IR 05000498/1988001
| ML20149F354 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 02/09/1988 |
| From: | Jaudon J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20149F344 | List: |
| References | |
| 50-498-88-01, 50-498-88-1, 50-499-88-01, 50-499-88-1, NUDOCS 8802170111 | |
| Download: ML20149F354 (40) | |
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i APPENDIX C
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U.S. NUCLtAR REGULATORY COMMISSION REGION IV .
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NRC Inspection Report: 50-498/88-01 Operating License: NPF-71 l
- 50-499/88-01 Construction Permit
- CP%-129
! Dockets: 50-498
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j 50-499 Licensee: Houston 1.ighting and Power Company (HL&P) ,
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4 P.O. Box 1700 i Houston, Texas 77001 . !
, 1 Facility Name: South Texas Project (STP), Units 1 and 2 Inspection At: STP, Matagorda County, Texas !
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Inspection Conducted: January 4-8, 1988 t
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Inspectors: J. R. Boardman, Reactor Inspector, RIV '
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, P. S. Brinkman, Senior Reactor Operations Engineer, NRR O. D. Chamberlain, Senior Resident Inspector, RIV .
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R. E. Farrell, Senior Resident Inspector, RIV
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R. C. Haag, Reactor Inspector, RIV W. D. Johnson, Senior Resident Inspector, RIV N. P. Xadambi, Project Manager,'NRR M. E. Murphy, Reactor Inspector, RIV
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G. A. Schwenk, Reactor Engineer, NRR I
- W. F. Smith, Senior Resident Inspector, RIV ;
S. R. Stein, Reactor Engineer, NRR J. E. Whittemore, License Examiner, RIV -
l l Accorupanying Personnel: J. P. Clausner, French AEC ,
l Approved: -
c:24/z M 21
/. P. pauden/I)eputy 0' rector, Division of Dat(t / I L Reactor Satety i i
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! Inspection Summary
j Inspection Cnnducted January 4-8,1988 (Report 50-498/83-01)
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] Areas Inspected: Special, announced inspection to assess operational i
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readiness. The areas assessed were operations, operations training, maintenance, surveillance, fire prevention and protection, and quality l assurance &nd management controls to assure quality, i
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Results: Five concerns were developed which appear to require resolution prior !
j to power escalated above 5 percent. These concerns are:
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j demenstration of the remote shutdown and cooldown capability, !
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i improved operator knowledge of plant status and control of mode changes,
f assurance that measures to identify and to implement technical !
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specification changes are effectiv [
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l clearance of the backlog of overdue station problem report investigations, i
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resolution of the question concerning the use of commercial agastat relays
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, There were also eight violations identified. These violations, the concerns
! listed above, and significant strengths are summarized in paragraph 2 of the
! repor ] Inspection Conducted January 4-8. 1988 (Report No. 50-499/88-01) t
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i Areas Inspected: None. All inspection activities were conducted on Unit 1.
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Results: Not applicabl !
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i j Attachments: !
- 1. List of Documents Reviewed l 2. List of Persons Contacted '-
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DETAILS
, Inspection Scope This inspection was to assess licensee readiness to operate abcte 5 percent power. The inspection was an assessment in selected functional area The areas selected were:
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operations trainin maintenance, '
surveillance,
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fire prevention and protecti >n. and
management controls to assurt qual' .
The emphasis in each area was to t Stornine the effectiveness of licensee program implementation. The inspection was a vertical probe of selected area A concurrent inspection was conducted in tiie area of physical securit/.
This is documented in NRC Inspection Reports 50-498/88-03 and
- 50-499/88-0 .
The list of documents reviewed and persons contacted are Attachments 1 and 2, respectively.
. Summary of Significant Findings .
The team identified four areas during the inspection which the team considered affected the licensee's ability to operate safely at power.
i Subsequent to the inspection, a fif th significant item was identifie The fifth item was the result of comparing inspection findings with NRC Information Notice 37-66. The inspection found several areas of licensee strength. The most noteworthy of these are delineated in paragraph The inspection team also identified eight violations and one unresolycd ite .1 Issues Identified ,
The following five issues were considered to require resolution prior to escalating powe . Remote Shutdown .
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A drill was conducted January 5, 1988. The drill scenario I I
i was a control room fire and evacuation, followed by a simulated remote shutdown. It was noted that the procedure for remote shutdown contained minor errors. It was also found that some operators, specifically nonlicensed l
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I operators, were not well trained in the procedure. For example, the procedure required that relays be "fingered" (i.e., operated manually). Several drill participants were not trained in the "fingering" technique. Additionally, it
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was noted that needed tools-(e.g., screwdrivers to open panels) were not staged. The NRC. inspection team concluded that the licensee'had not demonstrated the ability to conduct a remote shutdown and cooldown of the plant. This is a skill which all shifts should be able to demonstrate (paragraph 7). ,
2. Plant Statu_s
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Before the inspection, the licensee had documented a loss of plant status which occurred over a 52-hour period in October and November 1987. During this event, the licensee was in Mode 4 with all high head safety injection valves shut. This was contrary to Technical Specification During this inspection, it was found that the Mode 4 lineup procedure opened these valves, but placed controls for all three high head. pumps in a lockout condition. It was also
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found that the high head safety injection valves were all open, in Mode 5, which is contrary to Technical Specifications. When an NRC inspector asked control room operators on January 7, 1988, why the valves were open, the operators said that they did net kno The valves were subsequently shut. It was later determined that the valves in question had bet.n opened by the previous shift as part of a valve lineup made in anticipation of going to Mode 'he conclusion reached by the NRC inspection team was that 1
. there was a7 apparent weakness in operator knowledge of plant status and that the lineup and mode change procedures did not necessarily mesh corr m ly (paragraph 3). !
l 2. Technical Specification imp' e ation l Prior to the inspection, there hac' been an occurrence wherein a technical specification setpoint had been incorrectly implemented by the licensee. The apparent 3 cause was a failure to detect changes from draft technical
specifications, which were made when the technical specifications were issued with the low power license. The NRC inspection team found two additional items of this typ Both were in the area of core performance. It was concluded that the licensee's system for assuring that ,
technical specification changes were identified and !
implemented in procedures was act being effectively j implemented. This was considered significant because l technical specifications are normally reissued, with changes, when the full power license is issued l (paragraph 6). :
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2. Station Problem Reports The licensee's top tier program for identifying and correcting problems is the station problem report'syste The NRC inspection team found that 68 out of 204 station problem report investigations were overdue. The average length of time overdue was 40 days. It was concluded that this backlog of investigations was excessive and.that power escalation should not occur until identified problems were resolved (paragraph 8).
2. Agastat Relays
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It was found that the licensee had many commercial grade Agastat relays installed in safety-related application Th3se relays are of the "7000" and "F-7000" series. These are commercial relays and have a design life of 2 year' Since the manufacture dates for these relays were primarily in 1978 and 1979, it appeared that there were many relays *
installed which were beyond their design lif ,
2.2. Licensee Strengthe The NRC' inspection identified several areas of strength in licensee performance. The eight most noteworthy strengths are listed below:
2. Simulator Training A simulator training session was monitore The training session was well c.onducte The scudents rotated positions. The critique was good. The use of procedures was excellent. It was considered that the simulator training was an area of strength (paragraph 4).
2. Fire Brigade The fire brigade performance during the drill conducted January 5, 1988, was evaluated to be excellent. It was noted that this was a marked improvement over the last observed drill (paragraph 7).
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2. Spare Parts It was found that the licensee's program to identify spare parts was comprehensive. Additionally, spare parts l provisioning had been carried out aggressively (paragraph 5). -
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2. Preventive Maintenance The NRC inspection team found that the preventive maintenance program was comprehensive and thorough (paragraph 5).
2. Maintenance Work Instructions The maintenance work instructions reviewed, appeared to be well writte The level of detail and quality of instructions provided were excellent (paragraph 5).
2. Engineering Support -
Engineering support for maintenance was organized in two way The engineers reporting to the plant manager were assigned as cognizant engineers by systems. Engineering support at the corporate level was organized by disciplin , This appeared to provide excellent support to field activities (paragraph 5).
2. Surveillance Test Procedures Surveillance test procedures appeared to be well writte It was noted that they facilitated verbatim complianc It was concluded that these procedures were excellent considering that STP is a new plant (paragraph 6).
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2. Quality Assurance !
