IR 05000440/1988200
| ML20150D293 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 06/06/1988 |
| From: | Beckman D, Castleman P, Cummins J, Guthrie S, Mccormick, Mccormickbarge, Miller L, Norrholm L, Sharkey J Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20150D288 | List: |
| References | |
| 50-440-88-200, NUDOCS 8807130410 | |
| Download: ML20150D293 (39) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION Division of Reactor Inspection and Safeguards Report No.:
50-440/88-200 Docket No.:
50-440 Licensee:
The Cleveland Electric Illuminating Company P. O. Box 5000 Cleveland, Ohio 44101 Inspection At: Perry Nuclear Power Plant Perry, Ohio
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Inspection Conducted: March 14-25, 1988
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Other NRC Personnel Attending Exit Meeting:
Brian Grimes, Deputy Director,
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Approsed By:
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TABLE Or CONTENTS l
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1.0 INSPECTION SCOPE...............................................
2.0 DETAILED INSPECTION FINDINGS...................................
2.1 Operations.....................................................
2.1.1 Shift Routine..................................................
2.1.2 Procedural Control.............................................
2.1.3 Staffing and Operator Qualification............................
2.1.4 Shift Overtime.................................................
2.2 Maintenance
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10 Work Planning and Scheduling (...................................
2.2.1 Measuring and Test Equipment M&TE) Program....................
2.2.2
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2.3 Surveillance Testing...........................................
2.3.1 Organizatica and Scheduling....................................
2.3.2 Surveillanc Procedures........................................
2.3.3 Surveillance Tests Witnessed...................................
2.4-Nanagement Oversight and Safety Review.........................
2.4.1 Goals, Objectives, and Staffing................................
2.4.2 Systems Engineering............................................
2.4.3 Independent Safety Engineering Group (ISEG)....................
2.4.4 Plant Operations Review Committee (PORC).......................
2.4.5 Nuclear Safety Review Committee (NSRC).........................
2.5 Ouality Programs...............................................
2.b.1 Quality Assurance (QA)/ Quality Control (QC) Involvement........
2.5.1.1 Quality Audits and Surveillances
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2.5.1.1.1 QA Audits......................................................
2.5.1.1.2 OA Surveillances...............................................
2.5.1.2 Quality Control and Engineering................................
2.5.1.3 S u m a a ry........................................................
2.5.2 Corrective Action Program......................................
2.5.2.1 Audits of the Corrective Action Prcgram........................
2.5.2.2 Condition Report Program.......................................
2.5.2.3 Trends Program.................................................
32 2.5.2.4 Summary........................................................
3.0 EXIT MEETING...................................................
ATTACHMENT A - ATTENDANCE SHEET ATTACRMENT B - LIST OF OBSERVATIONS GLOSSARY
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a 1.0 INSPECTION SCOPE The primary focus of the inspet'in* was the safe operation of the Perry Nuclear Power Plant. The inspection effort was concentrated on control room operations and activities that interfaced with operations and supported the safe operation of the plant. As a part of the operations performance evalua-tion, the team observed 162 hours0.00188 days <br />0.045 hours <br />2.678571e-4 weeks <br />6.1641e-5 months <br /> of shift coverage and conducted random ba;kshift and weekend inspections.
In addition to observations of operations, inspections in the areas of maintenance, surveillance, management oversight, safety review, and quality programs were parformed.
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2.0 DETAILED INSPECTION FINDINGS 2.1 Operations During the inspection period, the team of nine inspectors observed operating activities in the control room and in the plant to obtain a representative overview of the licensee's conduct of operations. Of the 162 inspector-hours spent in direct observation of activites, 95 hours0.0011 days <br />0.0264 hours <br />1.570767e-4 weeks <br />3.61475e-5 months <br /> were spent on backshift and weekend coverage.
Sixteen shift turnovers were observed in the control room, involving randomly selected licensed operators serving in the capacity of Shift Supervisor (SS), Unit Supervisor (US), or Supervising Operator (50). Several turnovers within each shif+ were observed among licensed operators.
2.1.1 Shift Routina The team members observed that, during all three shifts control room decorum reflected professior,a1 attitudes that emphasized control over the facility and
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shift activities. The noise level in the general area was sufficiently low that it did not i.iterfere with comunications among operators, and traffic contro* in the horseshoe-shaped control area was adequate to properly restrict access.
In every instance, inspectors who entered the horseshoe area, after first obtaining permission from a licensed operator, ware challanged by other on-shift personnel. Responses to annunciations were generally thorough, although qveral team members observed separate examples of operators who cleared alarming annunciators without appearing to look at the annuciator panel to determine the source of the alarm condition.
Control room operators were found to be generally aware of plant status, component condition, and system configuration. Turnovers during shift change were usually thorough, although inspectors did note riifferences. between operating crews in the depth and detail of information passed along to the relieving crew.
Inspectors also noted that the oral and written turnovers often lacked a historical update of events and activities. One example was the ongoing diagnosis of problems with steam accumulation in the shutdown cooling portion of residual heat removal (RHR) system piping. Although the operating staff's involvement included temperature monitoring programs, periodic filling and venting procedures, and communication with the Systems Engineering Group, little mention was made of the evolution of the problem among operators.
Oncoming shift personnel regularly reviewed logs and other supporting docu-ments, including the active and potential limiting condition for operation (LCO) logs and the work order list, and were observed to walk down the control room panels alone and with the offgoing op'erator. There appeared to be suffi-cient time alloted for shift turnovers, and there were no observations of a turnover conducted quickly to pennit rapid relief of the offgoing crew.
Whil~e shift turnovers were generally thorough and lengthy, within shift turn-o..s conducted beween operators on the same crew were regularly observed to be brief and informal and to rely heavily on the assumption that the relieving operator was fully versed in plant status, in one instarice, a relief between 50s lasted an estimated 10 seconds and included 2 items related to tests tr evolutions in progress.
In another ir. stance, a US being relieved by the M had been involved in an interview with a team member for approxWtely 25 mindes prior to his brief turnover. The inspector observed-2-
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I that while the SS was present in the control room for that period, no comunica-tion occurred between the two operators.
The team evaluated the accuracy and effectiveness of control room log-keeping by reviewing the unit log maintained by the 50, the active and potential LC0 logs, and special logs for data collection on RHR shutdown cooling system piping. Midnight unit log entries, which provide a daily plant status sumary, were generally thorough and detailed. While the unit log was formally main-tained, team members often found it to be lacking in depth and detail.
For example, team rr. embers who had followed two major events during the inspection period, RHR problems and one inoperable main steam isolation valve (MSIV), were able to reconstruct the basic elements of the two events in sequence, but the detail contained in the unit log entries was insufficient to pennit analysis of the event or aid in its diagnosis. Team members identified discre-pancies in the thoroughness of unit log entries by comparing the inspector's knowledge of an event that had been observed with'the un!; log entry used to document that occurrence.
For example, for the March 20 power decrease result-
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ing from isolation of one MSIV, no explanation of the event was documented.
Likewise, the procedural deviation described in section 2.1.2 of this report that occurred during venting and filling operations on RHR piping on March 22 was not mentioned, nor was the verification of the position of the valve that was incirrectly operated. Despite the personnel errors and procedural devia-tions t' e unit log recorded only that the venting and filling evolution had been cor deted satisfactorily.
Both these examples describe incidents in which the requ rements of procedure OAP-1702, "0PS Section Rounds, Logs, and Records," were not met. Additionally, although the procedure requires the unit log to be a "hardbound, sequcntially numbered document," inspectors observed that the unit icg was being maintained on individual sheets inserted in a three-ring loose-leaf binder and that on two occasions individual sheets had
'orn at the three holes and become separated from the binder. Licensee person-
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i.el indicated the intention to return to the use of a hardbound document. The above examples of failure to properly maintain the unit logs is an observation (440/88200-01).
Team members oLserved that the LC0 logs, were disorganized and contained entries that apeared to offer only a sketchy explanation of a condition that
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led to an LCO. Nonetheless the logs were useful for those who used i; hem regularly. The operators interviewed were consistently able to identify and describe equipoent deficiencies, plant conditions, and applicable time constraints related to the LCO.
Further, the effectiveness of the LCO tracking system was an apparent contributor to the reduced number of LC0 violations since the fe.ility's startup test phase.
Data :ollection logs associated with RHR piping problems were thoroughly kept in accordance with temporary instructions.
Status boards mounted in the horseshoe area were nbserved to be effectively ut lized by shift personnel.
The emergency core cooling system (ECCS) status board m maintained current, and accurately reflected the degraded condition of RHR system piping. While the new electrical lineup status board was main-tained, the unofficial "note pad" style status board used by the US was not generally maintained current.
Interviews with shift personnel indicated that the board was a wall-mounted equivalent of a note pad and was not relied upon for accurate plant status. Operators appeared to be familiar with the use of the computers available in the control room and the status information 3-
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available, particularly the computerized work order list used as the only reliably maintained list of work in progress.
In additior, to generally being current with regard to plant status, operators were usually found to be knowledgable regarding equipment operating characteristics and peculiarities of control room instrumentation and how those characteristics could affect plant operation.
For example, operators were aware of the difference between the indicated and actual level on RHR beat exchanger A.
Licensee personnel were, in general, effective in their control of not-in-service (NIS) and information tags.
Implementation of procedures for both types of tagging was evaluated by checking approximately 200 tags against the require-
,ents of Plant Administrative Procedure (PAP) 1401, "Safety Tagging," Revision 3, and through inspection of the tag logs, tag placement, and operator inter-views. The team confirmed that the required supervisory reviews and approvals and periodic audits were made and that the tags were properly logged. The licensee has emphasized minimizing the number of active NIS tags by timely repair of out-of-service instruments and annunciators, and progress was
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routinely reported in the monthly management trend, reports. During the inspection period, active NIS tags numbered six per month for 1987 and tnree per month for 1988. A review of the declining long-term trend indicated that continued management emphasis on timely equipment repair was effective.
Inspectors reviewed the control of jumpers and lifted leads by evaluating the effectiveness of alterations made during the inspection period or. the high pressure core spray (HPCS) test return valve 1E22F011. Tag orders and the associated 10 CFR 50.59 applicablity checks were found to be in compliance with the requirements of PAP 1402, "Control of Lifted Leads, Jumpers, Electrical Devices, and Mechanical Foreign Items," Revision 5.
A review of the modified system configuration showed that the intended purpose of the altera-tion, that of maintaining certain HPCS related annunciators operable, had been met without undesirable side effects. Although isolated examples of minor recird keeping discrepancies were identified, the team concluded that licensee personnel were generally effective in controlling lifted leads and jumpers.
The team observed deficiencies in the communications equipment available in the Unit 2 control room area for use by the 50 to supervise the nonlicensed plant operators.
