IR 05000445/1992059
| ML20128D653 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 01/30/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20128D585 | List: |
| References | |
| 50-445-92-59, 50-446-92-59, NUDOCS 9302100196 | |
| Download: ML20128D653 (21) | |
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] :b_PPENDIE
U'.S. NUCLEAR REGULATORY COMMISSION 1- REGION IV i
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! Inspection Report: 50-445/92-59
! 50-446/92-59-L
- Operating. License
- NPF-87 i Construction Permit: CPPR-127
! Expiration Date: August.1, 1995
). Licensee: TV Electric
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Skyway Tower
- 400 North Olive Street ,'
! Lock Box 81 i- Dall as, -Texas 75201-
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i Facility Name: Comanche Peak Steam Electric Station, Units' I andL2 L
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Inspection At: Glen Rose, Tt*as i . .
L Inspection Conducted: November.26, 1992,- through January 5, 1993
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! Inspectors: W. B. Jones,: Senior Resident. Inspector
- J. I. Tapia, Senior Resident
- Inspector 0 G. E. Werner,-Resident Inspector Approved: 30 -
L.'A. Yandell, Chief, Project-Section B- Date '
Division of Reactor Projects
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- . Inspection Summar ! Areas Inspected (Unit 1)
- Routine, unannounced inspection of onsite: followup _
l of plant events, operational safety. verification, maintenance and surveillance i . observations, followup of inspection items, followup of' licensee event.
reports (LERs), and followup of construction deficiencie .
Areas Inspected (Unit-2): Routine, unannounced inspection followup.of
-; construction deficiencies _.
i -- Results (Unit 1):
.- The operators responded very well to the main turbine high j pressure stop valve closure. Very good communications.were noted between the licensed and nonlicensed operators (Section-2.6).
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k * Adequate. oversight of a Technical Specification ' required surveillance was not provided, resuliing in a missed diesel generator- surveillance requirement for fuel oil sampling (Section 2.3). A poor work practice-
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-2-during a surveillance activity resulted in two main steam isolation valves closing (Section 2.4).
- Radiation protection .(RP) personnel response to decontaminate the individual who fell to the lower reactor cavity upper internals storage area was good (Section 2.2). The RP technicians conducted comprehensive briefings and provided continuous work coverage for containment activities (Section 3.4). An auxiliary operator (AO) exhibited poor .
radiological work practices which were similar to previously identified weaknesses (Sections 3.1).
- Close coordination between operations and engineering organizations provided for a prompt resolution to-the Limitorque motor operated valve 10 CFR Part 21 concern (Section 2.5).
. .The deoxygenate.(DE0X) skid design modification impact review-appropriately considered operations and chemistry procedure The-chemistry procedure provided-for appropriate operations notification to align the DE0X skid and condensate storage cross-tie valves for operation (Section 3.8).
- Selected emergency core cooling system valves and electrical' lineups were appropriately aligned to support Modes 1, 2, and 3 plant operations. Normally inaccessible emergency core cooling system major flow path valves inside the containment building were also verified to be properly aligned (Sections 3.2 and 3.5)
- Containment building walkdowns were effective-in identifying and -
documenting system leakage. Housekeeping activities were-good ,
(Sections 3.3 and 3.4).
- Maintenance work activities were performed in accordance with the work instructions'. Excellent work coordination.was' observed between'the operations, RP, and maintenance departments to repair the chemical"and volume control system flow control valve. An-inspection followup item was identified concerning the manufacture-and installation of jumpers-used during maintenance activities (Section 4).
- - The licensee's use of their corrective action-program was mixed. The ONE' form process was correctly utilized to identify a condition which could have resulted in eventual wviliary feedwater pump _ operability problems (Section 4.6). The initial m rective actions to identify and
- resolve the residual' heat re.noval (RHR) pump cavitation indications'were weak. Due- to early interactions between the inspectors and the-licensee, with respect to the RHR pump and system performance, it could-not be determined whether the licensee's-corrective action process would have adequately identified and resolved this issue without NRC involvement (Section 5.2).
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- Surveillance activities were conducted in accordance with the procedure requirements (Section 5).
Results (Unit 2): Not applicabl Summary of Inspection Findings:
- Inspection Followup Item 445/9259-01 was opened (Section 2.6)
- Inspection followup Item 445/9259-02 was opened (Section 4.3)
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- Inspection Followup Item 445/9013-04 was closed (Section 6).
LER 445/91-024 was closed (Section 7).
- Significant Deficiency Analysis Report CP-88-30 was closed (Section 8).
