" category for the maintenance.
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Conclusions After performing a risk assessment of an online electrical Division I outage, plant management rescheduled some of the planned activities to lower the risk associated with the work. The inspectors concluded that this was indicative of effective management involvement in plant activities and conservative decision-making.
' M1.3 Scaffold Clearance from Safety-Related Eauipment i
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Inspection Scope (62707)
The inspectors conducted inspections of various scaffolds throughout the plant to j
determine if they could potentially affect safety-related equipment.
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Observations and Findinas Throughout the inspection period, the inspectors noted several scaffolds that did not meet the minimum 3-inch clearance requirement from safety-related equipment as specified by the licensee's scaffolding procedure. The following four examples demonstrated the licensee's failure to meet these requirements:
On June 6,1998, the inspectors identified that the scaffold for WO 98-432 on the
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Division i DG was improperly located within 3 inches of several safety-related piping hangers and electrical conduits. The inspectors informed the licensee of this condition. Subsequently, a seismic engineer inspected the area and initiated corrective actions. On June 24,1998, the inspectors identified that the scaffold was still within 3 inches of some safety-related piping hangers and electrical conduit.
On June 7,1998, the inspectors identified that Scaffold #2950, for WO 97-299,
was within 3 inches of electrical conduit and piping for safety-related valve E12F0537A, containment spray "A" second shut oft valve.
On June 19,1998, the inspectors identified that Scaffold #2864, for work on
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valve M40-F0617, was erected within 3 inches of the electrical conduit for safety-related valve 1PS2F200, instrument air containment isolation valve.
On June 19,1998, the inspectors identified that Scaffold #2489, for work on
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Maintenance Item S86-1833, was inadvertently placed within 3 inches of safety-related Cable Tray #1819.
Engineering personnel subsequently directed prompt corrective actions for each scaffold clearance problem.
Technical Specification 5.4.1.a requires, in part, that procedures be implemented covering applicable procedures recommended in RG 1.33, Revision 2. Maintenance procedures that may affect safety-related equipment are outlined in RG 1.33 recommendations. Section 5.5.5 and 5.5.6 of Generic Civil Instruction, GCl-0016,
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" Scaffolding Erection, Modification, or Dismantling Guidelines," Revision 1
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(August 4,1995) requires, in part, that scaffolding must have a minimum clearance of 3 inches from safety-related equipment unless specifically reviewed by a seismic l
engineer. The above listed examples show a failure to follow GCl-0016 during the
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construction of scaffolds. The failure to ensure the proper distance existed between scaffolds and safety-related equipment constitutes a violation of minor significance and is not subject to formal enforcement action.
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Conclusions
- The inspectors identified four instances where scaffolds were constructed by
' maintenance personnel closer to safety-related equipment than was allowed by plant procedures without the proper engineering review. The inspectors concluded that this was a result of inattention-to-detail by maintenance workers and was considered a minor j.
violation of adherence to procedures
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M1.4 Special Turbine Control Valve (TCV) Testina a.
Inspection Scope (71707)
On June 20,1998, the inspectors observed portions of special TCV testing. The licensee reduced reactor power to 90 percent to conduct the testing. The inspectors reviewed Temporary Instruction (TXI)-0271, " Turbine Control Valve Testing Optimization,"
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Revision 0, and the 10 CFR 50.59 Applicability Check, attended pre-evolution briefings, and observed portions of the testing.
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Observations and Findinas in the past the licensee had conducted TCV testing under an administrative limit of less i
than or equal to 90 percent power. The licensee conducted TXI-0271 in order to determine if the periodic TCV testing could be safely performed at a higher power level.
The TCVs were stroked after small incremental changes in reactor power between 90 and 96 percent. The 'hensee analyzed reactor physics data after each TCV stroke to determine that an adequate margin to design parameters was maintained at each higher power level.
The inspectors observed that the testing was well coordinated and performed in a conservative manner. Engineering personnel completed a safety evaluation and determined that performing the test at high power levels was within the design parameters and did not constitute an unreviewed safety question. The licensee determined appropriate testing termination criteria which was emphasized during the pre-evolution briefings. System engineering, reactor engineering, and operations department personnel were involved in the test and communicated frequently and effectively. The involved testing personnel thoroughly evaluated and discussed the test results at each power level prior to the SS's authorization to continue with the test.