Those deffciencies had been previously identified by the licensee and installation of comunications equipment comparable to that in Unit I was planned for the future. The team concluded that this additional equipment should enable the 50 to comunicate directly with plant operators without funneling communications through the 50 at the controls of Unit 1 and permit the control of certain equipment comon to both units from the Unit 2 control room.
Team members touring the plant noted that plant cleanliness was generally adequate. The material condition of unpainted carbon steel piping located inside the containment was, however, of concern to team members, who noted scaling and flaking rust on welded joints in RHR low press re coolant injection (LPCI) piping and other piping in nonsafety-related systems.
Exterior surfaces
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of the piping it. the vicinity of welded joints had, in some locations, deteriorated to the point that pits were visible.
With the possible exception of the interface between operations personnel and the Systems Engineering Group, the team determined that the operations inter-face with other licensee organizations was generally efficient and protiuctive.
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Maintenance personnel, for example, regularly adjusted the aggressive cyclical maintenance schedule to address problems which had the potential for adversely Impacting plant operation or causing an LC0. Likewise, the Reactor Engineering
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Group worked with the operators to prepare a visually displayed power / flow map that was used regularly.
Interviews with operations personnel revealed frustra-tions with the operations / systems engineering interface that appeared to be rooted in the operator's desires % be active contributors to the resolution of problems affecting plant operation.
Interviews with licensee management determined that this interface problem was well-known to management and was under review.
The team concluded that licensed operators on ' watch in tae control room had professional attitudes, displayed pride in the quality of their performance, and had appropriate concern for safe facility operation. Through interviews and observation of interaction with other licenset personnel the team concluded that operators clearly understood that the license carried with it both the responsibility and authority to supervise and direct the activities of others
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in the interest of safe reactor operation. Team members frequently observed an interest among operat rs in the events that occurred during the inspection period and a desire to contribute toward the prompt resolution of equipment problems that impacted operation.
Such interest was indicative of good morale among the operating staff. Liceraed operators appeared to have a sound under-standing of integrated plant operations, as evidenced by their understanding of the relationship between the RHR, reactor water cleanup, and condensate transfer systems during the diagnosis of RHR system malfunctions.
Loewise, observations and interviews with nonlicensed plant operators indi-cated enhanced understanding of facility layout, design, and operation when compared with their general knowledge level during the plant's startup test phase. Plant operators seemed to be familiar with the operating characteris-tics of individual plant components and with the general administrative and record-keeping requirements associated with nuclear plant operation. Plant operators also appeared to have a reasonable understanding of integrated plant operations, as illustrated by one plant operator's understanding of why the HPCS room floor drain could not be left partially open to permit continuous draining of the sump without impacting the operation of other systems located in separate rooms.
Plant operators seemed to dispicy an appropriate sense of responsibility and concern for the material condition of the facility and the, impact of the material conditions on safe plant operation, as evidenced by the manner in which plant operators were observed checking bearing temperatures, draining air dryers, and changing annunciator panel light bulbs.
Plant operators appeared to be current on the status of maintenance activities ongoing in tne plant and responsive to off-normal conditions.
For example, one plant operator who heard what may have been a water hammer in RHR piping notified the control room and investigated in the crea for pipe hanger damage.
2.1.2 Procedural Control As team members observed activities in the control room and in the plant, operator actions were compared with the requirements of the appropriate approved pro.edures applicable to the activity, The procedures were found to be maintained in a current condition, and observations in the (.ontrol room indicated that the applicable nrocedure was utilized as a reference or working document for even the most routine evolutions. Procedural content was complete
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and all numerical values and setpoints were present, indicating that the transition from construction and startup test phases to the operational phase was reflected in the. body of the procedures.
Interviews with operators indi-cated that the numerical values, setpoints, and equipment operation guidance
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contained in the procedures reflected the actual operational characteristics of the plant and not simply the design characteristics, thus adding to their usefulness as working documents on which operators could rely.
Each procedure appeared in general to be sufficient in that it contained all the necessary acceptance criteria, supporting data and formulas, and administrative controls,-
such as sign-off verifications.
The volume of temporary changes to procedures appeared to be managable for operators using the document in the field.
The potential for confusion caused by temporary changes was greatly diminished by incorporating the changes into the body of the procedure by replacement of an entire revised page rather than attaching a temporary change to the front of the procedure. Using margin bars
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to note the changes helped operators stay aware of temporary changes. The team did not identify any appreciable time lags in the management approval or administrative processing of permanent procedural changes.
The team noted that the actual total number of procedures was approaching 4000 and still growing as the plant's first refueling outage approached. This substantial volume of procedural guidance could become difficult to administra-tively control and utilize effectively; but nonetheless the team was unable, with the assistance of operators, to identify a single example of duplication, contradiction, or confusion among procedures. Operators consistently demon-strated their ability to identify and effectively utilize the appropriate procedure. This performance led the team to conclude that the seemingly excessively large volume of procedures had not detracted from safe or efficient plant operation.
Standing instructions were evaluated, and they appeared to effectively fill the time lag between management's decision to alter a particular operating practice and publication of the actual procedure change.
For example, pending a proce-dural change to require operators to accept an RHR shutdown cooling isolation rather than attempt a bypass of the reactor protection system (RPS) during certain surveillance tests, a management directivs was imediately distributed to operators via a standing instruction, that permitted the RPS bypass.
Compared with skills observed during the startup testing phase, operators had made significant progress in the use of the technical specifications as a working document, as evidenced by the decrease over the last year in the number of missed surveillance tests and LCO violations.
am members saw evidence in two instances that, while procedures were routinely
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and effectively used in the control room, activities with the capacity to affect facility safety were being conducted in the plant without benefit of procedural control.
In the first instance on, March 22, 1988, two plant operators attempted to vent and fill RHR system piping but incorrectly attached the vent hose to a valve in a separate portion of RHR piping located near the correct vent valve. Venting through the incorrect valve did not yield the expected discharge of steam and hot water. The plant operators did not, however, question the apparent inconsistency, even though this activity had been conducted before and the expected results had been obtained. The entire-6-
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evolution was conduct 9d without written procedural guidance and without guidance from the 50 in person ( ' via radio, even though a surveillance proce-dure existed to perform the fill qg and venting operation. The evolution was successfully completed after the reem members investigated and discovered the incorrect valve lineup. The above tailure to exercise proper procedural controls is an observation (440/88200-02).
In addition to the absence of appropriate procedural controls, factors contributing to this incident included:
invalid assumptions on the part of each plant operator that the other was fully versed in the evolution,
- operator unfamiliarity with the piping configuration,
- a willingness to readily accept unreascr.able and unexpected results
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without further investigation, absence of supervisory control on the scene or via -adic.
The filling and venting activity was completed successfully approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later using an appropriate procedure, but still without 50 supervision.
No mention of the incident or verification of the correctly restored valve lineup was inserted in the unit log.
No condition report (CR) was generated until two days later when a team member raised the question.
In a second instance on March 23, 1988, the team member on the scene in the RHR room did not observe the use of procedural guidance 6Jring valve manipula-tions. The confus'on among plant operators and the absence of S0 involvement was again apparent to the inspector.
2.1.3 Operator and Station Qualifications Based on observation and interviews with licensed operators staffing the control room, the team concluded that both the quantity and quality of opera-tors appeared adequate to ensure safe facility operation. Operator knowledge of component design, construction and operation, system configuration, and integrated system operation was determined to be generally high. The team saw evidence that as the design characteristics of components and systems were revised to reflect operating experience, operators had an active interest and integrated that new knowledge into their operating strategies. The team expects the operator knowledge level to improve as the plant moves toward routine full-power operation. Likewise, the team concluded that the quantity and quality of nonlicensed plant operators was sufficient to support plant operation and emergency response.
The team expressed concern over the role of the 50 as fire brigade leader.
While fully supporting the licensev s decision to have a licensed operator making operational decisions during a fire emergency, the team considered that.
the designated fire brigade leader should not be the 50 at the controls of the reactor so as to provide for prompt brigade leader response without the need for a within-shift S0 turn'over. During the inspection period, the licensee, made a comitment to revise PAP-0301, "Conduct af Operations," to change the-7-
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manner in which the brigade leader is designated so that the designated S0 would not be the 50 at the controls of the facility.
In addition, the licensee will revise the method by which the fire brigade attack team leader is desig-nated to ensure that a trained and qualified individual is assigned. The licensee also agreed to provide all attack team leaders with training compa-rable to that provided to the fire brigade leader through modification of PAP-1917, "Fire Protection Training Programs." This action addressed the team's reasoning that the attack team leader directing fire fighters at the scene of the fire should be able to fully assess the situation and provide appropriate information to the brigade leader at the comand post location physically removed from the fire scene.
The team regarded the depth of fire-fighting experience among personnel in the security and fire protection sections as a strong asset to support plant operations. The licensee's emphasis on fire protection training was considered to be a strength.
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The team identified an apparent need for greater 50 involvement in directing the activities of nonlicensed plant operators performing duties in the plant.
The team concluded that, while plant operators performed routine duties thoroughly, they did not demonstrate the knowledge of conservative, integrated plant operation necessary to conduct evolutions without appropriate guidance and supervision. The incident involving venting from the incorrect RHR valve described in section 2.1.2 is an example.
In that event, the involvement of the 50 in ensuring that the operation was carried out safely and successfully was conspicuously absent. The 50 did not provide the plant operator with the available procedure, review the procedure requirements with the plant operator, or rehearse the activity.
Nor was the 50 present on the scene or in radio contact. The 50 was not visibly involved in verification of the restored valve lineup once the incorrect lineup was discovered.
During the secord perfomance of the venting and filling activity, approximately three hours later, the 50 prepared procedural guidance for use by the plant operator but was still absent from the scene and not in radio contact.
This failure of 50s to direct ongoing activities is an observation (440/88200-03).
There was an observed need for plant operators to improve attention to detail while in the plant, including enhanced attention to radiological control practices and the ALARA concept. For example, while touring in containment, the team observed that plant operators failed to notice significant leakage from a maintenance project in progress. While performing RHR venting and filling activities, plant operators ignored water that had leaked onto the floor. That wa.ter was later found to be slightly contaminated.
In another instance an operator reached across a roped radiological barrier to use, as a writing desk, the top of a drum identified as containing contaminated clothing.
In addition to considering that the S0 supervising plant operators should spend
more time in the plant, the team identified a need for managers above the SS level to regularly tour the facility.
Inspectors reviewed security computer records from the last quarter of 1987 that documented access through entry doors into the control room, the radiologically controlled area (RCA), and containment for eight managers above the SS level. With two. notable excep-tions, the management group visited the control room infrequently, rarely made RCA entries, and virtually never entered containment.
Supporting data are not presented in this report because the licensee determined that these data were-8-
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safeguards information. The licensee informed the team, however, of a newly implemented program to require increased management touring in the plant.