l Attachments:
- Attachment 1 - Persons Contacted and Exit Meeting
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' s-4-DETAILS 1 PLANT STATUS (71707)
At the beginning of this inspection period, the Unit I reactor vessel was defueled and the second refueling outage activities were in progress. On November 26, 1992, the licensee completed the Mcde 6 surveillance requirements and began reloading the reactor vessel core. The core reload was completed on November 28 and Mode 5 was entered on December Mode 1 and the main generator breaker closure occurred on December 26, signifying the completion of the second refueling outage. Power ascension was in progress up through December 30 when the high pressure stop valves were inadvertently closed with the reactor at 45 percent thermal power. This occurred during the
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installation of an automatic turbine test modification. A manual turbine trip was initiated by the reactor operator and reactor thermal power decreased to the point of adding heat. Mode I was entered the following day and the main generator synchronized to the grid. Reactor power was at 86 percent at the end of the inspection perio ONSITE FOLLOWUP OF EVENTS (93702)
4 Nonsafetv-related Transformer Failure
On December 3 a nonsafety-related power transformer failed as a result of an internal fire. Power was lost to nonessential loads, including the NRC offices. The inspectors responded to the control room to ascertain the areas in the plant affected by the power outage and to observe operator actions in assessing and responding to any plant transients. Upon arrival in the control room, the inspectors positioned themselves at the-edge of the unit supervisor's work area and inquired as to the plant status. The unit supervisor responded by telling the inspectors to stay back from the area where he and the reactor operator were discussing the ongoing event. The manager of operations was present in the control room during this event and observed this interaction. The inspectors located themselves within hearing distance, but not in the way, in order to ascertain the nature and plant areas affected. From this vantage point, the inspectors determined that the area affected was a nonsafety-related transformer supplying power to nonessential site facilitie Based on the operators' discussions and direct control board observation, the inspectors verified that equipment required for shutdown cooling had not been compromise Later that day, the inspectors discussed the interaction between the unit supervisor and the inspectors with the manager of operations. The inspectors expressed concern that a senior reactor operator did not appear to recognize or acknowledge the regulatory requirement established in 10 CFR 50.70,
" Inspections," which requires each licensee to permit inspection by duly authorized representatives of the NRC. This failure manifested itself in behavior which was unexpected and not conducive to allowing the inspectors to implement their regulatory oversight function in an unfettered manner. This condition was acknowledged by the manager of operations, who indicated that a
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unencumbered access to deliberations involving licensed activitie On December 18 the inspectors met with licensee management personnel, the cognizant shift supervisor, and the unit supervisor. During the meeting, the requirements of 10 CFR 50.70 were reiterated. The licensee acknowledged that -
the requirement was:well understood. The unit -supervisor subsequently stated that it was not his intent to deny or restrict the inspectors' acces The NRC reiterated its position that inspector activities should not in.any way encumber the performance of licensee duties. During an event.which occurred ,
on December 30 (Section 2.6), the inspectors interacted with the same operating crew. The inspectors were readily Lable to gain information-concerning the event from the senior reactor operators:and were able to observe the operators response.-
2.2 Contamint. tion of a Contract Employee in the Reactor Cavity On December 6 the licensee informed.the inspectors of a contamination event caused _ by a Westinghouse contractor -falling into _the lower reactor cavit This area is used to store:the-reactsr upper internals during refueling activi_ ties. This incident was documented by the licensee in ONE-Form 92-144 The incident occurred while the individual'was working on the reactor cavity floor.- His statement of the incident indicated that-he was working near the edge of the reactor cavity when he slipped-and fell.into the lower-cavity _
pool. There was approximately 12 feet of-water in the pool. The worker was not hurt and promptly exited the lower cavity poo _
Decontamination efforts included having the individual take several_-showers.-
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Later, the individual was provided with a whole-body count to assess.any radiological uptake. It_ was determined that a _ minimal internal intake. dose (approximately 0.2 mrem whole body) was received. No detectable external-contamination was present after decontamination' efforts were complete. =The inspectors reviewed Contamination Event-Report 92-70, which-identified ~that no detectable external contamination existed and that only a minimal _ internal uptake had occurred. The licensee determined that-this event was not reportabl The-inspectors reviewed th'e Performance Enhancement' Review Committee meeting notes for the review of ONE Form 92-1443. At the time of the incident, a barrier had not been installed to ' prevent workers from falling'into the~ lower reactor cavity area. LImmediate corrective actions included installing a temporary ~ barrier to prevent recurrence, initiating =the lessons-learned- process to address the installation of personnel . barriers, and making a_ life ring available during cavity work. The ONE form indicated that design engineering will evaluate the feasibility _ of-designing a permanent barrie l
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-6-2.3 Missed Diesel Generator Fuel Oil Surveillance On December 3 the licensee identified that the performance date for-Surveillance Work Order 5-92-500181-AG to sample the Train B emergency diese generator fuel oil had been exceeded. The sample was_ scheduled to have been taken on November 11, 1992, with a grace period until November-28, 1992, but the sample was not taken until December 3. The Train B emergency diesel generator was declared inoperable because of the missed surveillance. The licensee immediately initiated' actions to sample the Train B fuel oil storage tank. The sample was found to meet the Technical Specification requirements and the Train B emergency diesel generator was declared operable. The-licensee determined that the Train B emergency diesel generator would have performed its intended safety-function during:the period it had been declared inoperable. LER 92-026-00, Revision 0,_" Missed Diesel Generator Fuel-Surveillance-Due To Personnel Error," was issued on January-4 addressing this-event. The inspectors will r2 view this event during-a subsequent _ inspectio This review will include work activity scheduling during the second refueling outage, implementation of previous corrective actions.for other missed surveillances, and the corrective actions-identified in the license event report.-
2,4 Main Steam Isolation Valve (MSIV) Engineered Safety Features Actuation
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k On December 20, during the performance'of Procedure PPT-SI-9502B, Revision 0,
"MSIV Isolation Valve Response Time Train B," two main steam isolation-valves (MSIVs) were inadvertently closed. The instrumentation and control (I&C) technician was attempting to install- a temporary test lead when-it was grounded. This caused a slave relay (K627)lto actuate and close the two MSIVs. The test lead was grounded because of a poor work-practice,- The I&C technician had attempted to land a lead from-the recorder. -The other lead
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from the recorder was-already installed. It was found that the leadfcould:not be installed on the barrel of the terminal . lug, so the I&C technician attempted to spread the lead apart by using the edge of the cabinet. This grounded the lead, causing the relay to energize and close the two MSIVs. The plant was in Mode 3 at the time and no primary or-secondary system pressure or
- temperature transient resulted from the event. The licensee-notified the NRC Operations Center via-the Emergency Notification System and the inspectorsi ..,
were also: informed of the event, -The licensee is reviewing the-event to' -
determine if an LER is require .5 Limitoraue Valve Operator 10 CFR Part 21 Notification On December 17 the licensee learned of-a 10 CFR Part 21 report through Vendor Letter 13852. The report identified that limitorque Valve Models SMB/SB-000 and SMB/SB/SBD-00 motor-operated valve actuators were not -seismically quali_fied. ' It was_ learned that the declutch levers, which permit- the valves to be manually actuated, had been restrained during-the seismic qualification testin _ _ __ _
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i l The licensee provided a prompt engineering review of the 10 CfR Part 21 1 report. Based on their evaluation, it was determined that the report was applicable to Comanche Peak Steam Electric Statio Design Change
, Notice $381, Revision 1, was issued on December 1 This design change. notice j identf fled the t.imitorge valves which were affected, and provided a means of
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restraining each declutch lever. These levers were tie wrapped to return the
' valves to a condition similar to the seismic qualification test configuratio !