I After stroking a TCV at different power levels, the licensee determined that 94 percent power was the new limit for the test. The licensee tested the remaining TCVs at 94 percent power, with acceptable results, to complete the surveillance test.
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Conclusions Special turbine control valve testing was performed in a controlled and conservative manner. The testing personnel thoroughly evaluated data at each power level prior to increasing power and continuing with the test. Engineering department personnel provided good support throughout the test by completing a thorough safety evaluation and providing timely evaluation of the test results.
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M4 - Maintenance Staff Knowledge and Performance M4.1 Site-Wide Standdown to Address Procedural Adherence Concems (62707)
On June 18,1998, the licensee held a site-wide standdown to emphasize the policies for procedural adherence. This action was implemented in response to licensee management and NRC concems in this area. (See inspection Report (IR) 50-440/98010.)
The standdown consisted of individual work group meetings to discuss management
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expectations and the newly developed and implemented PAP 0528, " Procedure Use and Adherence," Revision 0.2 (July 7,1998). The inspectors observed two of the discussion sessions and concluded that the supervisors clearly communicated their expectations.
. The inspectors considered the standdown to be an effective method of reinforcing management's expectations on procedural adherence.
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l M8 Miscellaneous Maintenance issues (92700, 92902)
M8.1 (Closed) Licensee Event Report (LER) 50-440/97004-00: Invalid High Suppression Pool Level Results in High Pressure Core Spray System Actuation. This event was documented in IR 50-440/97007. The inspectors concluded in the inspection report that the licensee's corrective actions and response to the event were acceptable. This item is l
closed.
M8.2 (Closed) Unresolved item (URI) 50-440/98006-02(DRP): Control of Grating During Maintenance on Hydraulic Control Unit Accumulators. On February 22,1998, grating sections and other items were temporarily stored in the containment " pool swell region" without an engineering analysis. _ The licensee subsequently performed an operability evaluation, which determined that there was no impact on the ability to perform a safe shutdown of the plant. Additionally, in response to Potential Issue Form (PlF)98-351, the l
licensee reviewed the adequacy of existing controls to prevent future instances of improperly stored equipment in the pool swell region. The licensee scheduled several
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procedural revisions to clarify when an engineering analysis was required prior to j
l performing work in the containment pool swell region. The inspectors had no further j
j concems. This item is closed.
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lil. Enaineerina E8 Miscellaneous Engineering issues (92700, 92903)
E8.1 (Closed) Inspection Followuo item (IFI) 50-440/%003-10(DRP): Discrepancies involving i
Condensate Storage Tank Level Markings. During a licensee self-assessment in 1995, l
discrepancies were identified in the set point calculations for condensate storage tank level and for the high pressure core spray suction path transfer to the suppression pool.
l This was detailed on Pages 12 and 13 of PNPP Audit Report PA 95-23, " System Based Instrumentation and Controls inspection," dated March 20,1995. PotentialIssue Form 95-387 was initiated to resolve the discrepancies. The inspectors reviewed the closure of PlF 95-387 and no other concems were identified. This item is closed.
E8.2 (Closed) IFl 50-440/96003-18(DRP): Updated Safety Analysis Report (USAR) Description of Emergency Lights. The inspectors identified four lights listed in the USAR that did not appear to illuminate the correct areas as listed in USAR Table 9A.3-2. The inspectors were concemed that one lamp out of two for several sets of lamps was not illuminating the motor control center (MCC) as described in the table. Upon further review, a subsequent walkdown, and discussion with fire protection engineers, the inspectors determined that there were no discrepancies. The USAR table specified "acce e' a MCC" for several lights; therefore, only one lamp aimed at the MCC was necer v and the other lamp illuminated the pathway. This item is closed.