The coordination and communication between the surveillance and audit groups of quality assurance were found to be excellent (paragraph 8), i 3. Operations i
i Several aspects of plant operations were reviewed by the NRC inspectors in !
order to assess the readiness of the operations staff to operate the unit at power safely. Areas reviewed during this effort included operator performance in following procedures, procedure quality and revision i'
control, design change coordination, shift turnover, operating logs, '
ciearance practices, and temporary modification control. In addition, one safety system was selected for walkdown. Findings in these areas are discussed in the following paragraph ; Performance The NRC inspectors observed operator implementation of Procedure 1 POP 03-ZG-0001, "Plant Heat-Up," at various times during the inspection period. No performance problems were identified during these observations. As discussed in the training section of
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this report (paragraph 4), operators were observed in performing multiple normal and emergency operating procedures during simulator exercises. Operator performance during these exercises was very goo .2 Procedures NRC inspector review of the plant heatup procedure resulted in questions on whether this procedure contained appropriate steps to align the high head safety injection' pumps correctly in order to meet Technical Specification requirements for Mode 4. It was determined that Technical Specification 3.5.3 was in error in requiring two high head safety injection pumps to be operable in Mode 4. Licensee -
representatives stated that this Technical Specification had been previously discussed with the NRC Office of Nuclear Reactor Regulation. An interpretation had been provided, stating that one of the "operable" high head safety injection pumps would be in a standby mode with its breaker racked out. Licensee representatives agreed to
. . propose a revision to Technical Specification 3. This revision is to state clearly the Mode 4 operability requirements for high head safety injection pumps. Tht NRC inspectors identified one human factors problem in the plant heatup procedure. Step 6.4 of this procedure requires starting the desired reactor coolant pumps. A note following this step requires, under certain conditions, the
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forming of a pressurizer steam bubble prior to starting a reactor coolant pump. This note should be placed before the affected procedure ste The NRC inspectors reviewed portions of Procedure 1 POP 02-SI-0002,
"Safety Injection System Initial Lineup." Forms 3, 7, and 11 are provided for Mode 4 alignment of safety injection system Trains A, B, and C. The required position for the high head safety injection pump main control board handswitch on each of these forms was PTL (Pull to Lock). Following this procedure would make all three high head safety injection pumps inoperable in Mode 4. Since' Technical Specification 3.5.3 required one high head safety injection pump to I be operable in Mode 4, this procedure was inadequate to control the safety injection system alignment. This procedure inadequacy is an apparent violation of Technical Specification 6. (498/8801-01)
3.3 Design Change Coordination ).)
The NRC inspector. reviewed Procedure OPGP03-ZE-0031, "Design Change Implenentation After Turnover," and discussed it with plant engineering and operations support group personnel. This procedure requires that procedures affected by a design change be identified by ,
the cognizant system engineer. These procedures are. required to be l revised prior to returning the affected system to service. Although the operations support group has primary responsibility for writing and revising operating procedures, this group has not been integrated i into the design change proces The NRC inspectors concluded that
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additional coordination between plant engineering and the operations I support group is needed~to assure that procedures are revised as required to reflect design change .4 Shift Turnover '
The morning shift turnover was observed by the NRC inspectors on January 6, 1988. The turnover process was conducted in a very professional manner. The information exchange appeared to be quite complete. Each pair of licensed operators was observed to make a complete walkdown of the control boards. The briefing of the -
oncoming crew by the shift supervisor, the lead chemistry technician, the lead radiation protection technician, and the chemical operations -
foreman was considered to be beneficial. During the preceding shift, the Tecnnical Support Center diesel had been found to be running for no apparent reason The operators had secured the engine and ret'urned it to automatic. This event was recorded in the reactor operator's log, but it was not discussed much during the turnover .
process. No* followup action concerning the inadvertent engine start was apparen The shift turnover process was observed to comply with Procedure OPGP03-ZA-0063, "Plant Operations Shift Turnover." The briefing complied with Procedure OPGP03-ZA-0066, "NP0D Preshift Briefing." The NRC inspectors noted that the shift turnover procedure did not designate responsibility for completion of the Safety Function Check List. This form was completed by the reactor operato The NRC inspectors noted that the print on this form was small and difficult to read and that no supervisory approval was required for the system operability determinations. The inspection team understands that the licensee plans to review the form and handling of the Safety Function Check List for possible improvement .5 Logs A limited review of selected chronological and data logs indicated that they were accurate and concise. They contained sufficient detail and properly recorded plant events and condition .6 Clearances Licensee equipment clearance practices,were evaluated for compliance with Procedure 1PGP03-ZO-0001, "Equipment Clearance." The procedure was being formally executed. One licensed or nonlicensed operator '
was assigned as a clearance coordirator and was located at a clearance control desk in the back of the control room. This practice was considered to be beneficial for proper procedure performance and for reducing distractions to the operators monitoring the main control boards. The NRC inspector reviewed.the clearance book, including all unreleased clearances which had been placed in effect in 1987. The NRC inspector noted that there was no copy of the clearance procedure available at the clearance control des ___
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Licensee representatives stated that a copy of the clearanco procedure would be placed at the clearance control des One unreleased clearance (87-5994).could not be locate Licensee personnel later stated that the clearance was no longer in effect, but the release documentation was los Two clearance orders (87-5333 and 87-4724) installed tags as an administrative control on valves which could not be locked. Licensee representatives stated that an Engineering Support Request had beeri submitted to obtain a means of locking certain valves. These valves were required by procedures to be locked, but because of configuration problems, no means existed to lock them. The -
Engineering Support Request could not be located by the licensee during the inspection. A new Engineering Support Request on this subject was prepared on January 6, 198 The clearance order required the signature of the person who accepts
. the clearance. The procedure defined "accept" as an independent verification that the system status is acceptable for the work to be done. The list of designated acceptors at the clearance control desk contained the names of 1002 person",, who had received training on the clearance procedure. There were no requirements that designated
, "acceptors" possess any specific technical expertise or system knowledg The NRC inspectors expressed a concern that some designated "acceptors" might not have sufficient system knowledge and technical expertise to perform an adequate independent verification of the adequacy of a clearance boundar .7 Temporary Modification Control Temporary modifications were controlled by the licensee using Procedure OPGP03-ZO-0003, "Temporary Modifications and Alterations."
The NRC inspector reviewed this procedure ano did not identify any concerns with its completeness or adequacy. The procedure did appear to have an internal conflict concerning whether or not blank or blind flanges were considered to be temporary modifications (Procedure Sections 1.1.f and 1.4). A licensee representative stated that this procedure would be revised to clarify this are The NRC inspector reviewed a sample of outstanding temporary modifications. Each had been appropriately evaluated and properly approved. The NRC inspector found that the temporary modification program was, in general, being administered in accordance with the procedure. However, two exceptions were identified. One nonsafety-related temporary modification (TI-WL-87-190) was still in place on January 5, 1988, but its approval had expired on December 18, 1987. The second exception was that Section 4.7 of the -
procedure requires the system engineer to cloud with red ink the affected area of the control room copy of key drawings affected by a i temporary modification. The engineer is also required to reference l
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10 s the temporary modification on the drawing, attach a copy of the temporary modification request to the drawing, and note which drawings were updated on the original temporary modification reques The NRC inspector found that none of these requirements had been' met for one safety-related temporary modification (TI-EW-87-252). This temporary modification installed a blind flange in place of a flow element in the essential cooling water system on November 25, 198 This failure to follow procedural requirements is an apparent violation of Technical Specification 6. (498/8801-02)
3.8 Safety System Walkdown .
The Train C high head and low head safety injection systems were ,
selected for walkdown by the NRC inspectors. Assistance in locating system components was provided by a licensee operator. He was very helpful and quite familiar with the systems. Major ' system flowpath valves, key instrument isolation valves, a sample of vent and drain valves, power ,upply breakers, and control room handswitches were inspected for proper positioning. Procedure 1 POP 02-SI-0002, "Safety Injection System Initial Lineup," was used during tha walkdow Forms 9 and 10 of this procedure provided the required lineup for .
Modes 5 and 6. This procedure requires Valver SI-0059C, SI-0224C, and SI-0070C to be locked closed. The NRC inspectors found that SI-0059C was not locked and that the locking devices (cable and padlock) on the other two ter 'landle valves could be removed by han The licensee's failure to adequately lock these three valves as required by procedure is an apparent violation of Technical Specification 6. (498/8801-03)
3.9 Control Room Observations On January 7, 1988, the NRC inspector observed that the three high head safety injection cold leg injection isolation valves (SI-MOV-0006A, -B, and -C) were ope Since the unit was in Mode 5 and the system lineup procedure required these three valves to be closed in Modes 5 and 6, the unit supervisor was asked about the apparent discrepanc A short tire later the unit supervisor had the reactor operator shut the three valve It was later determined that the valves had been opened by performance of a valve position
surveillance checklist (1 PSP 03-SI-0014) early on January 7, 198 The unit supervisor did not know that this surveillance had been performed during the previous shift in preparation for entering Mode .10 Conclusions The NRC inspectors evaluated the operators' safety sensitivity and awareness of safety system status. The general conclusion wa's that the operators exhibited a sound training background and a mature, professional attitude toward plant operations, and operational safety. They demonstrated a cautious and conservative approach to
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.. s 11 plant operations.' However, it was also concluded that in order to better support the operators the following areas should be reviewed for possible improvemen A better system is needed to highlight safety system status in order to assure that operators maintain an awareness of safety system statu Performance of procedure steps, out-of-sequence, should be better controlled and documente .
The mesh and flow of various system operating, system lineup, surveillance, and plant operating procedures should be assure .
This area was considered potentially confusing during mode change f An example indicating need for improvement in these areas was the confusion on the required position of the three high head safety injection cold leg injection v'alves resulting in their repositioning after a question from the NRC inspecto '
The surveillance procedure which was used to reposition the valves on the previous shift was performed well before the sequence indicated in the plant heatup procedure. Its performance had not been documented in that procedur *
There was nothing readily available to the unit supervisor to indicate that these valves had been placed in their Mode 4 alignment in preparation for entering Mode Resolution of the problem of operator awareness of plant status and verification that licensee procedures are adequate to con. trol conditions through mode changes, should be completed prior to power escalatio . Operations Training A limited scope review of training was conducted by the NRC inspector This included simulator training observation and evaluation of the licensee's methods of feeding back operational information to operator .1 Simulator Trainino The NRC inspectors observed a simulator requalification training session. During the session a licensed operating crew was subjected to complicated events and plant system malfunctions. The crew was evaluated both on individual and team performance by the licensee's simulator training staff. The event scenarios.were sufficiently complicated to cause entry into and exit from normal, abnormal, and emergency operating procedures. Scenarios were at a level of complexity to force simultaneous use of multiple procedures.