l 2.6 Manual Main Turbine Trin On December 30 with reactor power at approximately 45 percent, the main ,
turbine generator high pressure stop valves inadvertently closed. A plant
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transient ensued and the licensed operators manually tripped the main turbine to prevent a generator reverse power trip. The plant responded as expected and no abncrmel equipment actuations were noted during the transient or af ter
! review of the computer generated sequence-of-events printout. The inspectors -
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observed the licansed operators response to the transient. Prompt actions were taken to reduce reactor power to the point of adding heat. The 1 inspectors observed that the operators response to the transient was well overseen by the unit and shift supervisors, procedure use was noted to be
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l very good. Conurunication between the licensed and non11 censed operators was
' clear and good use of repeat-back statet.)nts was noted. Criticality was
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maintained throughout the event and the unit returned to Mode 1 the following
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i Subsequent investigation into the cause of the transient identified that a minor modification was being performed on the automatic turbine tester safety
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I&C and vendor technicians were working in the cabinet te
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device cabinet, i install an additional breaker to reduce the load requirements on a 24Vd::
breaker. Power to the cabinet was tagged out under clearance 1-92-04575. The clearance was reviewed by operations personnel and determined to be adequate.
! However, an intermittent ground existed on Bus 101, and during the work activity an arc occurred between the ground and a soldering iron being used in
! the cabinet. This caused a relay to actuate and close the high 3ressure stop t valves. The inspectors noted that the work activity had been scleduled to be
- done during the refueling outage. A review of the licensee's assessment of the event and the rationale for not performing the modification before startup is considered Inspection followup Item 445/9259-01.
3 ?.7 Conclusions i The licensee responded very well to the main turbine high-pressure stop valves closing. Communication between the licensed and nonlicensed operators was very good. The inspector's ability to gain information concerning the main
, turbine manual trip and observe the operators response was appropriate to provide an accurate assessment of the even RP personnel responded well to decontaminate the individual who fell into the
lower reactor cavity.
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-8-Oversight of surveillance requirements was not adequate to verify that all required surveillances were scheduled and implemented. A poor work practice during a surveillance activity resulted in two MSlVs closing. Close coordination was noted between operations and engineering to resolve the Limitorque 10 CFR Part 21 oncer OPERATIONAL. SAFETY VERIFICATION (71707)
3.1 !Ladiological Work Practice Observations During the previous inspection period, several poor radiological work practicos were observed by the licenste and the inspectors. These observations are documented in NRC Inspection Report 50-445/92-47; 50-446/92-47, paragraph 2.4, as Unresolved item 445/9247-04. The licensee's observations and short-term corrective actions were specifically directed at contractor personnel. These corrective actions were intended to enhance contract personnel work aractices in radici gically contaminated areas. The licensee and inspectors 1ad observed exampics of individuals opening their protective coveralls to obtain dosimetry and other objects. As stated in NRC Inspection Report 50-445/92-47; 50-446/92-47, the Itcensee had completed additional RP training for the contractor personn".; however, no additional training was provided for noncontract personne On November 30 the inspectors observed the dynamic venting of the Train A RiiR system. This evaluation required the A0 to manipulate potentially contaminated valves and to enter into the Train A RHR pump roo During the performance of this activity, the inspectors noted similar poor radiological work practices used by the AO:
- While i.. a contaminateo area, the A0 began to open his protective coverall- to obtain a locked valve tag from his shirt pocket. The inspectors immediately questioned the individual's action. The A0 indicated that he was going to let a second A0 standing outside the contaminated area reach inside his coveralls to remove the tag. An RP technician was then contacted. He removed the tag from the A0's pocket after putting on a set of rubber gloves. The inspectors discussed the A0's actions with him after exiting the contaminated area. The inspectors noted that the A0 was not cognizant of the poor radiological work practices which had been previously identified by the licensee and the inspector * A second concern was identified when the A0 entered the Train A RHR pump room without contacting RP. A posting on the door directed the individual to contact RP prior to entr The pump room had been posted l as a contamination and radiation area. Several hot spots were l identified on the RHR piping. The A0 had contacted the safeguards-
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radiation protection technician at the start of the shift while taking daily logs. Since the plant was shut down and the RHR system had been
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.g-drained, normally, the verification of radiation levels once during the shift would have been adequat The inspectors noted that the RHR pump suction was lined up to the refueling water storage tank; however, changing radiological conditions could have resulted during pump operation. The RP technician was not informed of the activity until
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after the inspectors prompted the o)erator to have the area surveyed for changing radiation levels. The tecinician surveyed the area and found no changes in radiation levels or hot spot location The inspectors discussed the AO's poor radiological work practices with the RP manager. He identified that no additional radiation worker training was planned for licensee personnel prior to completing the refueling outage. The RP manager did convey that long term corrective actions had been formulated in Plant incident Report 92-1168 to address the poor radiological work practices noted by the licensee and the inspectors. The adequacy of these corrective actions will be reviewed as part of the followup to Unresolved item 445/9247-04 which is beinq addressed in NRC Inspection Report 50-445/93-05; 50-446/9F 0 The inspectors observed RP technicians at the 832-foot level containment access point brief maintenance workers on radiological conditions inside containment. The briefing was very comprehensive and covered current radiological conditions, as well as actions required if radiological ccnditions changed during the maintenance activity. The RP technicians also used drawings of different elevations of containment to brief maintenance workers on area hot spots and other radiation hazards. After the briefing, the RP technicians quizzed a few maintenance workers on radiological conditions