The inspectors observing control room activities identified as a significant concern the administrative burden placed on the US as the SRO-licensed indi-vidual required to approve all work and surveillance activities in the plant.
The paperwork demand on the US was observed to be so time consuming as to potentially impede his ability to supervise control room operations. The administrative burden distraction for the US was considered by the team to be extreme during the day shift, difficult during the evening hours, and manageable on the midnight shift. The inspectors noted and supported the licensee's decision to have one licensed supervisor authorize and control all work, but expressed concern that this duty seriously detracted from the ability of the US to perform other supervisory duties considered important to safe
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facility operation. Those individuals interviewed indicated that the US and 50
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rarely toured in the plant.
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The demanding workload on the US was passed along in great part to the 50 at the controls because nearly all technicians, maintenance personnel, and contractors who receive work authorization from the US must then interface with the 50 in order to actually accomplish the authorized work. The distracting demands on the 50 were exacerbated by the volume of surveillance tests, requests for keys and information, and required telephone notifications of work such as weldiny Like the load on the US, the day shift 50 had the greatest burden.
Inspectors on several occasions observed that the 50 suspended all contact with nonoperators and turned to the control panels to assess plant conditions.
The team concluded that the recently implemented corporate smoking policy has resulted in the occasional absence of licensed on-duty operators from the control room. Because the closest designated smoking area was well-removed from the control room, thr. team's concern focused on the absence of key watch-standers from the control room for a nonplant-related activity.
The team concluded that any time essential licensed personnel were absent from the control room the crew's ability to respond to emergencies was diminished.
In one observed instance, a US was absent from the control room for a smoking break for 19 minutes. The 'JS provided only a brief turnover to the SS relieving him, and did not carry a radio. However, there were public address speakers in the designated smoking area. The team emphasized the importance of maintaining a full shift complement readily available and the need to minimize absences not related to operation of the facility.
2.1.4 Shift Overtime The team reviewed the licensee's controls for approval of overtime for personnel perfonning safety-related functions and key maintenance activities.
PAP-0110. "Shift Staffing and Overtime," Revision 2, established the guidelines and requirements for the approval of overtime for key personnel. PAP-0110, Section 6.5, "Overtime Guidelines," required that prior to making an overtime assignment, any supervisor shall review the individual's overtime hours for compliance with the overtime guidelines and shall initiate an overtime deviation request when needed.
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i A revicw of the Operations, Maintenance, and 1&C Departments' overtime and attendance records for the three months preceding the inspection identified eight instances in which the overtime guideline limit had been exceeded but had not been approved and one instance in which blanket authorization to exceed the overtime guideline limit was approved.
In the first instance, the team found that three power plant operators (PPO)
and two I&C technicians had exceeded 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in 7-days (excluding shift turnover) without an overtime deviation request authorization. One PPO had exceeded 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48-hour period without an overtime deviation request authorization.
In the secad instance, the team noted that a memorandum from the Maintenance General Supervisor to the Operations Department Manager, dated January 15, 1988, was used as a blanket overtime deviation request to exceed the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in 7-days guideline because of outage work.
In this case, the individuals exceeding the overtime guideline limit were not identified, nor was there
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evidence that the potential impact on plant safety was considered for the individual's overtime work activities.
In both instances the requirements of PAP-0110 were not observed.
Further, this practice was inconsistent with the published NRC policy statement, dited February 11,1982, "Policy on Factors Causing Fatigue of Operating Personnel at Nuclean Reactors." The team recognizert that the licensee's Quality Assurance (QA) Department had previous?y identified the blanket overtime deviation request as a problem.
in response to the QA finding, the Maintenance
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Group Supervisor made a commitment to provide an itemized list in the overtime deviation request prior to individuals exceeding the overtime guideline limit.
The team was concerned that excessive or unmonitored overtime could signifi-cantly reduce the effectiveness of operating personnel.
During this inspec-tien, the licensee acknowledgej the team's concern and indicated that improve-ments were needed in this area. These examples of excessive or unmonitored overtime constitute an observation (440/88200-04).
2.2 Maintenance The team reviewed the measuring and test equipment (M&TL) program, selected
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maintenance procedures, selected completed work requests, and examined the work planning and scheduling processes. Overall, the te.am found these areas to be adequately administered and controlled. The following strengths and weaknesses were noted in the maintenance functional area.
2.2.1 Work Planning and Scheduling The scheduling and planning of preventive and corrective maintenance, surveil-lance testing, and design changes (modifications) were found to be an integrated activity. The licensee utilized a coordinated approach by removing a train or portion of a system from service on a scheduled quarterly basis for maintenance, surveillance testing, and modification work. Consequently, the disabling of safety systems was minimized by accomplishing all planned maintenance in a relatively brief period of time. At the time of this inspection, the 1.icensee was in the first cycle of the quarterly schedule.
Some minor problems were.
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noted with the implementation of the quarterly maintenance schedule but were
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9 considered to be typical program startup problems.
For example, approximately 21 percent of the planned work from week 11 of the 13-week schedule was carried into over week 12.
If this problem persisted, the potential cascade effect of excessive carryover from week to week would negate the usefulness of the quarterly maintenance approach. The team noted, however, that there was virtually no carryover from week 12 to week 13.
Based on a review of plant procedures and personnel interviews, the team considered the practice of integrated planning and scheduling of preventive maintenance, corrective maintenance, surveillance testing and design changes to be a strength.
2.2.2 Measuring and Test Equipment (M&TE) Program The team reviewed the licensee's program for the control and administration of M&TE. Overall, the team was favorably impressed with the qualifications and knowledge level of the M&TE staff and the laboratory. One significant
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weakness in the licensee's M&TE program was evident. Administrative procedure PAP-1201, "Control of Measuring and Test Equipment," Revision 3, provided for the control of M&TE used in obtaining and establishing a high degree of confidence in the accuracy of safety-related measurements, as required by ANSI N18.7 and 10 CFR 50, Appendix B.
Section 6.6 of PAP-1201, "Nonconformance of Perry Plant M&TE," Revision 3, required that whenever M&TE had been issued and later found to be out of calibration, the past reliability of the M&TE must be determined.
PAP-1201 also requred that an out-of-calibration report (PNPP Form 5861/A) be sent to each responsible user or issue point if the M&TE in question had been used on plant instruments. The lead supervisor or engineer for the responsible user group was then required to perform an evaluation to determine whether any plant equipment in service was potentially affected.
If the operability of any plant system was in question, the lead supervisor or engineer was required to imediately notify the shift supervisor.
The lead supervisor or engineer was then required to ensure that a work order war, issued, or that a retest was performed to correct the potential problem.
At the time of this inspection,123 out-of-calibration reports had been issued in 1988. Thirty-seven of the 123 reports were issued for M&TE that had not been returned to the M&TE laboratory for recalibration.
In these cases, the M&TE was in calibration when it was issued; however, it had not been returned to the laboratory before its calibration due date expired.
The out-of-calibration report form providpd seven. evaluation codes to document the disposition of the work affected by the M&TE in question, as follows:
No Action Required Because:
Al Affected range (s) was(were) not used.
A2 The error did not cause any test result / calibration to exceed c
equipment allowable tolerances.
A3 Instrument would not function, 'ailure time and cause were known, and past reliability of the instrument was evaluated as being acceptable providing reasonable assurance that the instrument was in calibration prior to failure.
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A4 Other: Attach specific remarks on the attached list or on a separate sheet of paper.
Based on the Evaluation:
B1 The equipment listed on the attached list as marked required to be rechecked /recalibrated.
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B2 The equipment listed on the attached list was rechecked / rect.librated and no further action is required.
B3 Other: Attach specific remarks on the attached list or on a separate sheet of paper.
The team reviewed approximately 63 completed out-of-calibration reports to determine the acceptability and thoroughness of the evaluations. The team
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l found that 10 of 15 reports for equipment that had not been returned to the
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M&TE laboratory had been disposed of inappropriately.
Evaluation codes A1 - A3 were used routinely but incorrectly for the following reasons:
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If an instrument was lost or not turned in, the "as found" l
calibration data were not available to identify the affected l
range (A1),
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If an instrument was lost or not turned in, the "as found" l
calibration data were not available to identify the magnitude
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of the M&TE instrument error (A2),
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If an instrument was lost or not turned in, there was no l
record of a review of past calibration data to support the
contention that an instrument had failed in the field, tnat
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the failure time was known, or that the instrument had failed to function (A3).
The team was concerned about the failure to properly dispose of work affected by M&TE that was out of calibration.
In some instances, the affected M&TE was used to perform surveillance tests, safety-related maintenance, and post-l maintenance testing.
The team was also concerned with the licensee staff's apparent willingness to use equipment that was known to be out of calibration to obtain data.
For
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example, out-of-calibration report 88-0078, dated February 24, 1988, was issued
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for equipment that had not been returned for calibration.
The M&TE in I
question, a digital thermometer, was issued on November 5, 1987, and its l
calibration expired on November 20, 1987.
However, this instrument had a quarterly calibration frequency. On March 8,1988, out-of-calibration report 88-0078 was disposed with the following statement:
Equipment still in use in
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Engineering using to obtain data." The approval signature (responsible lead ergineer or supervisor) for the disposition was made by the I&C Department supervisor.
In response to the team's concerns, the M&TE in question was
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returned to the M&TE laboratory and recalibrated satisfactorily.
During the inspection, the process of evaluating work affected by
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out-of-calibration M&TE was discussed with the licensee.
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R staff personnel acknowledged the team's concern and indicated that improvements in the review and approval of out-of-calibration reports would be implemented.
2.3 Surveillance Testing The team inspected the surveillance testing progrdm, including program controls, implementation, scheduling, procedures, and post-surveillance data i
review. Several surveillance tests were observed, personnel associated with the program were interviewed, and plant records were reviewed to verify proper implementation of the program.
2.3.1 Organization and Scheduling The licensee implemented the surveillance testing program under PAP-1105.
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"Surveillance Test Control." This procedure described the organization, responsibilities, and program controls in effect to ensure that required surveillance testing was completed in a proper and timely manner.
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The Technical Specification Surveillance Instructions (SVIs) were developed and maintained by Technical Administrative Procedure TAP-0503, "Preparation of Technical Specification Surveillance Instructions." Full coverage of Technical Specification surveillance. requirements was tracked by using the Technical S;ccification/ Surveillance Instruction Cross Reference Matrix maintained by the Surveillafice Cotrdinator.
Surveillance testing was scheduled by the repetitive task function of the Perry plant maintenance information system (PPMIS), which tracked the required due dates for surveillance testing for each piece of equipment. The scheduling algorthms included th'e grace periods allowed by the Technical Specifications, and provided a due date and a late date for each test. A review of the surveillance completion records for all safety-related surveillance tests performed during the period December 1, 1987 through March 15, 1988 verified that no test had been performed late because of a scheduling error and that partially completed tests were not treated as fully completed for subsequent surveillance test scheduling. All tests noted to be past their late dates were late because of improper plant conditions, inoperable equipment, or relief granted by the NRC.