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Individual operator duty assignments were rotated for the different
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scenarios. This forced each operator to use procedures in both the operator and supervisory role After each scenario, the training staff conducted a detailed critique of operator performance. Good as well as deficient actions and practices were pointed out and discusse Techniques of team interactions, communications, and coordination were continually emphasized. There was a free exchange of information between the operators and the instructors during the critique The simulator training session observed was considered to be excellent in all respect Through discussions with training department personnel, the NRC inspectors learned that very few written critiques of classroom or simulator training are obtained from the students. It was
, recommended that student critiques on instructor performance and course content be solicited. This mechanism cculd lead to further improvements in the training progra y 4.2 Feedback of Operational Inf'ormation The licensee provides feedback of operating experience to operators through required reading files and requalification trainin Required reading files are maintained for the on-shift crews by the operations support group and for the crews in training by the nuclear training departmen The requalification training program has at least one D hour session per cycle devoted to feedback of operating information and lessons learned. Formal inputs to this session come from Station Problem Reports, the Review of Operating Experience Program, and the Technical Advisory Council. Station Problem Reports are reviewed by training department personnel for inclusion of lessons learned into the requalification training program. Training action assignments l l
may also result from the plant review and evaluation of Station l Problem Reports. This mechanism may not be fully effective or timely i because of the delays being experienced in Station Problem Report , .- )
evaluation (paragraph 8). -
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The Review of Operating Experienca Program (Procedure PGP03-ZB-0004)
was not reviewed in detail during this inspection. This program provides for evaluation of industry operating experience and may result'in inputs to the requalification training progra .
l The Technical Adviso'ry Council (Procedure IP 8.1) was not reviewed in detail during this inspectio Licensee representatives stated that this group provides training program oversight and approves training I
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program conten The group meets we.ekly and may provide input to the requalification training progra The NRC inspectors noted that much of the input to the requalification training program from plant staff such as operations and the operations support group is provided informally through phone calls. There did not appear to be a proceduralized method for providing quick feedback to the requalification training program from these group .0 Maintenance The objective of this part of the inspection was to determine if -
raaintenance was being managed effectivel .1 Licensee Method for Controlling and Documenting Maintenance The licensee's Maintenance Work Request (K4R) Program is described in Station Procedure OPGP03-ZM-0003, Revision 15, January 4, 1988,
"Maintenance Work Request Program." The program, covers reporting and correcting material deficiencies at the STP plant. Additional instructions for implementing the MWR Program are contained in Maintenance Support Standing Order 5, Revision 1, dated December 7, 1987, and in the "Post-Maintenance Testing Reference Manual,"
Revision 2. Maintenance Support Standing Order 5 provides guidance to the maintenance planners for developing MWR work instruction The "Post-Maintenance Testing Reference Manual" provides guidance to the maintenance planners for specifying the necessary Post-Maintenance Testing (PMT) requirements. These documents were reviewed by the NRC inspecto Work instructions are prepared by a maintenance planner and are reviewed by a Quality Assurance (QA) representative prior to initiation of the work. The QA review ensures that proper Quality Control (QC) hold points have been incorporated before the work begin The work instructions are required to contain provisions for the craftmen and QC inspectors te signify their completion and acceptance of the wor Following completion of the work, the KdR is to be reviewed and approved by the responsible Maintenance Foreman, Maintenance Support Section, Ooerations Department, QA, and the Cognizant System Engineer. The NRC inspection team concluded that
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this program should provide good instructions and controls (including post work reviews) for performing maintenance activities at the ST The NRC inspection team reviewed a representative sample of 16 completed KdRs (6 for mechanical maintenance, 5 for electrical maintenance, and 5 for I&C maintenance). The purpose of the review
'was to assess licensee implementation of the program. This review showed that the KdRs generally had been accurately filled out in accordance with the licensee's procedures and that the work instructions were in sufficient detail for a journeyman craftsman to
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perform the work. The work instructions had been completed by the craftsmen and QC personnel with no apparent error During the review of these MWRs, it was noted that MWR RA87031341 had been issued to adjust the limit switches on Valve BIRAMOV0003 (a containment isolation valve). The MWR work instructions included requirements to perform PMT. The PMT requirements specified for this valve were stroke testing and isolation time testing. Both of these tests, which have technical specification requirements, had.oeen performe Both the licensee's Post-Maintenance Testing Reference Manual (Revision 2) and 10 CFR 50.54(o) require performance of a Local Leak Rate Test (LLRT) af ter valve maintenance of this type before entering Mode 4. The MWR work instructions did not require ,
performance of an LLRT, nor was any other evidence available that an LLRT had been performe After the identification by the NRC inspection team of this failure to specify and perform the required LLRT, the. licensee reviewed the maintenance history for three functionally identical valves. This review showed that the limit switches on two of these three valves
. had not been adjusted, but ihat the limit switches on the fourth valve (81RAMOV0006) had been adjuste This review also showed that .
specified PMT for the fourth valve failed to include requirements for an LLRT. Tne failure to conduct required local leak rate testing after maintenance is an apparent violation (498/8801-04).
5. Assessment of Licensee Alternate Systems for Maintenance Work The NRC inspection team reviewed the licensee's Shop Work Order (SWO) system described in Station Procedure OPGP03-ZM-0010, Revision 1, October 18~ 1985,
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"Maintenance Shop Work Order." The SWO system is used to request work that can be performed in the Maintenance Shop Areas, such as fabrication of special tools, storage containers, shipping containers. The SWO system is not ;
intended to be used to request maintenance work for ;
safety-related plant structures, systems, components *, or i for temporary facilities. An MWR is required for such l items. Station Procedure 0PGP03-ZM-0003, Revision 15, January 4, 1988, "Maintenah.pe Work Request Program,"
assigns Maintenance Department personnel the responsibility for satisfactorily performing work in accordance with approved written instructions using proper quality part )
Licensee representatives expressed their position that l these controls are adequate to ensure that the SWO system '
will not be used to perform unauthorized work on safety-related plant equipmen The team reviewed the Shop Work Order Status Lo The Status Log showed that no SW0s had been issued for
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electrical or I&C maintenance since the facility operating license had been issued; however, several SW0s for mechanical maintenance had been issued since issuance of the operating license. Several of the SW0s for mechanical maintenance were reviewed, but no abuses of the system were identifie Based upon experience with similar systems at other licensed nuclear power facilit,ies, the NRC inspection team concluded that the SWO systee could result in its being used to perform unauthorized safety-related maintenance at STP. This concern was identified to the license .2 Corrective Maintenance and Preventive Maintenance -
The NRC inspection team reviewed licensee procedures and other management control documents and data for corrective maintenanc As corrective maintenance activities have increased in volume, the
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licensee's maintenance manpower budget was increased proportionately in 1987. The maintenance manpower budget for 1988 appears tc be adequat.e and includes additional manning growth, if require Outstanding identified individual maintenance activities were budgeted for required manpower; the total outstanding activities -
equaled 1 month's total maintenance manning budget. This was considered to be an acceptable and controllable backlog. A review of an Equipment Out-of-Commission Log dated January 5,1988, did not reflect safety significant backlog problem Maintenance procedures reviewed appeared acceptable except for a possible problem with incorporation and documentation of revision control of vendor technical information (VTI) with 3 of the 5 maintenar.ce procedures for Limiterque valve operators reviewe The anomalies in VTI had no hardware implication The NRC inspection team also reviewed licensee program and procedures relating to preventive maintenance (PM). PM procedures appear to be well identified and scheduled. A detailed review was performed for PMs related to Stan6by Diesel Generator No.11. The overall PM program appeared to be very comprehensive'for a plant as new as STP- '
5. Preventive Maintenance Referrals The NRC inspection team noted that for 1987, appreximately 25 percent of the scheduled PMs had been deferred. The NRC inspection team reviewed the licensee's program for approving PM deferrals. The PM deferral program requires that proposed deferrals be reviewed by the Cognizant Sy' stem Engineer, and that the Cognizant Section Supervisor erarove such deferrals. The Maintenance Manager is required to approve all proposed PM deferrals for quality related item The system for reviewing and approving proposed
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. 16 deferrals appears to be a good program which provided adequate control Since the NRC inspection team was concerned that the PM deferral rate (25 percent) might be excessive, a sample of completed deferral forms was reviewed to determine the reasons for the deferral In this review of the completed deferral forms, the team noted that several of these forms contained only minimal reasons for the deferral, lipon further investigation, the team determined that the deferrals were justifie Therefore, the team concluded that the PM deferral system was not being abused. The team did conclude that the forms for approving future deferrals ,
should contain additional information justifying the basis for the proposed deferra .3 Control of Spare Parts to Support Maintenance The STP-1 spare parts programs appeared to be very comprehensiv The program included recommendations made by equipment manufacturers, and it contained data from other sources. Implementation of the complete program will requira several years, but priority of implementation ha's been given the safety-related spare parts. Funded procurement for 1988 appeared to support program implementatio .