and also on the content of the radiation work permit under which the work activity would be performed. Most of the workers were cognizant of radiological requirements. Those: that were not were briefed and quizzed agai The inspectors also toured containment to verify that the RP technicians were providing continual support of maintenance activities during the outag Continual RP coverage was implemented by RP management as a result of personnel contaminations resulting from poor radiological work practices exhibited by contract maintenance personnel during the outage. During the tour, the inspectors noticed that RP was supporting each maintenance activity to assure proper radiological practices were exhibited to prevent additional contaminations. The inspectors observed that RP personnel promptly intervened to corrett poor radiological work _ practice .2 Train A Outaae Restoration The inspectors verified the Mode 5 electrical lineups for Train A RHR and the chemical and volume control system and the Mode 5 valve lineup for Train A RHR. The licensee had documented discrepancies in the system lineups on the system status discrepancy sheets. No errors in the lineups were noted; however, during the verification process. the inspectors did observe clearance tags marked for Unit 2 hanging on Unit 1 Breakers lEB3-2/8RF/BKR-2
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-10-component The clearance tags did meet the intent of Procedure STA-605, Revision ll, " Clearance and Safety Tagging," and no immediate safety concern was identified. The inspectors were concerned that the Unit 2 designated tags '
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on Unit I components could result in the wrong component being taken out of service. Operations was informed of the observation and promptly replaced them with Unit I tag ? 'onh jnment Walkdowns x ember 15 the inspectors accompanied the licensee on a preliminary nikdown of containment prior to completion of the second refueling outag The walkdown was led by operations and the lead containment coordinator and also included aersonnel from maintenance. The walkdown verified the statu'. of equipment, wor ( activities in progress, and general houtekeeping. A complete walkdown was conducted on the 960-foot elevation, 600-foot elevation, W the
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832-foot elevation. A full walkdown of the St4 foot elevation m not conducted since this elevation was not prepared for % over and additional housekeeping activities were in progress. He m er, the inspectors did conduct a cursory walkdown to verify the st% of the containment sumps. The inspectors noted that the sug a were clear and free of any type debris (tape, trash,etc.).
During the w.thewn. no equipment concerns were noted that could delay completion of the refueling outage. However, there were several pieces of nonsafety chiller support equipment tagged with work-in-1rogress tags. The licensee noted each tag and assigned the responsible wor ( organization with the task of resolving the tag before the final containment walkdown was conducte The inspectors noted that the status of housekeeping was good. Only minor debris was noticed in the entire walkdown. This debris was either immediately removed or included on a punchlist of activities to be performed prior to the completion of the refueling outage. Overall, housekeeping within the containment building was goo .4 Mode 3 containment Walkdown The insaectors accompanied operations and quality assurance personnel during the wal(downs of the containment building at normal operating temperature and pressure. The walkdowns consisted of a detailed examination of Reactor Coolant Pump Loop Rooms 2 and 3 to ensure that in-service inspection areas were not leaking and overall verification of piping integrity in the containment building. Numerous leaks were noted on vents and drain valves and associated downstream piping. Operations personnel verified that- the valves were closed and ensured that pipe caps were installed. Whenever a leaky component was identified, it was added to a discrepancy list. The discre>ancy list was used to identify components that would have to be repaired /rewor(ed, either prior to Mode 1, or at a later date. The licensee did not identify any reactor coolant system leakage which they concluded would cause a concern later in the operating cycl . , _ - _ . -
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-11-While in Reactor Coolant Pump Loop Room 2, the inspectors noticed a puddle of water on the floor. The water was leaking from a cap on the bypass vent valve on Reactor Coolant Pump 2 at the 842-foot elevation. During the time required to conduct the insaection, the water had run down the stairs to outside of the missile shield. T1e RP technician did not survey the water or rope off the area, thereby allowing individuals to step in the water. Personnel were dressed in protective clothing and no contaminations resulte The inspectors did note that the inservice inspection portion of the containment walkdown required additional personnel to remove lagging that had not been identified to be removed or previously identified to prevent reinsta11ation af ter maintenance. This oversight caused minor additional radiation exposure and personnel hazards due to working on high temperature components. The inspectors discussed this matter with RP personnel with regard to as-low-as-reasonably-achievable (ALARA) consideration The leak on the bypass vent valve on Reactor Coolant Pump 2 was subsequently identified on a corrective maintenance work order and repaire .5 Emergency Core Coolina System Walkdown Shortly after entry into Mode 3, the inspectors performed a walkdown of major flow-path manual valves inside the containment building associated with the chemical and volume control, RHR, and safety injection systems, and the safety injection accumulators. The valves were verified to be appropriately positioned and locked if recuired. The inspectors also performed a control board walkdown and confirmec that all emergency core cooling system control switches were properly aligned for Mode .6 Contro' Room Observations The inspectors observed various control room activities during the second refueling outage. Observations were conducted during normal daily and backshift activities in preparation for mode changes and during reactor startup. Startup and mode change checklists for Modes 2 and 3 were completed in accordance with plant procedures. Control room personnel were generally found to be cognizant of ongoing activities that could affect plant equipmen Very good communication and use of procedures was exhibited by all shift crew . Personnel Overtime to Support Refuelinq Outane Activities Maintenance and operations departments utilized overtime to supplement the normal shift complement during the refueling outage. The inspectors reviewed the overtime deviation authorization and summary. forms, STA Forms 615-1 and 2, for the months of November and Decembe The inspectors verified that-deviations from the overtime guidance specified in_ the Technical Specifications were appropriately authorized. It was found that' overtime usage was spread among the department's personnel. No abuses of overtime usage were identifie ___o
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Specifications were appropriately authorized, it was found that overtime usage was spread among the department's personne No abuses of overtime '
usage were identified.