The surveillance test tracking performed by PPMIS was backed up by semi-automated means to ensure that the required test due dates would not be lost if there was a failure of the PPMIS. This backup tracking function, performed on a personal computer, appeared to be effective. The data base was updated daily, and the resulting test listings were validated against the comparable PPMIS data. Another function of the personal computer system was to produce the weekly test schedule and operational condition chang? checklist.
A master SVI book was maintained in the control room, and was used by the control room staff to track the status of scheduled SVIs.
Besides the scheduled SVI list, this book also contained a matrix which cross-referenced surveillance tests with their respective Technical Specifications, and the Operational Condition Change Checklist.
The Operational Condition Change Checilist, maintained under the control of PAP-1114. "Operational Condition Change Checklist," provided the operators a sumary of all required SVIs coincident with a change in plant operational condition. This method of tracking condition-dependent SVIs appeared effective.
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PAP 1105, "Surveillance Test Control." and PAP-1101, "Inservice Testing of Pumps and Valves," required that completed pump tests be reviewed by the control room staff and the cognizant surveillance coordination and engineering staff within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> of test completion, and recommended that valve tests be reviewed within four working days of test completion.
In the team's review of completed tests, the team noted that all test reviews were performed within the required or recommended period, including nonpump and valve tests. The timeliness of test review was noted tu be a strength but the post-test technical data reviews and analyses of trends appeared to be somewhat shallow, especially in cases where inconsistent or anomalous data were obtained.
Further elaboration of this weakness is presented in section 2.3.2.
2.3.2 Surveillance Procedures
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Several survaillance test procedures were reviewed for technical adequacy, rigor, and usefulness.
In general, the procedures were well written and
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appeared to test the required functions.
The inspection team noted, however, one instance in which the omission of a required procedural step resulted in obtaining incorrect stroke times for containment isolation valve 1E12-F021 (RHR C test valve to suppression pool).
During performance of test E12-T2003, "RHR C Pump and Valve Operability Test,"
Revision 5, the subject valve had erratic stroke times over a period of several months. Dn December. 14, 1987, 1E12-F021's measured stroke time was 22 seconds; the previously determined normal stroke time for this valve was about 78 seconds, with a maximum allowable time of 90 seconds. Because of the varia-tion, the cognizant inservice inspection engineer increased the stroke-time test frequency from quarterly to monthly, and wrote a work request to have the stroke-time disparity investigated. The following data were obtained during four successive stroke-time tests of valve 1E12-F021:
12/14/87 22 seconds 01/21/88 21 seconds 01/25/88 78 seconds 02/29/88 77 seconds Review of test E12-T2003 and associated data packages from the dates listed above showed the apparent cause of the erratic stroke times to be a lack of clarity in the wording of the surveillance instructions, which, if followed verbatim, would result in the subject valve being stroked from a throttled, instead of fully open, position.
It appeared as though the operators who performed the tests on December 14 and January 21 followed the procedure verbatim, while the operators who conducted the tests of January 25 and February 29 were knowledgeable enough to fully open the valve prior to stroking; however, PAP-1105 requires the tests to be performed in a
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step-by-step sequence unless deviation is specifically authorized in each surveillance instruction. The operator who performed the test on January 25 recommended that the procedure be modified to have. valve 1E12-F021 fully open prior to stroking in order to obtain a valid stroke time.
In response to team concerns the licensee developed and implemented the requested procedure change while the inspection team was ensite.
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The inspection team had the following concerns as a result of the problem:
inadequate procedure used to demonstrate operability of a containment isolation valve, repeated deviation from the SVI procedural steps, no staff action to correct procedural deficiency for a period of more than seven weeks, and lack of aggressive investigation of the erratic stroke time of the valve in question.
Another case of inadequate review of valve performance data was observed by the team during review of historical stroke-time data. The team noted that the stroke time for valve IB21-F067C underwent an increase of more than 400 percent following the motor-operated valve analysis and testing system (MOVATS)
testing. On May 28, 1987, the subject valve's measured stroke time was 5 seconds. Workorder(WO) 87000402, issued for this valve on July 21, 1987, required that the valve's remote position indication limit switches be reset per Generic Electrical Instruction (GEI)-14. "Limitorque Limit / Torque Switch Adjustment," in concert with M0 VATS testing per gel-56, "Motor Operator Valve Analysis and Testing System (M0 VATS) Testing." Following completion of W0
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87000402 the measured stroke time was 21 seconds.
It should be noted that the valve's maximum allowable stroke time was 22.5 seconds. The licensee's method for measuring stroke time, as specified in PAP-1101, was to measure the time required from valve actuation switch positioning until receipt of the proper light indication in the control room.
It appeared evident that the pre-M0 VATS stroke times for valve 1812-F067C were based on erroneous limit switch sett-ings. The licensee was unable to provide the inspection team with pre-M0 VATS data demo 71strat1ng where the position indicating limit switches were set for this safety-relate:! motor-operated valve (MOV).
Further, the licensee was not able to definitively show where the corresponding limit switches were set for any other. safety-related MOVs which had not undergone MOVATS testing and the associated limit switch resetting.
At the time of the inspection, the licensee had performed POVATS testing on about one-half of the plant's safety-related MOVs, with the remaining MOVs to be tested by the end of the first refueling outage, which was scheduled for the first quarter of 1989. This item was turned over to Region Ill for followup. See NRC inspection report 50-440/88004 for the details of that followup.
The team's major concern resulting from this issue was that for those valves which had not Undergone M0 VATS testing Technical Specification surveillance stroke timing was being performed based on unknown MOV position indication limit switch settings.
Secondary ccncerns arising from this issue were that an in-depth investigation into the dramatic rise in stroke time had not been performed. As a result, the generic problem of unknown and potentially inaccurate MOV position indicator limit switch settings was never addressed.
The licensee had initiated action to confinn these limit switch settings prior to the time the team left the site.
Staff development and verification of surveillance tests were also inspected by the team, in particular, two licensee programs were reviewed:
the yellowline review and the currency review. The main purpose of the yellowline review program was to verify that the channel and system logic specified in Technical Specification section 3/4.3, "Instrumentation," was tested properly and that the sequential and overlap testing described in the surveillance instructions adequately met the requirements of the Technical Specifications. The main purpose of the currency review program was to perform a one-time review of all surveillance tests to ensure that applicable Technical Specification require-ments were adequately addressed, to verify the technical adequacy of the tests,
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and to identify and correct any undesired plant actuations or isolations caused by the tests. Both these programs appeared to be implemented in a meticelous manner and seem to be achieving their stated objectives.
2.3.3 Surveillance Tests Witnessed The following surveillance tests were witnessed by the team:
B21-T0032C "Reactor Vessel Steam Dome Pressure High Channel C Functional Check," Revision 3 B21-T0369B "Safety / Relief Valve Pressure Actuation Channel Functional for 1821-NG888," Revision 2 j
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C51-T0027E "APRM Trips Channel E Functional. Check " Revision 2, D17-T8051
"Offgas Vent Radiation Monitor Functional Check," Revision 3
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E31-T5395A "RHR/RCIC Steam Line Flow High Channel A Functional,"
Revision 1 R43-T1318
"Division 2 Diesel Generator Start and Load," Revision 2.
These surveillance tests were satisfactorily performed by on-shift operations personnel in accordance with approved, implemented procedures. The test personnel appeared to have a comprehensive knowledge of the surveillance procedures, test equipment in use, and equipment responses during conduct of the tests.
2.4 Management Oversight and Safety Review The general functions of engineering, committee activities and independent safaty evaluations were reviewed with respect to their roles of providing operational overview and support.
The plant is operated by the licensee's Nuclear Group, headed by the Nuclear Vice President who reports to the Chairman of the Board, and the Nuclear Group Vice President, who reports to the company President. The operating organiza-tion consists of five major departments: Operations. Technical, Nuclear Engineering, Quality Assurance, and Project Services.
Day-to-day engineering
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support is provided by the Technical Department, with design engineering and related functions supplied by the Nuclear Engineering Department. The
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Independent Safety Engineering Group (ISEG) is part of the Reliability and Design Assurance Group of the Nuclear Engineering Department.
The team's evaluation focused primarily on the ISEG, the corporate Nuclear Safety Review Committee, the on-site Plant Operations Review Committee, rnd the Nuclear Steam supply System (NSSS) Engineering Unit of the Technical Department. The principal attributes considered were the organizational
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structure, personnel and staffing, and definition and implementation of the organizational functions. The organizational structure was reviewed to deter-mine that it was prescribed by corporate policy documents, that its functions were adequately defined by charter documents and procedures, and that staffing and staffing plans were adequate to fulfill th'e chartered roles. The status of the implementation of major organizational functions was determined by-16-
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reviewing the procedures that were in place to fulfill charter functions; reviewing procedure implementation records; and interviews and discussions with licensee managers, supervisors, and staff personnel inside and outside the departments of interest.
Implementation of selected functions such as inter-departmental comunications, plant engineering support, and problem resolution was assessed by reviewing licensee activities and plant problems occurring during the inspection. Team member observations of plant equipment and operational activities during the day shift and the backshift in the control room and plant areas were included.
2.4.1 Goals, Objectives, and Staffing The primary sources of policy, goals, objectives and implementation require-ments were the top tier Perry Ope-ations Procedures (P0Ps) Manual and the second-tier Operations Manual Plant Administrative Procedures (PAPS).
Selected POPS and PAPS that were reviewed with respect to management oversight
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and engineering support are discussed below.
The details of.the procedures and individual department and group staffing levels and plans we e discussed with licensee management and staff. Particular
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emphasis was given to review of the HSSS Engineering Group and the ISEG.
Each group was found to have a weG-defined charter with specific roles defined for subunits.
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The Technical Department functions were specified by POP 0103, "Organization of Perry Plant Departments," Revision 0, and PAP-0101, "Perry Plant Operations /
Technical Department Organization," Revision 3.
The team was advised that a pending Revision 4 to PAP 0101 would authorize restructuring of the existing mechanical, electrical and inservice inspection testing units and that a transition to the new organizational structure was in progress. The team concluded that the new structure should meet the corpore.,:e objectives and fulfill assigned functions.
Staffing levels were found to be consistent with licensee plans, subject to routir.o personnel rotations and short-term varia-tions.
ISEG functions were specified by Technical Specificat!on 6.2.3, "Independent Safety Engineering Group"; Updated Safety Analysis Report (USAR) Section 13.4.3, same title; P0P-0203, "ISEG Operations," Revision 0; and Nuclear Engineering Department Procedure NEDP-0201, "!SEG Conduct of Operations,"
Revision 2.