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The NRC inspector reviewed the computer data printout, "Spare Parts Report for Status 34 and Status 44," dated January 7,1988. This report identified all maintenance activities held-up or impacted because of unavailable material. .This report indicated that the lack of material had no safety-significance at the time of revi Approved manning for the STP-1 Nuclear Purchasing and Materials Management Organization appeared adequate to support the spare parts progra A review of the STP-1 Master Parts List Tracking Chart dated i January 1,1988, covering program performance from October 1,1987, !
through January 1, 1988, was reviewed. Performance was slightly ahead of schedule on December 1, 1987, but behind schedule requirements on January 1, 1988. This drop in performance apparently resulted from the holiday season, and the concurrent reduction in i approved overtime. Increased manning is being implemented to compensate for reduction in overtim Schedule recovery appeared possibl The STP-1 Spare / Master Parts List program appeared to be operating j well at the time of the inspectio l l
5.4 Engineering Support of Maintenance It was found that plant engineering directly interfaced with maintenanc Support (project) engineering also supported ,
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maintenance in areas relating to design assure that the correct vendor technical information (VTI) was available to support maintenance activitie Support engineering is structured by engineering discipline, while plant engineering is organized by plant systems. This latter concept emphasizes the plant specific function of system components. The NRC inspectors concluded that such an emphasis can provide an assurance that analysis of component problems includes plant specific system operational consideration This emphasis can be overlooked in discipline oriented plant engineering organizations, where compliance with codes and standards tend to dominate engineering analysi It was found that plant system's engineers reviewed maintenance procedures (with included data sheets) as part of the approval cycle and after accomplishment of maintenance activitie The inspection team concluded that the engineering support of maintenance supported power operation of STP- .5 Control of System Boundaries and PMT
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The NRC inspection team reviewed the licensee's system for specifying control of equipment clearances and the need for performing PMT on .
MWR It was found that Section IV of the MWR form included a column for the maintenance planners to designate "No" or "Yes" if equipment clearance is required. The MWR form also contained a blank adjacent to this column for recording the number of the clearance tag if an equipment clearance is required. A review of the work instructions on MWRs requiring equipment clearances.showed that the work instructions contained a line item specifying the required equipment clearanc Section V of the MWR form included a column for the maintenance planners to designate "No" or "Yes" if PMT is required as well as a designation as to where the PMT requirements are include The licensee had provided written guidance for planners in determining PMT requirements. The apparent violation delineated in paragraph 5.1 indicates that some planners may require training in j the use of this guidance. It was noted that an audit of maintenance ,
conducted before licensing had identified similar failures to conduct
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appropriate PM .6 Specific Maintenance Concerns l
5. Agastat Relay i During the review of the maintenance program, the NRC team reviewed replacement of commercial grade Agastat Series 7000 relays used in safety-related application ;
This review identified 23 installed relays, from five
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suppliers, which were apparently commercial grade. These reiays had been "dedicated" by the suppliers. Site documentation did not indicate that Agastat had certified the relays' diaphagm material. Diaphagm material app;rently had been assumed by the suppliers, who qualified the relays based on these assumption Upon return to Region IV offices, the NRC inspection team reviewed NRC Information Notice 87-66, which states that commercial grade Agastat 7000 series relays have a
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projected qualified life of 2 years. All safety-related installed series 7000 commercial Agastat relays at STP-1 are older than 2 year It was also noted that there were 17 "F-7000" series Agastat relays at STP-1. These are not addressed specifically in NRC Information Notice 87-66'. These relays are installed in safety-related applications and they also have a 2 year design life; but their manufacture dates were in 1978 and 197 This will remain an unresolved item (498/8801-09) until it is determined if the installed 7000 and F-7000 series Agastat relays are acceptable in their installed applicatio .
5.7 Manacement Involvement in Maintenance The NRC inspector noted that Station Procedure OPGP03-ZO-0007, Revision 3, June 8., 1987, "Conduct of Maintenance" required that the Maintenance Manager / Technical Support Manager perform, on a routine basis, random plant and facility inspections. This procedure also required that the results and observations of these inspections and tours be documented and reviewed for action. These inspections and tours were intended to include irregular hours (e.g. , weekends and backshifts). The maintenance manager stated that he had established informal goals for himself, the division managers, and the technical supervisors, for making tours in the power block and performing such inspections. Although the Maintenance Manager had only minimal records demonstrating the performance of these inspections and tours, the NRC inspection team concluded that this oversight program was beneficia .8 Conclusions on Maintenance The NRC inspection team concluded that the licensee's maintenance program and performance, to-date, supported operation at power, '
subject to satisfactory resolution of the question on agastat relay *
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6.0 Survefilance The objective of this inspection was to assess the licensee's Technical Specification Surveillance Program to ensure that the licensee has adequate controls in place and has satisfactorily implemented them to fulfill all of the surveillance requirements delineated by the Technical Specification .1 Surveillance prooram The inspection team reviewed the licensee's procedures which inplement the surveillance program to gain an understanding of how the system is supposed to be structured and what format to expect -
when reviewing specific surveillance test procedures. These procedures were OPGP03-ZE-0004 (program), OPGP03-ZA-0055 (scheduling), and OPGP03-ZE-0005 (test procedures). The full titles and revisions can be found in Atta'chment 1 of this inspection repor The NRC inspectors also referred to Procedure OPGP03-ZA-0002 (plant
. procedures), when referenced by the above procedures. This latter procedure is an upper tier document used for initiating, cancelling, reviewing, revising, and approving station and division safety-related procedures. Based upon the procedure review, the NRC inspectors found that the surveillance program was sufficiently defined and that the delineation of responsibilities was clearly stated. The requirements, though somewhat complex, were presented in an orderly manner and did not generate many questions by the NRC inspector Meetings were held with key surveillance program participants to verify that the program was imple'mented as required by the procedures delineated abov Briefly, the surveillance program is managed by the plant engineering manager; he in turn has appointed surveillance coordinators responsible for surveillances that come under engineering cognizance (i.e. , plant computer, reactor performance, ASME Section XI, and l system performance). In addition, a plant surveillance coordinator .
has been designated for overall implementation and maintenance of the l surveillance scheduling program. This individual ensures that all surveillance tests are assigned to a responsible division (e.g.,
Operations, Maintenance Mechanical, Electrical, Instrumentation and Control, Chemistry, etc.). The plant surveillance coordinator also assures the integrity of the surveillance data base, trains a l surveillance coordinator for each of the divisions, and maintains a !
close interface with these coordinators. The Plant Surveillance i Coordinator distributes periodic reports and specifies the implementation dates, frequency, and allotment time for each surveillance test. He is responsible for escalating surveillance implementation problems such as overdue surveillances to the appropriate managers; however, a high level of visibility and priority appears to prevail over surveillances at STP-1; accordingly, the coordinators interviewed indicated such action has seldom been necessary, i
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The surveillance coordinator for each division is provided with a list of assigned surveillances applicable to his area of cognizance, surveillance program updates, schedules, and test packages for surveillances with a periodicity greater than one week, and also'some weekly surveillances that can be scheduled on a routine basi Surveillances with a periodicity of a week or less are scheduled by the division surveillance coordinators themselves. Most of these appear in routine log .
Nonscheduled surveillances (conditional surveillances) are performed when plant conditions warrant, such as when changing plant operational modes. The licensae has a mode change form.available to the control room on demand from the computer. There is a separate - <
form for each mode chang The form lists each surveillance that must be completed or current prior to exceeding the plant operational mode change. Periodic survei.llances are also listed with the latest completion date and next due date. Conditional surveillances are listed with required conditions for procedure. performance and a .
signature block. A division representative, with signature authority for the division assigned the conditional surveillance, signs for each surveillance. There is a separate signature required for each .
conditional surveillance. The final signature block on the mode change form is for the Shif t Supervisor's signature. The Shift Supervisor . verifies that all periodic and conditional surveillances
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required for the impending mode change have been accomplished prior to changing modes. The team concluded that the Surveillance Program was implemented in accordance with plant procedures and appeared to be performing its intended function !
The inspection team determined that no routine formal quality checks are performed on the computer data base that is used to schedule surveillances. The NRC inspectors were concerned that personnel or <
electronic errors could be introduced into the program which may ;
contain commands (or the absence of commands) that could prevent a given surveillance requirement from being' flagged for performance at The licensee committed to perform these checks on a
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formal basis. Implementation of this action will be tracked as an open item (498/8801-10).
6.2 Conduct of Surveillance Tests The team selected the surveillance test procedures listed below based '
on a cross-discipline sampling. The sample was limited to tests that were scheduled during the inspection period. The full titles and
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revisions can be found in Attachment 1 of this inspection repor Procedure System IPSP02-FW-0541 (Feedwater Flow)
1 PSP 03-DG-0002 (SDG Operability)
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- 1 PSP 03-CV-0010 (Boration Flow)
1 PSP 02-FW-0511 (Feedwater Flow)
IPSP02-FW-0517 (SG NR Level)
IPSP02-MS-0534 (Steam Pressure)
- 1 PSP 06-DJ-0001 (1E Battery)
- 1 PSP 07-WL-0002 (Radiochemistry)
- 0 PSP 07-CR-0002 (Process Rad. Monitoring)
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OPSP07-VE-0002 (Unit Vent Rad. Monitoring)
- 1 PSP 06-DG-0005 (Dograded Undervoltage)
IPSP07-WL-0001 (Effluent Releases)
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The procedures above marked with an asterisk (*) were reviewed in detail, followed by witnessing the actual performance or walkdow Procedure 1 PSP 03-CV-0010 (Boration flow) was not actually performed, but was walked down so that the team could observe and evaluate a surveillance test performed by Operations Department. The procedures not marked with an asterisk were reviewed by the team, but their perforn.ance was not witnesse The team noted that the surveillance procedures reviewed were well written; they contained sufficient detail so that verbatim compliance
. could easily be achieved. The documents were written in compliance with the guidelines and requirements of Procedure OPGP03-ZE-0005 (test procedures) and had many user aids that helped the performer comply with all the administrative requirements involved. During the performa'nce it was evident that the performers were well trained to execute the surveillance tests, and there was an obvious sensitivity and discipline to comply verbatim with procedure If it became necessary to make a nonintent change to the procedures in a rapid manner, the licensee's Field Change Request (FCR) method delineated in Procedure OPGP03-ZA-0002 (plant procedures) was found to be simple, well controlled, and timely. Discussions with the licensee's representatives who utilize the system commented that such a change can be made in about 30 minutes, thus minimizing delays in finishing the surveillance and getting the affected equipment back in servic There were, however, a few rp'oblems identified as a result of procedure reviews and observance of testing. These are listed in the following subparagraphs:
6. Procedure OPGP03-ZE-0005 has a note in Section 3.2.5 which states that permission for test commencement may be obtained verbally or in writing, as specified in the te'st procedure. In practice, it appears that the surveillance test procedures require written (signature) concurrence to commence tests that involve equipment or system manipulation. The inspection team was concerned that
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verbal concurrence could lead to misunderstandings and eventual' loss of control over safety system statu Such a practice was not observed during this inspectio Also, during completed surveillance data package reviews (discussed in paragraph 6.3 below), the team noted several cases where the Unit Supervisor signed for the Shift Supervisor either to authorize the start of testing or to signify Operations Department's review of the test result Plant Operations Standing Order PRO-23, Revision 2, effective October 12, 1987, allows the Unit Supervisor to sign for the Shift Supervisor for a number o,f things, (e.g., maintenance work requests), but the order does not .