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E8.3 (Closed) Violation (VIO) 50-440/97047 E1: Flow Control Valve Corrective Actions Violation. This concerned a reactor poveer transient on November 9,1996, as a result of restoring power to a reactor recirculation system flow control valve. The inspectors reviewed the licensee's violation response letter, dated December 18,1997, and the results of an investigation of the event (PIF 96-3400). The licensee implemented numerous corrective actions for this event with emphasis on conservative decision making, communications, and teamwork. The inspectors concluded that corrective actions were appropriate. This item is closed.
E8.4 Review of Previous Open items Related to USAR Discrepancies The inspectors reviewed several open items related to USAR discrepancies. For each item (listed below), the inspectors considered the licensee's completed or scheduled corrective actions to be adequate. The inspectors documented their discovery of these discrepancies in Inspection Report 50-440/97008 and the NRC issued a violation (EA 97-430) of 10 CFR 50.71(e) for inaccurate USAR information. The licensee's response to the violation, dated November 24,1997, and August 18,1997, discussed their USAR validation program and stated that the scheduled completion date was October 1998. The following examples of failure to update the USAR did not have a materia mpact on safety or licensed activities. Therefore, these examples were classified as violations of minor significance that are not subject to formal enforcement action.
e (Closed) IFl 50-440/96002-06(DRP): Incorrectly designated emergency light for emergency closed cooling valve. The inspectors had identified that in UCAR Table 9A.3-2, Emergency Light R71-S0205 was listed as illuminating emergency closed cooling valve P42-F0551. Actually, Emergency Light R71-LO206A illuminated this valve. The licensee initiated a USAR change request (96-095)
and prepared a safety evaluation (97-0017) to address this discrepancy. The inspectors reviewed the safety evaluation and USAR change and had no concems. This item is closed, e
(Closed) IFl 50-440/96003-04(DRP): Inaccurate Drawing in USAR for Reactor Water Cleanup Vent Valves. The licensee identified that 5 %" high point vent valves were not shown in USAR Figure 5.4-16. Upon identification, the licensee promptly prepad a drawing change (96-102) to correct the figure and a safety evaluatica (%-0069). This item is closed.
e-(Closed) IFl 50-440/90003-05(DRP): Inaccurate Drawing in USAR for Fuel Pool Domineralizer System. Figure 9.19 in the USAR had several minor discrepancies, which were identified and subsequently corrected by the licensee.
The inspectors reviewed the drawing changes (96-093,96-094) and associated safety evaluation (96-0063). The inspectors determined that there was no affect on the safety-related portion of the system. This item is closed.
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e (Closed) IFl 50-440/96003-11(DRP): Inaccurate drawing in USAR for Hydrogen Supply System. The licensee identified that the %" to %" piping expanders shown on USAR Figure 10.2-4 did not exist. Instead, the %" valves used bushings to connect to %" piping without the need for expanders. The licensee prepared a drawing change (96-096) to correct the figure and safety evaluation (96-0062).
This item is closed.
e (Closed) URI 50-440/96005-07(DRP): Emergency Core Cooling System Room Doors Not Locked as Described in USAR Section 9.3.3.3. The inspectors identified that the emergency core cooling system pump compartment watertight l
doors did not have locks. The doors are held closed by mechanical devices. This t
item was under review as a deficiency in the licensee's USAR Validation Project.
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This item is closed.
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IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 Deficient Radiation Protection F>actices a.
Inspection Scope (71750)
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The inspectors accompanied a non-licensed operator during his rounds to determine that he properly monitored and recorded data for required equipment.
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Observations and Findinos
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On July 12,1998, the inspectors identified that leakage control for the "B" CRD pump had not been properly established to minimize the spread of potential contamination. The licensee subsequently corrected the deficient condition.
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While accompanying a plant operator in the intermediate building, the inspectors l-identified deficient radiation protection (RP) practices in establishing leakage control for the "B" CRD pump. A radiation protection technician (RPT) had connected sleeving to the drain line piping of the "B" CRD pump to route the potentially contaminated CRD pump gland sealleakage to an adjacent contaminated drain. The drain had a contaminated mading outlining the drain. The licensee did not have a procedure which govemed this activity. Therefore, the RPT was to use good RP practices when establishing the leakage control for the minimization of the spread of contamination.