The aoove procedures were found to adequately reflect the license requirements. The ISEG staff consisted o'f the General supervising Engineer for Reliability and Design Assurance as Chairman, a full-time ISEG Supervisor, and five ISEG members on one year rotational assignments from other departments.
Discussions with ISEG managers indicated that the rotational engineer assign-ments had adversely offected the group's continuity, and longer rotations or permanent assignments were bein; contemplated.
Failure and root cause analyses were performed by the ISEG, the Technical Department and other organization units. Although PAP-1601, "Failure
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Analysis," Revision 1, provided a general assignment of responsibilities and processes, the licensee had not yet adopted specific failure analysis or root cause determination methods nor implemented personnel training.
The licensee appeared to be aggressively pursuing development of techniques and training to improve this function and had formed a multidepartment task force to guide this-17-
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Ldevelopment. The task force was targeted to implement the plan through-initial
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personnel training in May 1988. The team reviewed the task force's resource
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_ material and found it extensive and representative of industry state of the
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c art. Several trial-use programs were in progress on current ISEG projects, including the use of condition / event charting, barrier analysis, and change -
analysis.
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The team reviewed the qualifications and training of. incumbents in ISEG and Technical Department positions and determined that educational credentials, prior professional experience and plant (or plant-type) experience was accept-able.. In nearly all cases, the Technical Department Systems Engineers were
. degreed engineers _with extensive in-plant experience gained during test programs at Perry or contemporary boiling-water reactor facilities. This
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resulted, wi'h a few individual exceptions, in the engineers having especially
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good technictc credibility, which was relied on by the operating staff. The
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-1SEG staff possessed similar hualifications, with several of the members having
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design-oriented backgrounds.
Interviews with plant staff indicated that ISEG
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had previously not enjoyed good credibility or rapport with the operating organization, largely because of the group's prior organizational staf'
ISEG's early (circa 1985-86) projects were viewed by the staff as insuiti-ciently rigorous, unnecessarily negative, and with low-to-moderate constructive output..Recent changes in ISEG operating philosophy appeared to be correcting this. negative image.
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The team reviewed plant and job-specific training for a sample of Technical Department and ISEG personnel. The licensee was participating in the Institute of Nuclear Power Operations (INPO) training accreditation program for
"Technical Staff and Managers (TSM)". The team reviewed the training status with respect to the licensee's Final Safety Analysis Report (FSAR) and Updated i
Safety Analysis Report (USAR) commitments and the plant Training Manual and
found that the progress to date was consistent with the licensee's commitments.
This training program involved 11 courses, including plant reference materials, codes and standards, QA/QC, physical sciences and engineering, and plant systems and integrated operations. This program was still largely under development during the inspection and was scheduled for presentation to INP0 in June-July 1988. Only two versions of the plant systems training course (five-week and one-week courses) had been available and conducted. About one-half the targeted staff had received either one or the other of the two
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courses. As a result, training for about 75 percent of the staff members reviewed had been limited to "required reading" of procedures and unstructured on-the-job training. All the staff members in the groups of interest were identified for eventual participation in the training program. The licensee's training program also required development of departmental specific training plans to. supplement the general training. These plans were not yet under development. Some equipment-specific or task-specific training had been,
provided and was planned for the future on a case-by-case basis upon request by
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line management.
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2.4.2 Systems Engineering As previously mentioned, the NSSS Engineering Group was the focal point of this
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portion of the inspection. This group provides the principal day-to-day engineering support function for the plant operating staff. The engineering i
support interface with operational activities appeared to be well-integrated.
The systems engineering responsibilities included system troubleshooting and-18-
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problem investigation support; root cause analysis; work order initiation, review, and retests; surveillance and inservice test results review; condition report and licensee event report investigation and review; preventive maintenance reviews; design change participation; and involvement in industry and plant experience reviews.
Maintenance and work order related functions of the group were reviewed along with the team's inspection of maintenance activities as discussed in Section 2.2 of this report. There were no unacceptable findings related to the NSSS Systems Engineering Group's support of maintenance.
Similarly, functions of the group related to surveillance and inservice testing were reviewed as part of the inspection discussed in Section 2.3 of this report. Two examples of reviews involving questionable or unsatisfactory valve testing data are discussed in section 2.3 and attributed to the Technical Department.
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The team interviewed NSSS Engineering Group supervisors and staff engineers, and reviewed recently completed and ongoing handling of plant problems, condition reports, licensee event reports, and experience reports.
In most cases, the implementation of the required functions was found to be adequate.
The group had issued "Plant Engineering Guidelines" as departmental desk-top instructions for the administration of key activities, such as technical reviews alid equ'ipment performance assessment. The group appeared to be generally rigorous in their approach to their functions.
For example, rev'aw of records for the problem of the slow opening stroke of the main steam isola-tion valve (MSIV) that occurred during the inspection and prior problems with MSIV air-actuated solenoid valves indicated generally good techniques, including maintenance of investigation journals, use of internal and external vendor resoarces and assignment of priorities.
Interviews with plant opera-tions personnel indicated a generally high level of confidence and reliance on the group's personnel. The inspection team also conducted a sampling of licensee management reviews of operating experience reports, condition reports, licensee event reports and related investigations.
Licensing and compliance engineers and systems engineers were interviewed, reports were reviewed, and methods were evaluated.
in general, the System Engineering Group appeared to be well-founded and generally well-administered.
Routine activities appeared to be handled satisfactorily. The Group had good credi-bility with the plant operating staff, and the personnel were experienced.
The Systems Engineering Group appeared to have matured quickly, and it provided a positive contribution to the organization.
One problem, which involved apparent intra-system leakage and caused over-heating, steam binding, and a water hammer in the piping of the residual heat removal (RHR) system's shutdown cooling loop, was followed by the team through-out the inspection. The licensee's handling of this problem was considered weak.
In this case, the team found the group's approach less than rigorous, especially in comparison with the handling of other recent, similar activities.
The problem was initially identified on about March 10-11, when damaged RHR piping supports were found.
The team began review of the licensee response to the problem on March 15 and requested that the licensee present plans for resolving the probitm at the earliest opportunity. Also on March 15 a systems-19-
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engineer issued a memorandum to the operations departmer,t recomending interim measures to periodically flush and cool the piping and to collect data for additional evaluation.
Data collection and licensee internal discussions continued through about March 17-18 when Nuclear Engineering Department (NED)
assistance was requested by PPTD. Additional details of these activities are discussed in Section 2.1 of this report. Although the systems engineers provided more formalized flush and cooldown data collection instructions on about March 18, the licensee did not appear to have developed either a detailed plan for continued investigation or a plan for corrective action by March 21-22.
On March 21, a team member observed venting of condensate transfer piping connected to the RHR system in an apparent attempt to identify the source of high-temperature leakage. The systems engineer in charge in the RHR "B" room was directing plant operators in venting portions of the systems. Two venting evolutions occurred.
During the first venting from the condensate transfer system, loud water hamer noises were heard and were mistakenly thought to be
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l coming directly from the piping being vented. After several minutes of consideration, the systems engineer directed the second venting to begin.
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About five minutes after venting began, another loud water hamer was heard i'
that eventually was localized in reactor water cleanup (RWCU) and condensate l
transfer comon piping. During the venting, piping high temperatures taken with hand-held instruments and steam vented from the system drain valve were i
unexpected and were initially discounted by licensee personnel. The licensee
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subsequently id5htified another suspected intra-system leakage path from the high-temperature portion of the RWCU system and the conder. sate transfer comon piping. The team member observed that the licensee personnel on the scene did not appear to have clear objectives for the evolution, did not have a procedure at the work scene, did not rigoroucly evaluate the anomalous vent flow and
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temperatures observed, and continued the evolution without further review or management consultation after obtaining initially unexpected results.
As a result of the above observations and the apparent lack of an overall licensee responso plan for the problem, the inspection team requested a meeting with the Technical Department staff on March 23 to obtain additional infoma-tion. During this meeting, the team expressed concerns regarding the apparent lack of urgency in developing a corrective action plan, the informality cf observed activities to date, the lack of infcrmation available to the team, and the licensee's evaluation of potential safety significance of the problems.
The Technical C1partment staff advised that their recomendations had been referred to the Nuclear Engineering Departa nt for evaluation and approval during the week of March 14 and a response was er.pected that day. The team was presented a one-page investigation plan outline transcribed from the cognizant manager's office blackboard. This plan involved removal of insulation from the affected piping to increase heat losses to the environment and thereby minimize the frequency and extent of the required system cooldown flushes. The plan did not address detailed diagnosis or eventual repair of the leakage paths.
Review of the lead engineer's and systems engineer's problem files revealed historical review documents and working notes but little evidence of a p e-planned approach that would lead to a comprehensive corrective action. Addi-tionally, the NSSS Engineering Group's resources seemed somewhat strained by the several high-priority workloads occurring during the period; this workload included this inspection, problems with MSIV C slow opening stroke times, and a-20-
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leaking high-pressure core spray (HPCS) pump seal. The team considered this workload so be unusual but not extraordinary and was concerned with the group's inability to absorb such workloads with currently assigned resources. Although the overall site staffing was similar to that of comparable single unit sites, the assignment and alignment of resources for in-process problem support may-warrant licensee reevaluation.
Another problem was evident in the licensee's application of procedural controit to this problem.
As previously mentioned, on March 15 the Systems Engineer issued a memorandum listing various general actions to be taken to periodically vent and flush the RHR piping to redece temperatures and avoid water hammer on routine and emergency RHR system initiation. These memorandum instruc'; ions were expected to be superseded within a day by a new tempor6ry instruction (TXI). The Operations Department, however, issued the memorandum to the control room as part of the daily instructions (night ordes)
of March 15-16 and rubsequently used the general guidance of the memorandum to begin i-hour duration flushes ot' the RHR system on a once-per-shift basis.
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This flushing was accomplished by applying temporary instruction TXI-50,
"Reduction of E12 (RHR) Pressure to Compensate for Backleakage" Revision 0.
As written, TXI-50 provided "...the directions for reducing excess pressure in the RHR System..." and included directions for momentarily venting the system to reduce excess pressure down to normal keep-fill system pressures of 40-100 psig.
In the circumstances discussed above, excess pressure was not the primary problem but rather progressive heating of the RHR loops to above saturation temperature. The TXI-50 flow paths were used to establish a flush from the alternate keep-fill source, condensate transfer, rather than the nonnal RHR waterleg pumps as specified by TXI-50, to the suppression pool.
The team reviewed the flow paths and methods used by the licensee and found them to be acceptable but was concerned that a staff memorandum and daily instructions were used, in effect, to revise an approved operating instruction without benefit of the normally required reviews and approvals appropriate to a procedure-intent change. This matter was discussed with the Senior Operations Coordinator and the staff, noting that the practice appeared to be an isolated case but could provide the potential for operational evolutions without proper technical review and management authorization. Subsequently, on March 18, 1988, the licensee issued TXI-54, "Monitoring and Review of RHR Loop A and B High Point Temperatures for Potential Steam Voids," Revision 0, which substan-tially revised and formalized the guidance initially issued in the memorandum.