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address surveillance tests; This should be clarified. The issue of having consistent signoff requirements in the surveillance area was discussed with the licensee during the exit interview of January 8, 1988. The NRC staff will review the licensee's actio'n to clear this issue under open
item (498/8801-11).
6. Chemistry Procedure 1 PSP 07-WL-0001 requires saving a -
1 liter sample from each liquid waste discharge. The team noted during observation of IPSP07-WL-0002 that two of the samples saved in accordance with 1 PSP 07-WL-0001 were in 250 milliliter (ML) bottles. The chemist explained that they had run out of 1-liter bottle After some discussion with the Lead Chemistry Technician, the team concluded that 250 ML was en adequate s. ample and that the procedure was overly restrictiv However, the procedure should have been changed rather than disregarded. Failure to follow IPSP07-WC-0001 is the first example in this report of the licensee's failure to provide and/or to implement an adequate procedure controlling safety-related activities in accordance with Criterion V of Appendix B to 10 CFR 50 (Violation 499/8301-05).
6. During 4 review of Chemistry Procedures GPSP07-VE-0002 and OPSP07-CR-0002, the inspection team noted that the initial data reduction required calculating a sample volume, but that Procedure OPSP07-CR-0002 did not provide for calculating an average sample. During discussion with the licensee's representatives, the NRC inspector was told that the averaging calculation was performed routinely by the chemistry technicihns on verbal direction Failure of Procedure OPSP07-CR-0002 to provide for the necessary averaging calculation is the second example of the licensee's failure to provide and/or to implement an ~
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adequate procedure controlling safety-related activities in l accordance with Criterion V of Appendix B to 10 CFR 50 (Violation 498/8801-05).
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6.3 Review of Ccmoleted Surveillance Test Packages The team reviewed the below listed completed surveillances test packages for procedural compliance, technical specification compliance, and for adequacy of licensee reviews. The complete titles and revisions are listed in Attachment 1 of this inspection repor Procedure Performed IPSP02-RC-0463 .
01/05/88 1 PSP 02-RC-0430 12/31/87 1 PSP 02-RC-0474 01/05/88 -
1 PSP 02-FW-0537 01/04/88 1 PSP 02-RC-0464 01/04/88 1 PSP 02-RC-0454 01/04/88 1 PSP 02-RC-0461 01/04/88 IPSP02-RC-0462 . 01/04/88 1 PSP 02-SI-0931 01/02/88 1 PSP 02-MS-0515 01/02/88 1 PSP 02-NI-0043 12/31/87 .
IPSP02-SP-0002B 12/31/87 IPSP02-NI-0046 01/01/88 IPSP02-FW-0531 01/02/88 OPSPO4-XC-0001 10/27/87 The review of the above completed test packages did not reveal any l technical problems. The data sheets were complete and legible. The l
team's assessment of completed surveillance data reviews conducted by '
the licensee was satisfactory, however, two minor problems were i identified with respect to the implementation of Revisions and Field l Change Requests (FCRs) as discussed below: i 6. Procedures 1 PSP 02-RC-0454, -0461, and -0462 had been modified by FCR to allow the Unit Supervisor to waive Step 7.4.2 of each procedure when reactor coolant temperature is below 538 F. This step requires the performer to turn off the bistable monitoring pane Step 7.7.16 restores the panel These steps have signoffs on the data sheets which were neither modified nor i
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addressed by the FCR. Apparently, the entire series of 12 i procedures, 1 procedure for each channel of the RCS Temperature Loops, reflects the same problem. This FCR cauted confusion as to how to signoff the data sheet I Improper implementation of the FCR is the third example of failure to provide and/or to implement an adequate l procedurre controlling safety-related activities in -
accordance with Criterion V of Appendix B'to 10 CFR 50 (Violation 498/8801-05).
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6. ' Mechanical surveillance Procedure OPSP04-XC-0001 was performed on October 27, 1987, to the requirements of Revision 0 to the test procedure and FCR 87-2479. The FCR merely added several plant operational modes during which the procedure may be performed. The team's review of Revision 0 of the test procedure and the data sheet did.not identify any concerns with the conduct or results of the surveillance. However, a problem with the control-of revisions to the surveillance test procedures was identified during the teams review of subsequent revision .
An uncontrolled and unissued draft version of Revision 0 was used for incorporation of the minor changes of FCR 87-2479 into what apparently was thought to be approved .
Revision.0. Although this resulted in Revision 1 of OPSPO4-XC-0001 having conflicting requirements and referencing "nonexistent data sheets, it was not identified during the review and approval of the new revision. The
. procedure was subsequently revised to the current revision, Revision 2, with the errors still undetecte This is the fourt'n example of the licensee's failure to provide and/or a to implement an adequate procedure controlling safety-related activities in accordance with Criterion V of Appendix B to 10 CFR 50 (Violation 498/8801-05).
6.4 Assessment of Surveillance Backlog The team reviewed the surveillance Scheduling Procedure OPGP03-ZA-0055 and i.iterviewed the plant surveillance ,
coordinator to discuss the backlog of due and overdue surveillance The licensee publishes a daily list of surveillances which are coming due, are presently due, or are entering the "grace period" for completion. The "grace period" is defined as the time period between the surveillance due date and the point where a technical specification limiting condition for operation must be entered. This '
report receives wide distribution, including the Unit Superviso The team looked at the backlog of surveillances as of January 6, i 198 The list was not extensive and was comprised mainly of surveillances which would be done following a change in plant operational modes. The team concluded that the licensee was l
controlling the surveillance backlog adequately and that the backlog !
was manageable and not excessiv I
6.5 Assessment of Technical Specification Surveillance Coverage and Technical Adequacy of Surveillance Implementing Procedures The team randomly selected the technical specification surveillance requirements listed below and consulted the licensee.'s *
cross-reference list to determine what implementing procedures were written to cover each requirement. The team then retrieved each of the procedures identified in the cross-reference list to verify that the procedures, in fact, covered the surveillance requirement In i
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all cases reviewed, a procedure was found and i.t implemented the referenced technical specification surveillance requiremen The technical specification surveillance requirements selected were:
4.1.1. .1. .2. .1.1. .2. .2. .1. .2. .3. .1. .2. .3. .1. .2. . .1. .2. .5. .1. .2. .9. .
In order to ascertain the technical adequacy, accuracy, and quality of surveillance procedures 14 of the implementing procedures were selected from the above requirements at random. The exact titles of procedures reviewea appear in Attachment 1 of this report:
OPGP03-ZE-0004, Revision 6 OPGP03-ZA-0055, Revision 2 OPGP03-ZA-0007, Revision 10 OPGP03-ZE-0005, Revision 6 OPSP10-II-0003, Revision 1 OPSP10-II-0004, Revision 0 OPSP10-ZG-0001, Revision 0 OPSP10-ZG-0002, Revision 1 OPSP10-ZG-0003, Revision 3 OPSP10-ZG-0004, Revision 1 1 PSP 10-RC-0001, Revision 0 1 PSP 03-CV-0003, Revision 3 IPSP03-ZQ-0016, Revision 1 1 PSP 11-RH-0004, Revision 1 In general, the selected procedures were technically adequate. The team noted that they were well structured and user-friendly, as was the case with the procedures reviewed during the conduct of surveillance tests above (see paragraph 1.2). However, problems were identified in three of the procedures:
6. Procedure 1 PSP 11-RH-0004, Revision 0, was changed by ...
Revision 1 to incorporate new acceptance criteria. The n'ew values were revised on the data sheets, but not in the body of the procedure where the acceptance criteria are liste When the procedure was first performed, an FCR was implemented to delete the numeric values of the acceptance criteria from the body of the procedure to remove the conflict. At the time of this inspection, the procedure did not appear to have specific pass-fail criteria as required by Section 3.2.6 of Station Procedure OPGP03-ZE-000 This is the fifth example of failure to provide and/or to implement an adequate s
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6. Procedure 1 PSP 10-RC-0001, Revision 0, contained an acceptance criterion calling for a figure in the technical specifications which does not exis Apparently when the -
final technical specifications were issued, the figure was deleted. The licensee failed to reflect the deletion in the implementing procedure. The licensee's representative stated that this procedure will not be used until the second fuel cycle; however, no documentation or controls were presented to the NRC inspector providing assurance -
that this procedure will be amended prior to use. This is
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one example of the licensee's failure to conduct adequate technical reviews of the final technical specifications to ensure proper procedural implementation, resulting in a failure to establish an adequate procedure controlling safety related activities in accordance with Technical Specification 6.8.1.a is an apparent violation of NRC
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requirements (498/8801-06).