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3.8 Condensate Storage Tank Desian Modification The inspectors reviewed Design Modification 91-033, Revision 0, " Addition of l Piping to Allow Treatment of Condensate Storage Tank Inventory." This modification permits recirculation of the condensate storage tank to reduce oxygen concentration and contaminates, and to allow for chemical addition The physical plant changes included piping connections to nonsafety-related piping that can be aligned directly to the condensate storage tank. The insaectors noted that piping connections could permit the condensate storage tan ( level to decrease below the Technical Specification limit with the DE0X skid in servic The inspectors reviewed the operators' impact assessment formt which were used to identify procedures and programs affected by the design chance. The training organization revised licensed operator and A0 requalification training and initiated licensed operator training plans to include the design modification. The operations department revised Station l'rocedure 50P-303A,
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Revision 5, " Coordinator System," to include tie-in valves. Opdrational control of the DE0X system was delineated in Cll-8140. Revision 0, " Operation
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of the DE0X Skid (CST)." The inspectors noted that the alarm response procedure for the condensate storage tank level, operator logs, and turnover check sheets had not been identified as being imlacted by the d mign modification. This concern was discussed with tie operations support group, and it was found that these items had been considere Procedure CLI-814A provided for notifying operations to align the system for operation and
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shutdow The licensee noted that operation of the DE0X system was expected to be included on the operator turnover sheets in the comments sectio On December 20 the inspectors observed the shift turnover for the evening shift with the balance-of-plant operators. The oncoming balance-of-plant
operator questioned the off-going operator concerning the status of the condensate storage tank DE0X skid. The off-going operator thought the system was secured. Approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after turnover, the inspectors questioned
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the balance-of-plant operator about the DE0X skid and he indicated that he thought it was secured but would have to check.
4 The DE0X skid had been aligned and placed in service the previous day in accordance with Procedure CLI-814A. The chemistry procedure requires that the chemistry technician recommend the use of the system and coordinate with operations personnel to place the system in service. Followup calls to the secondary chemistry lab found that the chemistry technician was unaware of system status. The lead chemistry technician had aligned the system during the previous night shift and was aware that the DE0X skid was in service. The reactor operator logs, perimeter A0 logs, and chemistry logs had rio reference to system startup. The safeguards building A0's log indicated that the DE0X skid lined up to the candensate storage tank.
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The inspectors noted that the operations and chemistry personnel were not )
cognizant of the DE0X skid status. Although no personnel or equipment hazard existed during the period, it was noted by the inspectors and the licensee that their management's expectations were not me .9 Conclusions Licensed and nonlicensed operators demonstrated good communication between themselves and with other departments. Procedures were appropriately utilized. One instance was identified where the status of the DE0X skid was I not understood by the reactor operator or the chemistry technician. A review of operations and maintenance overtime usage indicated that the licensee was meeting the Technical Specification requirements for deviating from the guidanc The DLOX skid design modification impact review appropriately considered operations and chemistry procedure The chemistry procedure provided for appropriate operations notification to align the DE0X skid and condensate storage tank cross-tie valve Selected emergency core cooling system valves and electrical lineups were appropriately aligned to support Modes 1, 2, and 3 plant operations. Normally inaccessible emergency core cooling system major flow path valves inside the containment building were also verified to be properly aligne The RP technicians conducted comprehensive briefings and provided continuous work cov< age for containment activities. An A0 exhibited poor radiological work practices which were similar to previously identified weaknesse Containment building walkdowns were effective in identifying and documenting system leakage. Housekeeping activities were goo MAINTENANCE OBSERVATION (62703) Replace Steam Generator Blowdown Valve The inspectors observed two contract maintenance personnel preparing a pipe nipple in preparation to weld in a replacement valve for Steam Generator Blowdown Vent Valve ISB-0184. The work was being conducted in accordance with Work Order 1-92-02280-00. The proper cleanliness zone was established and tool accountability was being maintained. The maintenance personnel were observed using good work practices. The inspectors verified that the work order was listed on Clearance 1-92-02548 and had been accepted by the maintenance grou .2 Motor-0perated Valve Static Test The inspectors observed two contract motor-operated valve analysis and test system technicians performing the setup of test equipment necessary to perform i a static test of Motor-0perated Valve 1-FV-4772-2, the Train B containment