2.4.3 Independent Safety Engineerina Group (ISEG)
Technical Specification 6.2.3 provided for the composition and functions of the ISEG, including examination of specific subjects "which may indicate areas for improving unit safety." The ISEG was further required to make detailed recommendations for such improvements. These requirements were amplified by USAR Section 13.4.3.
The Group's charter and operating procedures were provided by NEDP 0201, "lSEG Conduct of Operations," Revision 2.
The ISEG was chaired by the General Supervising Engineer, for Reliability and Design Assurance,.and had a full-time supervisor reporting to the chairman.
Five full-time membars were degreed engineers who met the composition require-ments for the Group.
ISEG supervisor and member qualifications and training records were reviewed and found to be acceptable.
The Group functioned in-21-
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three principal roles. Ten to 12 major "projects" were selected for examina-tions annually, using a management screening and approval mechanism. Addi-tionally, one member of the group was assigned on a monthly basis to perform surveillance of cperating and maintenance activities.
These two activities resulted in a series of project reports that described the activities and made formal recommendations. The third activity was a less-well-documented review of individual "current events" and industry awareness material that came to the attention of the Group but did not warrant the status of a "project." Examples included procedure and experience report reviews done by a subcomittee of the Nuclear Safety Review Comittee (NSRC), participation in response development for NRC, INPO, and the owners group, and other operating experience input reviews.
The team reviewed the ISEG project listing (1985-88), project and surveillance reports and detailed recomendations. The project reports generally indicated a rigorous review process and included valid recomendations.
The team noted that major projects during 1987-88 averaged about'two per ISEG member per year, not including the operations surveillances. The overall volume of output
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and correspondent safety impact appeared to be low compared with ISEG output at other comparable facilities.
Also, the ISEG apparently continued development of findings beyond initial problem identification to the preparation of recom-mended solutions, although these solutions were frequently a broad spectrum of recomended actions (see below). Group effectiveness could possibly be improved by changes in project selection strategy and the level of resource investment in a_ single project. Such changes might result in more timely evaluation of more issues. Timeliness cf ISEG reports and findings is further discussed below.
In contrast to the more rigorous individual project reports, the operations surveillance reports tended to be more a narration of the month's operational and maintenance related activities and events than an "independant verification that these activities were performed correctly," as required by Technical Specification 6.2.3.3 and USAR Section 13.4.3.
Only 12 recomendations (findings) were issued during 1987 as a result of these surveillances. Of those issued, only five had been issued at the time of thi:; inspection.
Discussions with ISEG management and interviews with ISEG member engineers indicated that the reports may not have been representative of the actual verification and reconmendation efforts. The licensee advised the team that potential recommendations and findings that were routinely addressed and closed during a given month were not typically discussed in the reports.
The team noted that the ISEG operational surveillances were similar in scope to those being performed by the QA Department but did not appear to have the rigor and critical approach of the QA surveillances. The licensee stated that the reports did not accurately represent the rigor of the verifications performed and that the format would be evaluated for improvement. The t.o.s further noted, however, that the surveillances appeared to be accomplished without benefit of a preplanned checklist, except for a general guidance listing informally issued by the ISEG Supervisor.
It was not clear that the intent of the Technical Specifications was being fulfilled by this activity, and this was considered a weakness by the team.
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At the time of this inspection, four of eight "project reports" for 1987 had not been issued. This lack of timeliness was also observed to have affected the impact and response to the Group's recommendations. Most of the 1987 issued recomendations remained open awaiting response or action from the receiving departments. The team also noted that through 1986 into 1987, ISEG's findings tended to be more programatic than technical and frequently broad in
scope; for example, Project Report 86-008, "Plant Electrical Operating Practices," made eight broad recomendations for major procedure and design changes and reevaluation of operating practices. Six of the eight recomenda-tions remained open at the time of this inspection.
Interview results indicated that this approach resulted in low priorities being assigned by responding organizations because of the resources needed to respond being directed to more contemporary and manageable tasks.
The open recomendations were tracked on the station-wide computerized Commit-ment Tracking System; they were not treated "y the licensee as firm action
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commitments, but rather as nonbinding recommendations. The poor reporting timeliness and open recomendations had been identified as problems in the
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"lSEG 1987 Annual Report" to senior licensee management. Although the ISEG management had identified corrective actions, such as detailed report scheduling and recommendation followup to improve performance, no material improvement had occurred, and the ISEG Chairman and Supervisor were considering other possible remedies. The team considered the above circumstances to be significant detfactions from the Group's effectiveness.
One of the ISEG minimuin performance requirements specified by NEDP 0201, Section 1.2, was ISEG evalution of the effectiveness of the operational Quality Assurance Program, independent of normal functions of the Quality Assurance Department. This was construed by ISEG management to mean QA program activi-ties intrinsic to the other activities being examined by ISEG. The team agreed with this interpretation and believed that review of QA activities concurrent with other technical subject reviews was a worthwhile and workable apprc3ch.
The projects undertaken and surveillances conducted, however, with one excep-tion, reflected essentially no consideration of QA activity evaluation.
Although a number of the ISEG findiogr involved QA program concepts, such as document control, corrective action programs, and administrative procedures, these findings were almost ne'ver presented in a manner that related the find-ings or recommendations in a QA context.
Similarly, no evidence was found to indicate that a methodical approach to QA concepts was considered in project planning and implementation. One project report did concentrate on spare parts procurement and material control aspects.' Several ISEG collateral duties, such as procedure reviews, opalating experience report reviews, and initiation and
review of condition reports, represented partial fulfillment of the requirement but were not consistently documented. This aspect of the charter procedure was
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also not clearly evident in the Group's strategic project planning. The ISEG Chairman and Supervisor acknowledged this evaluation and stated that fulfill-ment of this function vculd be reevaluated and adjusted as necessary.
The ISEG was participating in the interdepartmental task force for establishment of a site-wide failure and root cause analysis process. The team found that ISEG was using various analysis methods on a trial basis for ongoing reports.
The team reviewed draft project report "Root Cause Analysis of CR 88-020 Using Events ano Conditions Charting Method " dated March 22, 1988. This report-23-
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evaluated problems with frazil ice fouling laxe water intakes in January 1988 and was a commendable first effort in applying systematic failure analysis methods. The inspection team considers this to be a positive indicator of the licensee's intent to improve problem analysis methods, 2.4.4 Plant Operations Review Comittee (PORC)
The team evaluated review activities of the Plant Operations Review Comittee (PORC) through inspection of procedures and meeting minutes, discussions with PORC members, and attendance at a scheduled meeting. The PORC activities observed exhibited several strengths that make the comittee effective in reviewing plant procedures, modifications, and operations.
PAP-0103, "Plant Operations Review Comittee," Revision 3, provided a description of PORC membership, responsibili. ties. authority, conduct of activi-ties, review subjects, and reporting requirements, and provided the charter for
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the PORC. The delineated responsibilities, memberships, and quorum require-ments in PAP-0103 were consistent with Technical Specification 6.5.
PORC member 2 are designated in Technical Specification 6.5.1.2 by organiza-tional title. The licensee did not permit a member or alternate to vote or count toward a quorum unless the member had been qualified through completion
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of a comprehensive reading and study program. The inspector reviewed the training program status for all current members and alternates. The training program included approximately 205 procedures and documents, along with all current temporary procedure changes. Completion of the program was closely tracked. Once initial qualification was complete, the individual received a periodic printout showing those procedures and documents in the original program that had been revised.
In this way, each member was made aware of the current issue of each of the applicable governing documents. At the time of this inspection, three designated PORC members were still undergoing qualifica-tion. At the time of this inspection, 5 of the 21 qualified members and alternates had training status records showing incomplete review items over one month old. The oldest item had an effective date of June 1, 1987.
In response to the inspector's question, the PORC chairman stated that no policy or guide-line had been established for disqualifying members from voting when update training became delinquent.
Technical Specification 6.5.1.5.f requires that PORC review all violations of Technical Specifications. The team selected two sources of violation reports to confirm that PORC had reviewed a sample of such items identified in calendar year 1987. The first of these sources were three violations identified in NRC Inspection Reports 50-440/87-04 and 87-12. Since NRC inspection reports were not routinely sent to PORC for review, these violations were not addressed in the context of Technical Specification violations. The team confimed, however, that the violations were in fact reviewed as Licensee Event Reports (LER) 87-11, 87-17, and 87-48.
Another source of violation reports was the licensee's Condition F:e et Systea, described in PAP-06t,6, "Condition Reports and Imediate Notificaticas,"
Revision 5.
This ? stem was selected for review because it should include those violations that may not have resulted in an LER, such as violations of Technical Specifications Section 6, "Administrative Controls." Condition reports documented and provided for the investigation, notification, and-24-
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reporting of potentially reportable event;. The condition report also provided for reporting abnorral plant conditions or events that required further action and review by plant staff.
The criteria for initiation of a condition report were found in PAP-0606; they spec *f tally included Technical Specification violations. During the evaluatio
~ view process, the compliance ennineer
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was required to screen all conditi %
e s foe PORC review. This scrcening was designed to ensure that, among otn, i' is of interest, Technical Specifications violations, particularly action 6, were sent to PORC for review.
The team selected 12 condition reports which documented missed surveillance tuts to confirm review by PORC.
In no case hid the condition rciport been forwarded to PORC for review. The licer.see stated that a missed surseillance test did not constitute a violation unless the associated "Limiting Condition for Operation and Action Statement" were not met. While this approach was consistent with Technical Specification 3.0.2, it denied PORC an opportunity to evaluate the frequency and causes of missed surveillance tests. The evaluation
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that resolved each of the 12 condition reports reviewed concluded that no Technical Specification violation had occurred.
The team member involved attend d scheduled PORC meeting 88-039, held on March 17,1988. Attendance was ample to meet quorum requirements, and nearly all material for consideration had been distributed to PORC members and alternates earlier in the meek. Licensee practice has been to require that review material be available for distributicn to members 'on the Manday preceding the scheduled weekly meetings on Thursday. Only one nonscheduled item was addressed as a walk-in at the meeting observed by the team member. The team member found that PORC members were inquisitive, and good interchanges occurred at the meeting. Agenda items were reviewed in advance of the meeting, with the result that minimal briefing time was necessary by the item sponsor. PORC activities were a strength but could be improved by addressing the potential for missed reviews discussed above.