6. Procedure OPSP10-II-0003 was found to contain an incorrect equation for adjusting the core radial peaking factor limit for fractional power levels. This is the second example of I an inadequate technical review of changes that were made upon issuance of the final technical specification As a l result, the implementing procedure contained requirements that were less conservative than the technical i specification requirements. The licensee's failure to l establish an adequate procedure controlling safety-relate j activities in accordance with Technical 1 Specification 6.8.1.a is an apparent violation of NRC !
requirements (498/8801-06). !
6.6 Assessment of Licensee Dependance on Previous Preoperational Tests to Meet Current Surveillance Requirements The team studied a sampling of surveillance test review packages containing documented preoperational tests thaC had been used to satisfy specific technical specification surVei'llance requirement The packages had been assembled by the site organizations responsible for the surveillance tests and were reviewed and approved by plant l engineering and the plant operations review committee (PORC). The
, selection of packages reviewed by the team came from three maintenance divisions: mechanical, instrumentation and controls.,and i l
electrical. These surveillance test review packages-reportedly satisfied requirements of the following surveillance test procedure OPSP04-DG-0001 Standby Diesel Generator Inspection IPSP13-HC-0934 Response Time Test - Containment Pressure
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.1 PSP 13-HC-0935 Response Time Test - Containment Pressure 1 PSP 13-HC-0936 Response Time Test - Containment Pressure IPSP13-SF-0001 ESF Train A Response Time 1 PSP 13-SF-0002 ESF Train B Response Time .
1 PSP 13-SF-0003 ESF Train C Response Time IPSP06-NZ-0002 Low Voltage Breakers Functional Test IPSP06-NZ-0006 Molded Ca.se Breaker Inspection -
1 PSP 06-DJ-0005 125 Volt Class IE Battery 60 Month Performance Test IPSP06-DJ-0004 125 Volt Class 1E Battery Service Surveillance Test Some of these surveillance procedures had indicated test frequencies of 54, 60, or 72 months in the scheduling database. However, Technical Specification 4.3.2.2 requires the response time of each Engineered Safety Features Actuation Systems function to be demonstrated within limits every 18 months. Discussions with the licensee indicated that they were aware of this situation and needed to stagger the surveillance schedules of the long-term surveillance tests to meet the 18-month requirement of Technical Specification 4.3.2.2. Once this staggered scheduling is established in the surveillance scheduling database, the test procedures may be written for those tests that will be performed first. Since the procedures marked with an asterisk had not been issued yet, the team-compared the technical specification surveillance requirements with the data packages and concluded that the surveillance requirements were me During a later inspection, it will be necessary to follow up to verify that the remaining time response tests have been issued and scheduled in a timely manner. This is an open item (498/8801-12).
Two of the packages for OPSR04-DG-0001 were not sufficiently complete to determine that all theisu'.veillance r test requirements were satisfactorily met by preoperational testing. The surveillance test review packages, which had been reviewed and approved by plant l engineering and PORC for Emergency Diesel Generators 11 and 12, did l
not contain data sheets for crank shaft web deflection inspections i required by the surveillance test procedure. After the omissions were identified by the NRC inspector, additional copies of the da'ta l sheets were produced by the licensee that indicated the inspections had, in fact, been performed with acceptable results. However, the I
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approved incomplete review packages indicated that the licensee's technical reviews (e.g., PORC) were not completely effective. The team expressed concern to the licensee as to the thoroughness of PORC reviews and concluded that the mechanism of PORC activities should be evaluated to ensure that reviews are being conducted by individuals whose workload could detract from the quality of reviews. Also, Procedure OPGP03-ZE-0004, Section 4 5 2 requires a complete package to be forwarded to PORC for review when information other than surveillance test procedures are utilized to satisfy surveillance requirement It appeared that this requirement was not met. This is the sixth example of where the licensee failed to adequately implement procedures controlling safety-related activities in accordance with Criterion V of Appendix B to 10 CFR 50 -
(Violation 498/8801-05).
6.7 Review of Operator Proficiency T
While observing the performance of individuals conducting surveillances, the team noted the ability of the operators and technicians to perform the task In general, the performers
,* appeared to be sufficiently familiar with the equipment, and had obviously reviewed the procedures before attempting to start the surveillances. It was intmediately obvious that personnel at STP-1 have been indoctrinated in the philosophy of verbatim complianc This was demonstrated by their discipline to follow the procedures in a deliberate, step by step manner. Discussions between team members and the performers supported this observatio '
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One NRC inspector interviewed the Maintenance Department Training Coordinator to gain an insight as to the minimum training and experience levels held for personnel responsible for conducting maintenance and surveillance tests. In addition, training records for two individuals that had been observed conducting surveillance were reviewed. The experience and training of these individuals was more than adequate for the tasks performe HL&P placed a Maintenance Interim Qualification Program into effect on June 1, 1987. The program delineates the documented qualification requirements for individuals performing activities in the I&C,
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Electr,1, cal, Mechanical, and Metrology Division The program appeare,d to be intact and functioning satisfactorily. The licensee is currently working toward full INPO accreditation by the enu of
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198 .8 Quality Assurance and Independent Safety Engineering Group (ISEG)
Surveillance Observatics Activities
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The team reviewed 29 Quality Assurante Surveillance Reports which l documented observations made by QA of various discipline tecnnical l specification surveillance activities. Key attributes were' checked l
with objective and constructive result In general, the reports l
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were complimentary, however, there was documented evidence that the QA inspectors were critical of the activities and did not hesitate to identify deficiencies and suggestions for improvement. The team concluded that QA activities appeared to be adequate in this are The team also reviewed an Independent Safety Evaluation Group (ISEG)
observation of (&C Surveillances, dated September 28, 1987. The ISEG was also critical of the performance and came up with four conclusions which have generic implications worthy of consideration by plant managemen ,
The team did not have sufficient time to follow through and determine what actions were taken as a result o.f the QA Surveillances and ISEG -
review. This will be pursued during a later inspection and will be tracked as open. item (498/8801-13). ,
6.9 Conclusion The inspection team concluded that the conduct of surveillance activities supported operation at power. However, the concern about correctly identifying and implementing technical specification changes should be resolved prior to exceeding 5 percent powe . Fire Protection and Prevention The objectives in this area of the inspection were to observe the conduct of a backshift fire drill and verify fire brigade staffing and training currenc .1 Orill Scenario A fire drtil scenario was jointly developed by the NRC inspector and .
the licensee's lead engineer for fire protection. The scenario was to be initiated by a flash fire in the control roo The fire was to cause immediate evacuation and establishment of remote plant control for subsequent safe shutdown. This scenario provided for evacuation of the fire brigade capability, plant operator knowledge and procedure adequac . 7.2 Fire Drill Observation A fire drill was conducted on January 5, 1988. The fire brigade response was prompt; all members were properly equipped. The brigade leader conducted a rapid assessment, made proper use of the fire preplan, established availability of the proper suppression equipment, assigned, and briefed and dispatched the initial attack team. Subsequent to the fire being declared out, adequate smoke *
removal equipment was staged, a reflash watch was established, and area survey was conducte Fire brigade response was considered satisfactor * -
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7.3 Shutdown Drill The plant operators on shift were assigned specific duties by the licensee's Procedure 190P04-20-0001, "Control Room Evacuation." An NRC inspector was assigned to follow each operator as an observer during the dril '
7. Observations The following are specific observer. comments: ,
Shift Supervisor and Primary Plant Operator Auxiliary Shutdown Panel (ASP): -
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HVAC noise 1.evel was excessive and interferred with communication The auxiliary shutdown panel communications console had a high static noise level and interferred with communication *
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Operator was slow in establishing comi.mnications and did not use preferred method which is sound powered phones, until prompted by an licensee observe The operator was not familiar with the procedure,
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nor was he familiar with the location of all the panels holding equipment which he was required to operat The operator was not sure how to verify the position or actually r.osition some of the valves '
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The operator simulated operating the wrong fire dampe The operator was unaware of what function was initiated when he operated the fire camper switc The only training that the operator had received was the required reading of the procedur Remo'.e ope:ation of valves by manual manipulation of the control rslays called, "Fingering Relays,"
is required by the licensee's procedure. This -
operator bad never performed this action nor had
, he been trained in i * Unit Supervisor The operator was knowledgeable and understood the
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procedure; he promptly established '
communications, opened panels, and performed required actions by procedure as directed by the shift superviso .