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-14-spray recirculation valv The technicians were following Procedure MSE-P0-8007, Revision 1, "MOV Strain Gage Calibration," and were documenting determinated wires using the lifted Icad and jumper log. The inspectors found the technicians knowledgeable of licensee procedures and verification processe .3 Containment fan Cooler Corrective Maintenance The in.;pectors observed the installation of an electrical jumper in preparation for the implementation of corrective maintenance Work Order 1-92-024810-00. This work order was issued to replace the bearings and clean the Containment fan Cooler 1-03 motor. The purpose of the jumper was to support the installation of a gag on the fan discharge damper. The work order provided instructions to manufacture and termiaate a jumper between Terminal Points TBJ-8 and TBJ-9 in Switchgear IEB3/98/ Comp in accordance with Procedure MSE-G0-1203. procedure MSE-G0-1203, Revision 2, " Electrical Terminations Wire Sizes 26 AWG Through 10 AWG," was reviewed by the inspectors. Section 8.1.10, " Installation of Field Jumpers," requires that jumpers be installed as shown on interconnection drawings using the type and size wire compatible with circuit requirements. The procedure does not specify the connection details for the jumper. As a consequence, the jumper in use during the implementation of the work order utilized alligator clips on each end. The inspectors noted during the observation of work that the contract electrician attempting to install the jumper was having difficultly in securely attaching the jum)er to the terminal block. The permanent wires are attached to the terminal alock with screws which leave little room for securely attaching an alligator clip. The electrician was instructed by an A0, who was providing independent verification of the jumper installation, to cease attempting to install the jumper because the alligator clip fell off every time the cabinet door was closed. The electrician then proceeded to the shop to manufacture another type of jumper connection. The observation of this process by the inspectors identified a practice which has the potential to cause future problems because of installed temporary jumpers falling of The lack of specific instructions for the manufacture and installation of temporary jumpers is an observation for the licensee'_s consideratio The review of the licensee's program for electrical jumper control'is considered Inspection Followup Item _445/9259-0 .4 flow Control Valve Packina Renlacement On December 30 the inspectors observed the replacement of live load packing on chemical and volume control system flow control Valve 1-FCV-0121. This valve was repacked.during Refueling Outage 2 with the new style live load packin The packing failed, resulting in identified primary leakage of approximately 3 gp Operations and maintenance personnel attended the maintenance activity prejob-brief. A standby clearance was used for this activit r
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-15-With Valve 1-fCV-0121 isolated, operations personnel were unable to use the centrifugal charging pumps (CCPs) through their normal charging path; therefore, normal seal injection flow using the CCPs was unavailable. The Technical Specification 3.1.1.2 requirement that three boron injection flow paths shall be operable was satisfied by being able to use an alternate charging path. The positive displacement charging pump was in service and .
supplied the reactor coolant pump (RCP) seals. Contingencies were developed to supply RCP seal injection flow using the CCPs, if the positive displacement pump failed. Procedures were developed and operations personnel were stationed to open a manual valve to supply seal injection flow in the event that the positive displacement pump became inoperable. The inspectors found the operations personnel cognizant of the proceduralized contingency action Mechanical maintenance personnel repacked the valve as authorized by Work Order 1-92-033144-00 and Proceduro MSM-G0-8202, Revision 2, " Graphite Valve _ l Packing and Live Loading." Continuous RP technician coverage was su? plied by a dedicated technician. The system engineer observed the failed paccing removal. No specific cause for the packing failure was eviden Valve 1-FCV-0121 was returned to service later in the day and was observed to be operating properly. The operations, RP, and mechanical maintenance department personnel worked well as a team to perform this task in a timely manner. Excellent work practices were used by the maintenance technician .5 tLotor-Driven Auxiliary feedwater Pump Rotatina Element red 1acement The inspectors observed activity associated with the tear down and inspection of the Motor-Driven Auxiliary feedwater Pump 1-01. This activity was authorized by the shift supervisor on October 30, 1992. Work Order 3-92-321107-01 provided, in part, for the tear down and inspection of the pump rotating element, it was identified that the pump packing had significantly degraded on both the inbound and outbound ends, in June 1992. Motor-Driven Auxiliary feedwater Pump 1-01 actuated, as a result ,
of both blackout sequencers actuating. When Motor-Driven Auxiliary Feedwater Pump 1-01 was operating, the inboard pump packing extruded. This event is documented in NRC Inspection Report 50-445/92-24; 50-446/92-24, paragraph 7.1, j A violation was identified at the time (445/9224-01) because a ONE Form was ( not initiated to further evaluate the packing failure.
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The inspectors found that the work activity was performed in accordance with the work order. The rotating element was replaced by the work activity. ONE
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form f> 92-1124 was initiated because of the identified degraded packing. The l
0NE form process was correctly utilized to identify a condition which could L have resulted in eventual pump operability problem .6 Conclusions
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Maintenance work activities were performed in accordance with the work
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instructions. Excellent work. coordination was observed between the
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-16-operations, RP, and maintenance departments to repair the flow control valv An observation was identified for the use of manufacturing of jumpers used during maintenance activitie The ONE form process was correctly utilized to identify a condition which could have resulted in eventual pump operability problem SURVEILLANCE OBSERVATIONS (61726)
5.1 RHR Dynamic Vent On November 30 the inspectors observed the dynamic venting of the Train A RHR system following the Train A outage. Surveillance Work Order 5-92-500426-AA and Procedure SOP-102A,- Revision 7 " Residual Heat Removal System," were the governing documents used to conduct the surveillance. In addition, the system was concurrently being vented using Procedure OPT-203A, Revision 3, " Residual Heat Removal System Operability."