However, the inspectors observed that the RPT had terminated the discharge of the i
sleeving at the outer edge of the contamination mading of the drain and that the sleeving
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had not been secured to the floor with tape. The inspectors informed radiation protection
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department personnel of the condition. An RPT corrected the problem and l
communicated the unacceptable condition to the radiation protection manager. Later, the i
inspectors discussed the issue with the radiation protection manager and stated that the
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condition should have been previously noted by other plant personnel.
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Conclusion
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The inspectors identified that sleeving used to contain leakage from the "B" CRD pump I
was not properly secured and was not terminated within a controlled contamination area.
l This deficient condition did not result in the spread of contamination and was corrected by the licensee. The area of the plant was readily accessible and the condition should have been identified by plant workers who had performed work or tours in the area. The inspectors concluded that this was an additional example of inattention-to-detail by plant workers
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V. Manaaement Meetinas l
X1 Exit Meeting Summary The inspectors presented the inspection results to m7mbers of licensee management at the conclusion of the inspection on July 22,1998. 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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l PARTIAL LIST OF PERSONS CONTACTED Licensee
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L. Myers, Vice President, Nuclear s
H. Bergendahl, Director, Nuclear Services Department N.' Bonner, Director, Nuclear Maintenance Department P. Bordley, Nuclear Unit Supervisor J. Bridgens, System Engineer P. Curran, System Engineer
. J. Grabnar, Projects Engineer l
T. Henderson, Compliance Unit Supervisor
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W. Kanda, General Manager, Nuclear Power Plant Department F. Keamey, Superintendent, Plant Operations G. Kindred, Probabilistic Safety Assessment Engineer S. Moffitt, Manager Plant Engineering A. Pusateri, System Engineer T. Rausch, Operations Manager R. Schrauder, Director, Nuclear Engineering Department J. Sears, Radiation Protection Manager l
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INSPECTION PROCEDURES USED
iP 37551:
Onsite Engineering IP 61726:
Surveillance Observation IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support
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IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92902:
Followup - Maintenance IP 92903:
Followup - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Closed
50-440/93021-01 LER Loss of Emergency Closed Cooling System Safety Function
. 50-440/96302-06 IFl Incorrect USAR - Emergency Light j
50-440/96003-04-IFl inaccurate Drawing in USAR for Reactor Water Cleanup Vent Valves 50-440/96003-05 IFl inaccurate Drawing in USAR for Fuel Pool Domineralizer System j
50-440/96003-10 IFl Discrepancies involving Condensate Storage Tank Level Markings i
50-440/96003-11 IFl inaccurate Drawing in USAR for Hydrogen Supply System 50-440/96003-18 IFl USAR Description of Emergency Lights.
- 50-440/96005-07 URI USAR Discrepancy - Emergency Core Cooling System Doors Not Locked 50-440/97004-00 LER High Pressure Core Spray System Actuation 50-440/97047-E1 VIO Flow Control Valve Corrective Actions Violation 50-440/98006-02 URI Control of Grating During hydraulic control unit Maintenance
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l LIST OF ACRONYMS USED l
CFR Code of Federal Regulations CRD Control Rod Drive CST Condensate Storage Tank DG-Diesel Generator DRP Division.of Reactor Projects EA Enforcement Action IFl Inspection Followup item IP inspection Procedure 1IR inspection Report LER Ucensee Event Report MCC Motor Control Center NRC Nuclear Regulatory Commission NWS'
National Weather Service PAP Plant Administrative Procedure PDR Public Document Room PIF Potentialissue Form PNPP Perry Nuclear Power Plant PTl Post Test Instruction RCIC
' Reactor Core Isolation Cooling RG Regulatory Guide RP Radiation Protection RPT Radiation Protection Technician SCC System Control Center SS Shift Supervisor SV1 Surveillance Instruction TCV Turbine Control Valve TS Technical Specification TXI Temporary Instruction USAR'
Updated Safety Analysis Report URI Unresolved item
. VIO Violation
.WO Work Order L
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