7. Conclusions Concerning the Safe Shutdown Orill A general conclusion made by the observers was that the
'procedu,*e should provide more specific guidance to the operators and should be more prescriptive for interface ;
with procedures required to support or run in parallel with the control room evacuation procedur Tne inspection team also noted two specific errors in the procedur These .
were:
Addendum 3, page 42, Item 6, shows no action but ,
should show transfer to the AS * Addendum 1, page 6, transfer switch for FV-0012 was '
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i incorrec It was further concluded that training in this procedure had not included all personnel who would be required to '
l perform functions during a remote shutdown /cooldow .4 Conclusions and Concerns on Fire prevention and protection The NRC inspector reviewed the present fire brigade staffing and '
J determined that it was in accordance with licensee commitments and procedures. Training records were reviewed, and it was found that initial training and quarterly qualification training was being satisfactori,1y accomplishe The NRC inspector noted that the
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,,Ticenseehadno,tre,qufh'edpet+0dicwrittenexaminationsduringthe
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a qualification maintetaancs traiping. Instead, reliance had been placed on the drills afd hands-On practice sessions to assess the
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adequacy of the train'ing program. Since the fire drill observed by
the inspection steam was judgedyto'be satisfactory, there could be a
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, presumption that the classroom training was satisfactory. However,
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there were no records. sighted to' indicate that the licensee had used 4 s ' drill p6rformance to assess the h(fectiveness of cla,ssroom training,
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8.0 Quality Ast.orance and Management' Controls to Assure Quality
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ifnis area of' inspection included a review of the licensee's corrective
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. qqtion program, event repofting, gnAlity assurance audit program, and -
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Independent The results of ;
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~., - the review ,of,each Safety aicaEnnineering GroupT(ISEG).
are document,cd below: activitie *-
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1 . s 8,.1 Corrective Action '
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It was determined that the licent)$ uses several different inethods to
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.1. . identify, to document, and to tFack to completion nonconforming or
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These it.clude but may not be limited to:
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Quality Assurance Deficiency Rep 3rt (OR);
Nonconformance Report (NCR): *
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, is Station Problem Report (SPR); are
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.y Maintenance Work Request (MWR).
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Several departments also had their own internal systems to i( 'tify
, s nonconforming item Examples were the systems used to track .1e N. -
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following:
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Nnalth Physics; '
& ' %, Cheoi stry - i
,. Five Protection; and
Industrial Safety program m A reyjad cf these methods revealed that the DR, NCR, and SPR programs
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cor,tains) structured provisions for root cause analysis and action to prevent recurrence; these three programs also had a higher level of manageeint visibility than the other programs, which had limited
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i ss management visibility and less structured provisions for root cause
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analysi> or action to prevent recurrence. The NRC inspector
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-concluded that aggressive management oversight of these various l
- , corrective iction methods is needed to assure that problems receive l
adequate visibility and evaluatio This area will be monitored
. . du* int,'futuref NRC inspection ,
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8. Station Problem Reports ;
8.1. Timeliness of Action The Station Problem Report (SPR)' program an selected SPRs were reviewed in detail by'the NRC
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inspector. -In addition-to documenting corrective action determinations,.it was found that the' SPR i program was also used to determine NRC reportability.- It was no.ted that-the SPR program
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was identifying and documenting problems. Many of the problems: identified w'ere being-evaluate .
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- effectively in a timely. manne However, a number of potential problems and concerns were identified with the management of l the program. These included the fact that many j SPRs (64 of 204) are overdue for corrective ,
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action investigations. Interdepartmental '
Procedure IP 1.450 "Station Problem Report" requires final or preliminary corrective actions investigations within.17. days. Of the 68 SPRs .,
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overdue, the average overdue was 40 days; there i
were 33 SPRs overdue by greater than 30 days; 17 SPR investigations were overdue by more than $
60 day Examples of overdue 'SPRs are as follows:
N Title Days ;
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Overdue '
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j SPR 870362 MWR Work Derformed on 106
Incorrect Valve .
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SPR 870429 Jumper Installed During 62 i
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Test Not Remove'l
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SPR 870482 Some MOVs Have Internal 10 i -
Electrical Components
Which do not Meet EQ !
Requirements *
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SPR 870482 had such apparent significance that the inspection team followed up on it. It was .
j found that the MOVs in question were neither i
purchased to meet EQ requirements nor located in l l'
an area subject to a harsh environmen j
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investigations promptly, as required by procedure {
) to assure that conditions adverse to quality are ~
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'l corrected to preclude recurrence, w'as identified by the NRC inspector as an apparent violation of NRC requirements (498/8801-07).
8.1. Past Audit of SPR Program A quality. assurance audit deficiency report (DR 587-064) issued in August 1987 identified the
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same problem with overdue corrective action !
investiga'tions for SPRs. At that time, there '
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were 55 of 179 SPRs overdue with the average' '
being 3 weeks overdue. The corrective actions for this OR included issue of a new procedure and -
a transfer of program responsibility. With the >
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present status of overdue corrective action investigations for SPRs being 68 of 204 overdue, i it is apparent that the corrective actions for i DR 587-064 were not effective in precluding i recurrence of the problem. This failure to i
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assure that conditions adverse to quality are promptly corrected to preclude recurrence was :
identified by the NRC inspector as a second .
example of the above potential violation
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(498/8801-08).
8.1. Other Observations The NRC i.1spector noted that there appeared to be a wide difference in the quality of root cause analysis for SPRs. It was concluded that this might be indicative that training is needed for people that may be called upon for corrective action investigation The NRC inspector was provided with a draft revision to the SPR precedure. This draft was reviewed and it was noted that, while certain areas were strengthened, some provisions of the
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draft might tend to suppress problem identification. These provisions are:
Individuals no longer write SPRs. They must *
now explain the problem to their supervisor, and the supervisor will initiate the SPR if he deems it appropriat *
The criteria for SPRs is restricted to very significant p:*oblems or to problems for which ho other program exist .s .
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This concern was discussed with' licensee managemen The SPRs were not being trended by Nuclear Assurance as required by the SPR procedure. This was discussed with licensee Nuclear Assurance management, and it was noted that an earlier outside audit had identified the same proble The licensee is presently developing a trending program in response to this outside audi ,
8.2 Event Reporting
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This area of inspection included a review of Licensee Event Reports (LERs) and a review of operational logs for events not reported under 10 CFR Part 50.72 or 50.7 The licensee has issued 25 LERs since receiving a low power licensee at the end of August 198 Eleven of these LERs were reviewed by the NRC inspecto On the average, the LERs reviewed were timely and they effectively described the event. including determination of root causes and corrective actions. The only concern noted with LERs was that completion dates for corrective actions were not being identified in all cases. Licensee management stated that their intent was to include completion dates in LER The NRC inspector reviewed the unit supervisor / shift' supervisor logbook for November 1987. There were no conditions noted by the NRC inspector which appeared reportable that were not reported to the NR No '.olations or deviations were identified in this area of inspectio .3 Quality Assurance Audit Program This area of inspection included a review of the QA audit schedules for 1987 and 1988. The history of performance to schedule and status of open audit findings was also reviewed. It was noted that the QA department had been reorganized in November 1987 to place an emphasis on monitoring an operating plant. The QA organization staffing appeared to be adequate, with some dependence on technical specialists, to meet audit and surveillance goals. The 1987 audit schedule was essentially completed as scheduled. The 1988 audit schedule appears to be structured to monitor plant activities on a realistic time basis. An aggressive QA surteillance schedule is also planned for 1988 with over 300 QA surveillances scheduled. The QA audit and surveillance groups appear to complement each other with transfer of information and coordinated followup of findings. The status of open QA audit findings indicates effective management involvement with the responding to and closing of audit finding An ,
escalation process is also available to QA when neede '
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Two potential concerns were identified during this review.' The first appeared to have been a high threshold for issuing QA deficiency reports during prelicensing audits and surveillances of operations areas. Instances were noted wherein audit deficiencies were identified, but only the identified problems were corrected, and no further corrective actions had been required. A review of recent audit results indicates that the threshold for issuing audit findings has been lowere The licensee was encouraged to establish effective oversight of this area, and the NRC will monitor this area during future inspections. The second concern was that the monthly QA status reports are not detailed enough. Visibili.tylto the overall status of audit findings is not provided along with details on trends. This information would be useful for department managers and -
the Nuclear Safety Review Boar No violations or deviations were identified in this area of inspection, 8.4 Independent Safety Engineering Group (ISEG)
This area of inspection was conducted to assess the use and effectiveness of ISEG. ISEG has been functioning at South Texas Project since May 1987. The NRC inspector was provided a listing of 24 reports issued by ISEG in 1987. A review of this listing indicated a good mix of proactive and reactive ISEG activities. The ISEG director was also interviewed by the NRC inspector. ISEG is now requiring responses to all report recommendations. These responses are evaluated and the results are provided to the Nuclear Safety Review Board. ISEG is fully staffed and one individual is senior reactor operator qualified with strong operational experience. ISEG has a goal of 50 percent direct observation / evaluation of plant activitie It appears that ISEG has been effectively used during the early operations stage of this project, i
No violations or deviations were identified in this area of inspectio .5 Other Observations '
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It was noted that the licensee has established a system of ,
surveillances in the plant by senior members of management. These surveillances were being conducted both on the day shift and on backshifts and weekend .0 Exit Meeting An exit meeting was held January 9, 198 At this meeting, the inspection !
team presented a briefing on the secpe of the inspection and the finding The licensee did not indicate that any of the material discussed was proprietar I
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ATTACHMENT 1 '
DOCUMENTS REVIEWEQ Procedure Number Title Plant Procedures
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OPGP03-ZA-0002 OPGP03-ZA-0002 Plant Procedures OPGP03-ZA-0055 Plant Surveillance Scheduling OPGP03-ZE-0004 Plant Surveillance Program OPGP03-ZE-0005 Plant Procedure Preparation OPMP01-ZA-0036 Miintenance Department 0-J-T Program OPS 010-ZG-0001 Determination of Moderator Temperature Coefficient OPSPO4-DG-0001 Standby Diesel Generator Inspection (During Shutdown)
OPSPO4-XC-0001 Inspec_ tion of Containment Emergency Sumps -
OPSP07-CR-0002 Condenser Air Removal System Exhaust Particulate and Iodine Weekly Sampl6s
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OPSP07-VE-0002 Unit Vent Weekly Sample Analysis OPSP10-II-0003 Determination of Limiting Hot Channel Factors and Axial Offset OPSP10-II-0004 Determination of Quadrant Power Tilt Ratio Using Incore
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Instruments OP5P10-ZG-0002 Core Reactivity Balance OPSP10-ZG-0003 Shutdown Margin Verification Modes 3, 4, & 5 OPSP10-ZG-0004 Determination of Moderator Temperature Coefficient at Power
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IPOP04-ZO-0001 Control Room Evacuation IPSP02-MS-0515 Steam Pressure Loop 1 Set 2 ACOT (P-0515)
IPSP02-FW-0511 Fe'edwater Flow Loop 1 Set 2 ACOT (F-0511)
1 PSP 02-FW-0511 Feedwater Flow Loop 1 Set 2 ACOT (F-0511)
IPSP02-FW-0517 Narrow Range Level Set 4 ACOT (L-0517)
IPSP02-FW-0531 Feedwater Flow Loop 3 Set 2 ACOT (F-0531) .