The A0 performing the venting was briefed by the reactor operator and was given the two arocedures to follow. All valve manipulations were done in accordance wit 1 the procedures. Good self-checking and knowledge of expected system response were noted by the inspector .2 Review of ASME Section XI Testina for 1 rain A RHR Pump The licensee conducted ASME Section XI testing on Train A RHR pump and check valves after maintenance on the system. Operations Testing Manual Procedure OPT-203A, Revision 3, " Residual Heat Removal System.0perability,"
Section 8.8.1, was conducted on November 30. Train A RHR pump was started and immediately secured due to indications of cavitation (varying motor amperage and fluctuating discharge pressure). The initial test was conducted at high-flow rates and the licensee changed the procedure to reduce the system flow rate to approximately 1000 gpm and move the pump farther away from pump-run-out condition The inspectors were informed of the Train A RHR pump cavitation the next mornin This was the first performance of Surveillance Test Section 8. following the expanded ASME Section XI testing scope. The system alignment consisted of taking a suction from the refueling water storage tank and discharging back to the suction side of the pump at full-flow conditions, approximately 4500 gp Pump runout flow is approximately 5500 gp The refueling water storage tank level was at 20 percent and this supplied a suction pressure of 20 psig. The required net positive suction head pressure stated in the design basis documents and Final Safety Analysis Report is approximately half of what was being supplied to the pump at the time of the surveillance. Subsequent questions about the cause of the pump cavitation were not addressed and the inspectors questioned the operability of the RHR pump during accident conditions under the same flow and pressure condition T
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-17-address the apparent cavitation and pum) operability concerns. 533 tem engineering, working in conjunction witi operations, determined that the pump had not cavitated; however, they did conclude that the puma fluctuation had been caused by air in the RHR heat exchanger U-tubes that and been recirculated to the suction side of the pum The operations department contacted other sites and compared their RHR fill and vent procedure with the others. The licensee came to the conclusion that the procedure used to vent the system was not adequate to remove all the air from the RHR U-tube heat exchanger. The RHR system lineup for testing was such that any air in the heat exchanger would be returned to the suction sido of the pump. Past operating and surveillance system lineups were such that air remaining in the heat exchanger would be sweat into the reactor coolant system or cavity. The licensee also indicated t1at preoperational testing had demonstrated that the RHR pumps would not cavitate under full flow condition Due to early interactions between the inspectorr. and the licensee with respect to the RHR pump and system performance, it could not be determined whether the licensee's corrective action process would have adequately identified and resolved this issue without NRC involvement. The licensee's initial corrective actions to revise the surveillance procedure to decrease the pump flow rate were taken without first determining the cause for the indications of apparent pump cavitation. As a minimum, the licensee's delay in initiating a ONE form for potential cavitation in a major emergency core cooling system component is indicative of a weakness in the licensee's safety assessment and corrective action program .3 MSIV Testina The inspectors observed the performance of Procedure OPT-509A, Revision 2,
"Section XI Testing of Unit 1 MSIVs," Sections 8.2.7 and 8.2.8, authorized in accordance with Work Order 5-92-500065-A The viewed sections of the surveillance verified the operability of MSIV 3 and 4 relays and stroke time The test was completed satisfactoril .4 Train 8 Safetv In.iection and toss of Offsite Power Testing
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on December 11 the inspectors observed Section 8 of Procedure PPT-SI-7411B, Revision 1, " Safety injection in Conjunction with Loss of Offsite Power, Train B." This procedure was performed-to satisfy 18-month Technical Specification surveillance test requirements regarding engineered safety features actuation, response times, and diesel generator capability. The inspectors observed actuation of the signal from the control room and noted that equipment operated as required. Communications with personnel out in the plant were excellent, observers were stationed appropriately to record data, and the test engineer provided good coordination of the activity. The inspectors reviewed the test procedure and verified that procedure changes had been properly inserted, that prerequisites had been :atisfied, and that restoration was performed properly. Later that day, the inspectors observed the performance of Procedure PPT-SI-7415B, Revision 1, " Safety injection l
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e-18-without loss of Offsite Power, Train B." As above, this procedure was performed to satisfy 18-month Technical Specification surveillance test requirements. The inspectors observed the prerequisites being established, the assignments of observers to record data, and the communications. The inspectors noted that good coordination existed between the operators and test engineers, that personnel were attentive to duties during the test, and that communications were good. The inspectors reviewed the completed tes procedure and verified that all steps were completed and that appropriate data was recorded on various attachment .5 Emeraency Core Coolina System Forward Flow Testina The inspectors observed a aortion of the emergency core cooling system check valve operability test. T1e test was conducted in accordance with Procedure PPT-SI-8200,--Revision 1, and Work Order 5-92-502110-AA. The inspectors observed control room activities during testin Good communications existed between the control room and A0s.- The inspectors also verified that the test flow transmitters, which were installed to measure seal injection flow, were operable and properly calibrate During the test, the inspectors noticed a discrepancy between the RCP seal injection flow indicators and charging flow controller (1-FK-0121) reading The seal injection readings were measured at Flow Indicators 1-FI-0142, 1-F1-0143, 1-F1-0144, and 1-F1-014 Flow Controller 1-FK-0121 measures -the total charging flow across Orifice 1-FE-0121. Flow Controller 1-FK 0121 also records the output of- Flow Control Valve 1-FCV-Ol?l - The test- procedure required Valve 1-FCV-0121 to be throttled to obtain 40 gpm maximum charging flow. The maximum reading measured by Flow Controller 1-FK-0121 while throttling Valve 1-FCV-0121 was approximately 21 gpm.- The combined flow to the RCP seals as measured by the seal injection flow elements was approximately 40 gpm. A flow transmitter, which was installed across -
Orifice 1-FE-0121 to provide flow indication, also measured approximately 21 gp The licensee stated that maintenance had been performed on the orific (1-FE-0121) earlier. in- the outage and the orifice.may 'not have been properly vented. The licensee then vented the orifice which'is downstream of
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Valve 1-FCV-0121.- -After the orifice was vented, Flow Controller 1-FK-0121-indicated approximately 40 gpm for a short period of time, then, flow-Transmitter 1-FX-0121 again indicated approximately 21 gpm. The licensee suspected that throttling the flow:through Orifice 1-FE-0121 collapsed additional _ air .in the line which caused the differences in the readings._ The-licensee _ suspected the air inside the orifice lines caused incorrect
. . differential pressure across the instrument diaphragm, resulting in-erroneous
, readings at Flow Controller 1-FX-0121. Additional _ fill and vent of-the lines-
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removed the remaining air, and charging flow then corresponded _to seal-injection flow.