2.4.5 Nuclear Safety Review Comittee (NSRC),
Activities of the Nuclear Safety Review Conittee were evaluated through review of the charter and meeting minutes, discussions with personnel, and attendance at a scheduled meeting of the full comittee. The NSRC Charter, Revision 4, dated January 14, 1987 provided overall guidance for functions of the Committee. The Charter was supplemented by five guidelines, titled as follows:
001 Administrative 002 Operations and Maintenance Subcommittee 003 Radiological Environmental and Chemistry Subcomitcee 004 Audit and QA Subcomittee 005 Engineering Subcomittee The purpose statement of Guideline 001 stated that the Guideline w e not a nandatory requirement. Guideline 001 was, however, thc only :'ocumer.: that stated the Technical Specification 6.5.2 requirements for NSRC member-25-
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qualifications, quorum, and meeting frequency. Taken in the aggregate, the Charter and Guideline 001 conformed to Technical Specifications 6.5.2 require-ments covering NSRC activities and membership. Although the Guideline 001 procedures w2re stated to be optional, the team found that NSRC operated in accordance with them.
Guidelines 002 through 005 described the activities of the four standing NSRC subcomi ttees. The majority of the NSRC review effort was accomplished in the subcomittees, which met bimonthly during the intervening period between the bimor.thly full comittee meetings.
Each subcomittee reported to the full NSRC at meeting No. 45 held on March 16, 1988. An inspection team member attendeo this meeting.
At meeting No. a5, there were informative presentations, good discussion, and active intercha.ge among the members. Agenda item material was distributed to members in advance to allow prior review before decisions were made at the
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meeting. One apparent exception to this early review process was that a revised version of a Technical Specification amendment request had not been distributed to all members.
lo confirm conformance with Technical Specification requirements, the team verified member cualifications, audits and the review process used to ensure that necessary items received NSRC review. Based on a qualification matrix prepared By the-licensee, some level of expertise in each of the areas listed in Technical Specification 6.5.2.2 was evident among the members. With respect tc auait areas in Technical Specification 6.5.2.8, the inspector reviewed an audit and QA Subcomittee report dated March 7,1988. Attachmeni 3 to that report listed QA audits completed during 1987. The reports were listed under NSRC audit areas consistent with taose in Technical Specification 6.5.2.8.
The NSRC participated in audits at one of three levels: Category A were NSRC-led audits, Category B were QA audits with NSRC participation, and Category C were QA audits reviewed by NSRC. All required audit areas were covered and tracked by the subcomittee.
The inspection team reviewed NRC inspection reports, PORC minutes, condition reports, safety evaluations, and LERs. All NRC inspection reports and LERs were routinely routed to all NSRC members.
In addition, Guideline 002 required that the 0,nerations and Maintenance Subcomittee review NRC inspection reports and LERs, as well as PORC minutes and safety evaluations. Those items selected for review were evaluated in detail and documented in the subcomittee report
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to the full NSRC. The team noted, however that no evident mechanism had been
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established to ensure that all PORC minutes, LERs, and safety valuations were provided to the subcomittee for review.
Condition reports were reviewed by the Engineering Subcomittee; however, only closed condition reports, were reviewed. This practice created the possibility that particularly difficult problems might not come to the attention of NSRC.
An additional concern in this area was the lack of a mechanism to ensure that all closed condition reports were submitted to the Engineering Subcomittee for review, in general, NSRC conducted detailed and informative reviews. While no examples were found of failures to evaluate an LER, a Technical Specification violation, a r.et of PORC minutes, or a safety evaluation, the practices employed by NSRC-26-
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and its subcommittees provided the potential for missed items and should be reviewed for adequacy.
2.5 09311ty Programs The team conducted a review and assessment of the licensee's Quality Assurance and Quality Control program and organization.
Included in this review and assessment were the conduct and reporting of audits and surveillances, inspec-tions of quality-related activities associated with work orders and repetitive tasks, qualification of auditors and inspectors, and the trends emerging from followup on quality organization findings.
In addition, the team reviewed the licensee's corrective action program for overall effectiveness, 2.5.1 Quality Assurance (QA)/ Quality Control (QC) Involvement Findings The quality organization included an operational section, a procurement and
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administration section, and a maintenance and modifications section. Each section reported to the Nuclear Quality Assurance Department (NQAD) manager who reported to the Vice President, Nuclear.
2.5.1.1 Quality Auaits and Surveillar,ces The opera,tional section was, in part, responsible for auditing administrative, operations, and technical support activities for implementation and adequacy, reviewing plant operations manuals, procedures, and instructions, as well as conducting surveillances of plant operations activities and providing support for plant-related maintenance and modification activities.
2.5.1.1.1 QA Audits The team reviewed the 1988/1989 audit schedule that had been issued to plant management on December 9, 1987. This schedule, which was reviewed by the NSPC QA Subcommittee, was required to include all audits specified by section 6.5 of the Perr,v Technical Specifications, FSAR, connitments, and the QA plan. The team.rev1ewed the audits required by the Technical Specifications and found that they were included in the a dit schedule. A comparison with the audits specified in Table 18-1 of the N plan, however, revealed several discrepancies between the plan and the audit scnedule. When this inconsistency was brougl.t to the licensee's attention, the team was given a QA plan change request form that was initiated on November 10, 1987.
The change request form was approved during the OSTI inspection. This change brought the audit schedule into compliance with the QA plan. The change request was also found to comply with the audit frequencies identified in NRC Regulatory Guide 1.33 which endorses ANSI N18.7.
From a list of the previously conducted audits, the team selected and reviewed five audit packages. The team verified, through discussions with applicable QA personnel and review of the audit packages, that the audits covered appro-priate areas, were sufficiently technical in nature, and resulted in meaningful findings that were adequately reported.
The team noted that deficiencies were identified as action requests and followup occurred as prescribed in the QA manuai. A review of selected action requests indicated that management was making adequate disposition of action requests received from the QA audit teams.
In addition to action requests, the audit reports often made
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l recomendations that were not specifically related to deficiencies. Tht. team found these r= commendations to be a valuaole management tool that could result in improved programatic performance. A review of management followup on a samr4 of these recomendations revealed that management usually addressed then recommendations; however there was no formal program in place to ensure that they were being addressed. A recent change in the way recomendations are addressed should result in significant improvements in this area, since plant management is now requested to respond in writing to each recomendation.
During the team's review of audit report PIO 87-25 "Technical Specifications,"
the team identified an item addressed in section IV.4.e of the audit report that was not adequately pursued by the auditors. This item concerned the lack of response time testing of an affected circuit or component when the component was replaced in a circuit that requi:ed periodic response time testing by Technical Specifications. The auditors noted the item but dismissed it based on looking at the results of several response time tests completed
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recently with no evidence of test failures because of faulty components. The auditors were interviewed and asked to identify the specific work order (s),they reviewed that resulted in the identification of this specific concern.
The work order that 3s produced was for a component (relay) that was not related specifically to a circuit that required response time testing. With lack of a specific example, the team interviewed the instrument and control (I&C)
enginsering supervisor and was infonned that circuitry or component response time testing would not automatically be required if a component was replaced with a like-for-like component in a circuit that required response time testing. The I&C enginee-ing supervisor stated that relays, or other compo-nents with vendor certifications that identify the components as having very short response times, would have little or no effect on overall circuit response times.
In these cases, the supervisor stated that a functional test may be all that wnuld be required to consider the component and associated circuit operational.
The team infonned the licensee that to rely solely on vendor certifications for the response time attribute of a component associated with a circuit requiring response time testing was nonconservative and represented a weakness in the post-maintenance testing program. For example, NRC inspection report 440/86012 identified a relay in the neutron tronitoring system that did not meet the actuation time specified in its vendor certification.
Subsequently,1.he t,STI team was informed that the licensee was develoning a program for bench-testing Agastat relays (EGP type), if they were to be used to replace relays in a Technical Specification response time loop, to ensure that the relays operated within the vendor specified response time.
In a i
memorandum from the Acting Manager of the 1&C Section to Perry Licensing, dated
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March 24, 1938, it was stated that a procedure will be developed for delineating how and when these relays would be tested.
Audit Report PIO 87-Ic "Effectiveness of Corrective Action." was reviewed by the team and was found to be particularly outstanding in both its depth of review and the significance of its findings.
The corrective actions taken by management to resolve the findings identified in this audit report are discussed in section 2.5.2 of this report.
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The team's review of the qualifications of selected auditors indicated that the auditors were well-qualified and, in all cases, exceed he regulatory and plant requirements for the positions held.
In addition, technical specialists and outside consultants were used during selected audits to enhance the technical k'owledge of the audit team when the need was identified.
n 2.5.1.1.2 QA Surveillances The team reviewed the log of completed QA surveillances and selected a sample of five surveillances fo* detailed review.
In addition, the team reviewed the January 1988 and February 1988 surveillance schedules.
From these reviews and discusmns with applicable QA personnel, the team verified that selected surveillances covered appropriate areas, were sufficiently technical, and resulted in meaningful findings that were generally adequately reported.
The team was informed that many of the surveillances were based on unscheduled reviews of plant functions resulting ' rom QA inspectors' reviews of condition
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reports, plant logs, other deficiency-related logs, tours, and other plant activities. This policy had been recently implemented to encourage perfonnance-related surveillances that allow inspectors to utilize more of their investiga-tive skills in identifying plant deficiencies.
From review of the celected surveillance reports the team concluded that this policy of_ unscheduled reviews appeared to have resu}ted in the performance of effective surveillances.
The team's review of the qualifications of selected surveillance inspectors indicated that the inspectors were well-qualified. The team was informed that several inspectors received plant systems training, which was viewed by the team as an enhancement to the surveillance training program.
2.5.1.2 Quality Control and Engineering The maintenance and modification quality section was in part responsible for the review of work orders, assignment of QC hold-and-witness points, development of unique inspection plans (when' deemed necessary), performance of field inspections, and review of final completed work packages.
The team reviewed the January, February and March 1988 OC work order sumary
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sheets, selected OC inspection reports, and selected work orders.
From these reviews, the team concluded that an adequqte level of QC hold-and-witness points was being identified and that QC rejections when necessary of in-process work resulted in the generation of detailed QC inspection reports and the performance of reinspections.
Final review of completed work packages also appeared to be thorough in that many minor deficiencies were being identified and the work packages'were being sent back to the responsible organizations for correction.
The team was concerned, however, that the apparently large final work package review rejection rate indicated that the maintenance and planning organization was depending on the quality organization to find work package deficiencies, rather than perfoming their own detailed final review. When this concern was discussed with the licensee's CC management, the team was informed that actions were being taken by both the QC and the maintenance organization to improve the quality of the work packages. QC organization actions included providing a-29-
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list of identified deficiencies to the maintenance manager, conducting meetings with maintenance management to discuss ways to improve completed work packages, and developing a lower tier document to identify and resolve future deficien-cies. The team met with the maintenance manager and was provided an informal plan that was developed to improve the quality of the maintenance organiza-
. tion's work packages. This plan included additional maintenance personnel training and improving material requisition control and final work package reviews prior to sending the completed packages to the quality engineering group.