1 PSP 02-FW-0537 SG IC Narrow Range Level Set 4 ACOT (L-0537)
1 PSP 02-FW-0540 Feedwater Flow Loop 4 Set 1 ACOT (F-0540)
1 PSP 02-MS-0534 Steam Pressure Loop 3 Set 1 ACOT (P-0534)
IPSP02-NI-0043 Power Range Neutron Flux Channel III ACOT (N-0043)
IPSP02-NI-0046 Extended Range Neutron Flux Channel IV ACOT (N-0046)
IPSP02-RC-0430 Delta T and T Average Loop 3 Set 3 ACOT (T-0430)
IPSM2-RC-0454 RCS Temperature Loop 4 Set 1 ACOT (T-0454)
1 PSP 02-RC-0461 RCS Temperature Loop 1 Set 2 ACOT (T-0461)
1 PSP 02-RC-0462 RCS Temperature Loop 2 Set 2 ACOT (T-0462)
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IPSP02-RC-0463 RCS Temperature Loop 3 Set 2 ACOT (T-0463)
IPSP02-RC-0464 RCS Temperature Loop 4 Set 2 ACOT (T-0464)
IPSP02-RC-0474 RCS Temperature Loop 4 Set 4 ACOT (T-0474)
IPSP02-SI-0931 RWST Level Set 2 ACOT (L-0931)
IPSP02-SP-00028 '
SSPS Actuation Train B Master Relay Test IPSP03-CV-0003 Centrifugal Charging Pump 1A Reference Value Measurement IPSP03-CV-0010 Boration Flow Verification IPSP03-DG-0002 Standby Diesel 12 Operability Test IPSP03-ZQ-0016 TAVG & Shutdown Rod Position Surveillance During Critica'l Approach IPSP06-DG-0005 Degraded Undervoltage Coincident With SI Relay IPSP06-DJ-0001 125 Volt Class 1E Battery 7-Day Surveillance Test
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t IPSP06-DJ-0001 125 Volt. Class 1E Battery 7-Day Surveillance Test >
IPSP06-DJ-0003 125 Volt Class 1E Battery Intercell Surveillance Test !
IPSP06-0J 0005 125 Volt Class IE Battery 60-Month Performance Test >
IPSP06-NZ-0002 Low Voltage Breakers Functional Test '
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IPSP07-WL-0001 Liquid Waste Effluent Releases *
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1 PSP 07-WL-0002 Radiochemical Surveillance for Liquid Waste Processing System Monthly Composite
IPSP10-RC-0001 RCS Flow Determination i IPSP11-RH-0004 RHR/RCS Interlock Test
- IPSP11-XC-0008 Local Leakage Rate Test P.enetration M-90 Personnel Airlock
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ISP506-NZ-0006 Molded Case Breaker Inspection ,
IP 1.45Q Station Problem Reporting /
IP 3.10 Plant Modifications IP Technical Advisory Council IP Licensed Operator Training i IP 4.1Q Nonconformance Control IPSP03-SI-0002 Safety Injection System Initial Lineup IPSP03-SI-0014 ECCS Valve Checklist 2 OPCP01-ZA-0012 Chemical Laboratory Quality Control l OPG03-ZR-0004 Radiological Controls Deficiency Reporting i OPGP03-ZO-0001 Clearance Procedure
! OPGP03-ZO-0003 Temporary Modifications and Alterations j OPGP03-ZA-0053 Shift Turnover l OPGP03-ZA-0064 Preshift Briefing OPGP03-ZA-0066 Configuration Management i OPGP03-ZB-0004 Review of Industry Operating Experience OPGP03-ZE-0051 Design Change Implementation After Turnover .
OPGP03-ZF-0014 Fire Prevention Surveys '
OPGP03-ZH-0002 Preventive Maintenance Program OPGP03-ZM-0003 Maintenance Work Request Program OPGP03-ZP.-0003 Maintenance Work Request Program r OPGP03-ZM-0010 Maintenance Shop Work Order .
OPGP03-ZO-0007 Conduct of Maintenance OPGP03-ZO-0028 System Configuration Control OP01-ZP-0030 Maintenance of Logbooks j OPOP-G-ZE-0020 Post-Maintenance Testing Program CVCS System Operator Procedure
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OPOP02-CV-04 "
OPOP03-ZP-0001 Plant Heatup ,
- QAP Deficiency Reporting l
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ATTACHMENT 2
, PERSDNS CONTACTED
Licensee P. Appleby, Manager, Nuclear Tralning Department C. Ayala, Supervising Engineer, Event Reporting
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- R. L. Balcon, Audits & Assessments Manager W. R. Bealefield, Maintenance Support Technical Supervisor W. S. Blair, Maintenance Support Manager
S. Blinka, Performance Support Supervisor D. J. Bryant, Lead Chemical Technician 3 M. H. Carnley, I&C Maintenance Manager . .
] L. R. Casella. Supervising Project Engineer '
D. Chamberlain, Systems Engineer
- R. W.' Chewning, Chairman, Nuclear Safety Review Board
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K. Christain, Shift Supervisor
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J. N. Constatin, Supervisor, Simulator Training
- S. M. Dew, Manager, Operations Support J. Fisher, Surveillance Coordinator M. Fredlander, Engineer ;
- J. E. Geiger, General Manager, Nuclear Assurance ~
L. Giesie, Development Analyst t
- J. H. Goldberg, Group Vice President, Nuclear R. Grantom, Surveillance Coorcinator J. Greene, Manager. Inspection and Surveillance R. Hamilton, Shift Supervisor S. E. Hill, Maintenance Support Technical Support Supervisor
- D. L. Hooper, Information Coordinator, CPL -
B. Humble, Section Supervisor
] *J. L. Hurley, Operations Service Manager, BCC
- G. L. Jarvela, Health Physics Manager D. Keating, Quality Engineering Manager
, T. Koenig, Production Support Supervisor
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J. A. Labuda, Senior Engineer Specialist - Fire Protection O. Leajer, Reactor Support Manager
- J. W. Loesch, Plant Operations Manager
- M. A. Ludwig, Maintenance Manager J. M. Mackay, Mechanical Maintenance Manager S. R. Maples, Chemistry Technician M. A. Markovich, Senior Chemical Technician
- M. A. McBurnett, Operations Support Licensing Manager
- A. C. McIntyre, Manager, Support Engineering ,
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G. N. Midkiff, Director, Independent Safety Engineering Group
- L. Mills, Senior Secretary ;
B. O. Monteau, Maintenance Specialist i T. J. Morris, Maintenance Department Training Coordinator i:
- D. Musick, Staff Engineer
- W. L. Mutz, I.P.S. Manager I D. Nester, Lead Engineer J. Nersta, Manager, Systems Division
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I E. Nichols, Electrical Maintenance Manager '
J. Noftsger, I&C Surveillance Supervisor
- G. L. Parkey, Plant Engineering Manager t S. Parthasapathy, Consulting Engineer ,
A. L Proffit, Jr., Mechanical Maintenance Technical Supervisor R. Rehkugler, Audit Supervisor :
J. H. Ross, I&C Maintenance Foreman C. S. Russell, Chemical Operations Foreman (Acting)
K. Trippel, Lead Systems Engineer .
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- T. E. Underwood, Chemistry Manager i
- E. Vaughn, Vice President, Nuclear Operations i
- G. Walker, Site Public Affairs l J. R. Walker, Manager, Operations Support Group .
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- F. G. Waterhouse, Information Management !
L. G. Weldon, Manager, Operations Training -
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J. Wells, Unit Supervisor (under instruction) :
F. L. Wiens, Maintenance Support Technical Supervisor C. D. Wren, Lead Engineer & Fire Protection Coordinator R. Zampieri, Engineer l
NRC
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- J. E. Bess, Resident Inspector (Operations), STP
- L. J. Callan, Director, Division of Reactor Projects, RIV '
- R. Carpenter, Senior Resident Inspector, STP -
- L. Constable, Chief, Project Section D. RIV
- P. Hildebrand, Reactor Inspector, RIV
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- 0. M. Hunnicutt, Chief, Test Programs Section..RIV !
- C. E. Johnson, Senior Resident Inspector (Construction), STP
- L. A. Yandell, Chief, Radiological Protection and Safeguards Branch, RIV .
- Indicates presence at exit meeting held January 8, 198 The NRC inspection team also contatted other licensee personnel including individuals in operations, maintenance, engineering, and trainin ,
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