I Due to the inability of Valve 1-FCV-0121 to control flow, the licensee decided
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c 1to'use measurements taken from the RCP seal as indication of. seal injection
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-19-flow. The procedure originally required seal injection flow indication to be taken at flow Controller 1-FK-0121. A procedure change notice was written to allow seal injection flow to be measured at the RCP seals. After the data was collected, the licensee conducted an evaluation to determine if there was enough flow to the seals to allow readings to be taken from RCP seal indicators. The licensee evaluated the flow through check valves at the output of the charging pump. The licensee compared the actual flow with the minimum acceptance criteria for the check valve. The analysis concluded that there was enough flow to assure proper seal injection. The ins 3ectors reviewed the licensee's evaluation and concluded it was accepta)l .6 Conclusions Surveillances were conducted in accordance with the procedural requirement The emergency core cooling system flow test was properly reviewed and the surveillance test procedure revised to permit the use of alternate flow indicatio The licensee's corrective actions to identify and resolve the conditions which
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resulted in the RiiR pump cavitation indications were considered weak.
i Although the immediate corrective actions prevented recurrence of the
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condition, it appears that, without the inspectors continued questions in this l area, the inadequate RHR venting practice may not have been identifie FOLLOWUP (92701) (Closed) Inspection Followup Item 445/9013-04: Auxiliary feedwater system check valve backleakane Backleakage from the main feedwater system to the auxiliary feedwater system was originally observed in April 1990 during low-power operations. The licensee's evaluation has shown no adverse effects on auxiliary feedwater system operability or safety function provided by the check valves; however, the system was designed for relatively low temperatures and not the normal operating temperatures of the main feedwater syste The licensee installed eight temperature elements on the upstream side of the auxiliary feedwater supply line check valves. These indications are on the main control panel, thereby allowing operators to monitor temperatures for indication of main feedwater backleakage. In addition, differential temperature annunciators _ comparing feedwater and auxiliary feedwater nozzle temperatures give indication of backleakage. During at-power conditions, no abnormal backleakage has been indicated; however, indications of backleakage have been noted periodically during startup. When backleakage has been indicated, the operators have rectified the condition by-following i y Procedure ABN-305, Revision 3, " Auxiliary feedwater System Halfunction." The 1 l
inspectors concluded that the licensee's corrective actions were appropriat !
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-20-7 ONSITE REVIEW 0F LER (92700)
The inspectors reviewed the following LER to determine whether corrective actions were adequate and whether the response to the event was adequate and met regulatory requirements, license conditions, and commitment .1 (Closed) LER 91-024: " Inoperable Main Steam Safety Valves Due to less lhan Adequate lift Setpoint Ve.'ification Procedure" The main steam safety valves were initially tested and their lift setpoints were adjusted on March 20, 1990. On October 4, 1991, the main steam safety valves were again tested in accordance with the approved procedure; however, 13 of the 14 main steam safety valves were found to be out of Technical Specification tolerances. The setpoints were subsequently rese The licensee identified the root cause to be a less than adequate procedur The main steam safety valves were initially set with a very high ambient noise level caused by the operation of atmospheric relief valves. The actual lift setpoint was determined by audible indication of valve simmering. The high noise level interfered with lift setpoint indicatio The procedure was changed so that the atmospheric relief valves would be closed or a method adopted to account for high ambient noise level The inspectors reviewed the licensee's corrective actions and found them to be appropriat FOLLOWUP ON LICENSEE ACTION ON 10 CFR PART 50.55(e) DEFICIENCIES (92700) (Closed) Construction Deficiency _Significant Deficiency Analysis Report CP-88-30: " Cold Overpressure Hitiaation System (COMS)
Actuation During Accident Events" This issue was closed for Unit 2 in NRC Inspection Report 50-445/92-42; 50-446/92-42. The Unit 2 report referenced Safety Evaluation Report Supplement 25, Section 5.2.2. The Unit I cold overpressure mitigation system is like-for-like with the Unit 2 cold overpressure mitigation system and, based on the reviewed documentation, the issue had been adequately addressed.
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ATTACHHENT 1 1 PERSONS CONTACTED 1.1 10 LLiCTP.ir 0. Bhatty. Site Licensing R. D. Bird, Jr. Manager, Work Control Center M. R. Blevins, Director of Nuclear Overview W. J. Cahill, Group Vice President, Nuclear Engineering and Operations R. R. Carter, Assistant to Menager, Maintenance J. R. Gallman, Trend Analysis Manager W. G. Guldemond, Manager, independent Safety Engineering Group T. A. Hope, Site Licensing Manager J. J. Kelley, Vice President, Nuclear Operations J. J. LaMarca, Manager, Engineering Outage B. T. Lancaster, Manager, Plant Support D. M. McAfee, Manager, Quality Assurance S. S. Palmer, Stipulation Manager D. J. Reimer, Manager, System Engineering E. J. Schmitt, Operations / Engineering Training Manager L. H. Strope, Plant Analysis B. B. Taylor, Staff Assistant, Plant Operations R. O. Taylor, Manager, Administrative Services c.. L. Terry, Vice President, Nuclear Engineering and Support R. D. Walker, Manager of Regulatory Affairs for Nuclear Engineering 1.2 NRC Personnel L. A. Yr.ndell, Chief, Project Section B D. N. Graves, Senior Resident inspector, Construction The personnel listed above attended the exit meeting, in addition to the personnel listed above, the inspectors contacted other personnel during this inspection perio EXIT MEETING An exit meeting was conducted on January 5, 199 During this meeting, the inspectors reviewed the scope and findings of the report. The licensee did not identify as proprietary any information provided to, or reviewed by, the inspector _ _ _ _ - _ _