The team's review of the qualifications of selected quality control and engineer inspectors indicated that the inspectors were well-qualified. The team also interviewed several inspectors and determined that the inspectors were knowledgeable of their duties, had high morale, and had no significant quality control concerns.
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2.5.1.3 Sumary
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In general, the team found the licensee's QA/QC organization t o be a signifi-cant licensee strength. Findings identified by this organiza: ion have and should continue to be a valuable management tool to ensure plant compliance with procedures, Technical Specifications, and other safety and regulatory requiremeats, and to provide. management with identified deficiencies and useful recomendations for plant equipment, personnel and procedural improvements.
Improvements are currently being made to enable the QA/QC organiz'ation to better comunicate identified problems to plant management and staff. These improvements include:
the use of a "split form" that identifies audit recom-mandations and allows applicable management to comunicate with and respond to the auditors concerning these recomendations prior to the audit exit; conduct of preexit meetings with lower level plant supervisors to provide these super-visors with a sumary of the auditors' findings and the opportunity to exchange views and pertinent information concerning the findings; and providing mainte-nance management with specific information concerning work packages -that are being rejected because of missing or incomplete :nformation. The team encouraged plant management to continue to take steps to improve the comunica-tion channels established with the QA/QC organization to take full advantage of the valuable information provided by this independent group.
2.5.2 Corrective Actica Program Corrective action programs were inspected to determine whether there was a comprehensive and effective means to identify, track, and correct problems. The team reviewed several audit reports that covered the corrective action program, the condition report program, and the licensee's program for detecting emerging trends in conoition reports, LERs, and work orders.
2.5.2.1 Audits of the Corrective Action Program The licensee was in the process of upgrading its corrective action program in response to audit report 87-12. "Effectiveness of Corrective Actions," a maintenance self assessment, an INP0 visit, and other reviews.
The reviews.
identified areas that needed improvement, including investigation techniques, troubleshooting techniques, content and retrievability of information contained-30-
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in the plant maintenance information tracking system (PPMIS), and the use of tn: :quipment historical data.
During a NRC Region III maintenance team inspection, 'nspection Report No. 50-440/87025, the maintenance team asked the licensee to provide a presentation on its response to the areas identified above. A copy of this presentation was provided to the OSTI team for review, and from the review the team concluded that the licensee was progressing toward
. improvements; however, che OSTI team did not conduct a detailed review of the steps taken by the lit nsee.
The QA audit group was in the process of completing a new audit on effective-ness of corrective actions, and the inspection team asked the audit team leader to brief the team on the results of this audit. He reported that the new audit concentrated on the condition report program and identified, among other things, weaknesses in the way operations personnel interpreted events that should require condition reports. Several examples of plant events were identified in which the auditors felt that a condition report was warranted but not initiated. The auditors were in the process of comunicating these
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findings to the Operations Department at the time of this inspection.
2.5.2.2 Condition Report Program The team obtained a listing of all condition reports issued in 1988 and selected 13 of 78 for review.
From a cursory review of these reports, the team concludef that The licensee's disposition and followup actions appeared to be adequate. During reviews of operations logs the team was sensitive to the audit team's finding concerning operations personnel not always initiating condition reports when required, but identified only one event during the team's two-week inspection that was not properly reported as a condition report when required. This event is discussed in paragraph 2.1.2 of this report.
2.5.2.3 Trending Program The team reviewed the licensee's 1987 Annual Trend Reports, dated March 11, 1988. These reports included annual trends indicated by 1.ERs and condition reports and summarized the licensee's quarterly trend reports on the same subjects.
From the review of the annual trend reports the team concluded that the licensee was adequately categorizincj LERs and condition reports and performing detailed evaluations to detect emerging trends.
Recomendations identified in these reports appeared to reflect in-death analyses of the events and provided useful suggestions for programmatic and hardware modifications to help prevent recurrence of similar events.
The team also reviewed the licensee's work order trending program. This program was developed in part to resolve a QA audit finding concerning the requirement to perform trend analysis for work orders (audit PIO 86-48).
This trerding was accomplished by the reliability and design assurance section (R&DAS). R&DAS reviewed all completed safety-related work orders via the PPMIS computer.
Specific information was then transferred manually to the reliability information. tracking system (RITS) computer, which had the capa-bility to sort work crders by part numbers or vendors. R&DAS used these data to identify recurring failures of specific components and equipment supplied by specific vendors. The time spent manually transferring applicable data from the PPMIS to the RITS has, however, prevented.the staff from performing many detailed analyses of selected components to determine adequacy of periodic-31-
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maintenance, design enhancements, or other corrective actions to reduce component problems. Equipment failure information was, however, provided to plant maintenance and engineering personnel for review. To alleviate the resource burden, the licensee was modifying the PPMIS computer software to access data and perform the task the RITS was performing without manual manipulation of the data. Other computer enhancements were being considered that should further improve R&DAS' ability to identify recurring equipment problems.
The team concluded that, when fully implemented, the work package trend evalua-tion program should provide a valuable indicator of recurring equipment problems. With the implementation of the enhanced systems, R&DAS' resources could be directed towards analyzing data and making significant recommendations for plant improvements.
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2.5.2.4 Summary
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From the limited review of the licensee's corrective action program, the team concluded that programs are generally in place to identify, track, and correct problems.
Problems identified by the licensee's own staff indicate that improvements were needed, and plans for improvement were being implemented.
The full implementation of these improvements, counled with the plant's recent movement from startup to full commercial operation, should result in improve-ments in plant performance and matei al condition.
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3.0 Exit Meeting l
. The OSTI team and other NRC representatives met with licensee personnel to
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discuss the scope and findings of the inspection on March 25, 1988. Attendees (
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at the exit meeting are identified in Attachment A.
During the inspection, the team also contacted members of the licensee's staff not identified in Attachment A to discuss issues and ongoing activities.
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s ATTACHMENT A ATTENDANCE SHEET EXIT MEETING - March 25, 1988 NAME ORGAhiZATION TITLE _
J. E. Cumins NRC/DRIS Team Leader C. J. Haughney NRC/DRIS Chief, Special Inspection Branch L. J. Norrholm 9C/DRIS Asst.TeamLeader(SectionChief)
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J. W. McCormick-Barger NRC/RI OSTI Team Member
P. I. Castleman NRC/DRIS
'0STI Team Member
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D. R. Beckman NRC Consultant OSTI Team Member R. W. Cooper, II NRC/RIII Section Chief K. A. Connaughton NRC/RIII Perry SRI G. F. O'Dgyer NRC/RIII Perry RI
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D. P. Igyarto CEI Acting Manager, Instrumentation and Controls Section
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R. J. Tadych CEI Training Manager B. K. Grime's NRC/DRIS Deputy Director, DRIS/NRR S. C. Guthrie NRC/ Rill SRI, Big Rock Point, OSTI Yeam Member L. R. Miller NRC BWR Instructor, Reactor Technology, OSTI Team Member J. M. Sharkey NRC/DRIS OSTI Team Member R. Stratman CEI Acting Gen. Mgr., Perry Plant S. Tulk CEI Supervisor,QA W. Coleman CEI Manager,0QS G. A. Dunn CEI Supervisor, Compliance
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T. E. Mahon CEI Manager, Site Protection
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J. J. Waldron CEI Principal Engineer, NSRC Chairman A. F. Silakoski CEI
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Manager, Reliability and Design Assurance /ISEG
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ATTACHMENT A
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ATTENDANCE SHEET EXIT MEETING - March 25, 1988 NAME ORGANIZATION TITLE A. P. Myer CEl-Supervisor, Independent Safety Engineering Group S. F. >'ensicki CEI Technical Superintendant W. R. Xanda CEI Manager, Operation H. N. Kelly CEI
' Senior Operations Coordinator
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E. Buzzeni CEI Manager, licensing & Compliance F. Stead CEI Director, Technical Dept.
A. Kaplan CEI Vice President, Nuclear C. M. Shuster _
CEI Director, Nuclear Eng. Dept.
V. K. Higaki CEI Manager, Outage Planning Sec.
D. J. Rossetti CEI Ops. Engr., Outage Planning Section (OSTI Interface)
H. Coon CEI SVI/ Computer Engineer T. Colburn NRC/NRR PD-33 Project Manager K. E. Perkins NRC/NRR PD-33 Project Director D. O. Myers HQAD/MMQS Sr. Ops. Program Consultant J. R. Hayes NQAD/00S Quality Engineer
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R. A. Newkirk PPTD/ Tech. ;
. Manager, Technical Section S. J. Wojton PPTD Manager, RAD Protection M. Cohen PP00/ Maintenance Manager, Maintenance M. D. Lyster CEI/PPOD General Manager P. D. Roberts PP00-Ops. Section Lead 3VI Coordinator T. A. P.emick PP1D-Technical Sec. Operations Engineer H. L. Hegrat PPTD-Licensing /
Operations Engineer Compliance
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e ATTACHMENT B LIST OF OBSERVATIONS 440/88200-01, Inadequate Logs, discussed in section 2.1.1 440/88200-02, Failure to Use Procedures, discussed in section 2.1.2
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- 440/88200-03, Lack of Supervising Operator Involvement in Shift Personnel Activities, discussed in section 2.1.3
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440/88200-04, Overtime Deviation, discussed in section 2.1.4
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GLOSSARY ALARA As low as reasonably achievable ANSI American National Standards Institute CFR Code of Federal Regulations FSAR Final Safety Analy:is Report gel General Electrical Instruction HPCS High-pressure' core spray I&C Instrumentation and Controls ISEG Independent Safety Engineering Group LC0 Limiting condition for operation LER Lir.ensee Event Report LPCI Low pressure coolant injection MATE Measuring and Test Equipment M0V Motor-operated valve M0 VATS Motor-operated valve analysis and testing system MSIV Main steam isolation valve NEOP Nuclear Engineering Department Procedure
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NIS Not in service NQAD Nuclear Quality Assurance Department NRC U.S. Nuclear Regulatory Commission NSRC Nuclear Safety Review Committee NSSS Nuclear steam supply system OSTI Operational Safety Team Inspection PAP Plant Administrative Procedure
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PNPP Perry Nuclear Plant Procedure POP Perry Operations Procedure PORC Plant Operations Review Committee PP0 Power Plant Operator PPMIS Perry plant maintenance information system QA/QC Quality assurance / quality control R&DAS Reliability and Design Assurance Section RCA Radiologically controlled area RHR Residual heat removal RITS Reliability _information Tracking System SO Supervising Operator SS Shift Supervisor
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SV1 Surveillance instructions TAP Technical Administrative Procedure TX1 Temporary Operating Instruction US Unit Supervisor USAR Updated Safety Analysis Report
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