IR 05000424/1988033
| ML20205H175 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 10/11/1988 |
| From: | Shymlock M, Linda Watson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20205H154 | List: |
| References | |
| 50-424-88-33, NUDOCS 8810280407 | |
| Download: ML20205H175 (43) | |
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UNITED STATES
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,j NUCLEAF. REGULATORY COMMIST,10N o
REGION 11 d
101 MARIETTA ST N.W.
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ATLANTA. OEORotA 30323 e
Report No.:
50-424/88-33 Licensee: Georgia Power Compaie P. O. Box 4545 Atlanta, GA 30302 Docket No.:
50-424 License No.: NPF-68 Facility Name:
Vogtle 1 g
Inspection Conducted: August 8 - September 12, 1988 MA 6 Mk
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Team Leader:
LT Watsor Dat4 Signed Inspectors:
M. DeGraff L. Lawyer R. Musser T. O'Connor D. Prevatte R. Schin D. Starkey L. Wert
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Approved by:
M. Shymlo(M Chief Date Signed Operational Programs Section Division of Reactor Safety SUMMARY Scope:
This was an announced Operational Performance Assessment (OPA). The OPA assessed the effectiveness of various plant groups including Operations, Maintenance, Quality Assurance, Engineering and Training, in supporting safe plant operations. Plant management awareness of, involvement in, and support of safe plant operation were also evaluated.
The inspection was divided into three major areas including:
Operations; Maintenance and Engineering Support of Plant Operations;
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and, Programs for Management Assessment of Quality.
Emphasis was placed on numerout interviews of personnel at all levels, observations of plant activities and meetings, extended control room observations, and plant and system walkdowns.
The inspectors also reviewed plant deficiency cards and Licensee Event Reports for the current Systematic Assessment of Licensee GS102SO407 881014 ADOCK0500g4 PDR
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Performance (SALP) evaluation period, and evaluated the effectiveness of the licensee's root cause identification; short term and programmatic corrective actions; and repetitive failure trending and related corrective actions.
Results:
In general, plant management was effective in esta511shing and implementing appropriate controls over plant operation. The licensee had established effective methods to recognize plent problems and establish action plans to correct problems both in the technical and human factors areas.
In addition, improvements had been made in interdepartmental communications.
Management meetings were concise and involved full active participation of appropriate organizations.
To promote communications, teamwork and problem resolution, plant management nad formed an Operations Management Council (OMC) which consisted of key managers.
This body identified top priority management issues and formulated action plans for resolution of the problems. In addition, a Management Duty Officer (MDO) program had been established for response to plant incidents and to provide management involvement in field activities.
The M00 program was being upgraded to incorporate Independent Safety Engineering Group (ISEG) recommendations on field observation techniques.
Control room operations were conducted in a professional and responsible manner. Control Room Operators (CR0s) were attentive and knowledgeable.
The use of a Support Shift Supervisor (SSS), to provide technical and administrative assistance to the Shift Supervisor (55), greatly contributed to reduced noise levels and traffic flow in the control room. Turnover checklists were thorough and detailed yet concise enough for efficient turnover.
Access to the "at the controls" area was rigidly controlled.
The licensee maintained an "Information Limiting Condition for Operation Log" (LCO) to track situations which would restrict unit operation in another mode, prevent a mode change or become an LCO upon loss of certain other Technical Specification (TS) or safety-related equipment.
This is a valuable tool for the SSs.
A brief revMw of the use of the emergency operating procedures (EOP)
in the simulator, including observation of four accident scenarios, indicated that operator actions were adequate, procedural compliance was good and the E0Ps were adequate.
The inspectors observed that the instructors conducted thorough critiques at the end of the simulator training sessions which were an asset to the training program.
Operations management had established good communications with the Operations staff and important information was passed between staff and management correctly and effectively. Engineering expertise had been added to the operations on-shift staff by using a number of Senior Reactor Operator (SRO) licensed engineers on-shif ____-- _ ___ -_____________ ___--________ _-__ _ _ _ __ -
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Plant Equipment Operators (PEOs) were knowledgeable and performed well with the exception of a failure to write Maintenance Work Orders (MW0s) for inoperable heat tracing.
The licensee established additional guidance for PEOs on the performance of clearances
involving draining, filling and venting processes to correct
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discrepancies noted by an NRC inspector.
The deficiency card (DC) system was roted to be adequate in 1dentifying conditions adverse to quality.
DC trending information
was presented to management in a quarterly report. The NRC did not identify any significant adverse trends during review of the DCs.
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The maintenance work order backlog was manageable and prioritized.
I plant material condition and housekeeping was adequate except that
additional emphasis was needed on applying and maintaining permanent l
coatings for supports and floors and improving labeling.
i The plant had established a long-term program to upgrade valve i
component and location labeling including establishment of a labeling shop with permanent and contract employee staffing.
The valve labeling program had been completed and acceptable goals had been
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l established for labeling of Unit I and Unit 2.
The coopet ation between plant departments and the engineering staff in resolving problems was noted as a strength.
Engineering participation in plant activities included a solid system engineering group which was actively involved in the maintenance and testing of systems.
Systems engineers routinely reviewed post maintenance testing for adequacy prior to test performance. An engineer-on-duty program had been established for 24-hour engineering assistance.
Adequate programs existed to control post maintenance testing, deferred preventive maintenance, %'O review prior to mode change, and operating experience review.
A sample of design changes and temporary modificatior.s reviewed by the NRC identified no problems.
A review of key controls identified a need to review the ability of PEOs to obtain ksys from the control room in order to respond to plant problems in the event of loss of power to security doors. The licensee agreed to review this aspect of ke/ control.
Quality Assurance (QA) reports were adequate, however, the inspectors concurred with the licensee in plans to increase the Operations experience in the group and noted that additional training had been given to auditors for reviewing human factors problems.
The inspectors also noted that improvement was needed in targeting areas in Operations for review and using a lower threshold for root cause determination and corrective action.
Weaknesses were noted in some plant programs and activities.
A number of surveillance tests required by TSs had been missed over the past year. Although management had taken some corrective actions
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based on individual events and QA audit findings, the Nuclear Regulatory Commission (NRC) Resident Inspector found it necessary to prompt management to study and propose corrective actions for certain aspects of the problem.
In addition, some actions proposed by Operations management to correct deficiencies in the licensed operator required reading crogram had nat been fully implemented and additional examples of deficienc" s in this program were identified and citad as a failure w "
adequate corrective action.
Additional examples of failure to allow various adeninistrative requirements in the Operations area indicated a lack of attention to detail and/or a reluctance to revise procedures to reflect the conduct of activities.
The example of an inadequate surveillance procedure, cited in this report, was due to the failure of the licensee to correct known deficiencies in procedures. Additional examples of failure to follow procedures and failure to correct sequence of steps or administrative control mechanisms wera noted but had little safety significance.
These findings indicate that a plant-wide problem with correcting procedures and procedure compliance existed.
The problem existcd even though personnel interviewed stated that procedure compliance and the correction of inadequate procedures were mandatory.
Although review of lighted control room annunciators indicated that the licensee had established an aggressive program to achieve a black board concept, the licensee did not routinely conduct safety evaluations for annunciators that were disabled.
In one case, a 10 CFR 50.59 evaluation was required because the annunciator was described in the Final Safety Analysis Report (FSAR).
Failure to perform the evaluation was cited as a violation.
In addition, the licensee had not conducted an evaluation of operating the plant with a ground in the 125V de system for an extended period of time.
A review of the instrument calibration program identified three instruments which had not been included in the calibration scheduling program.
These instruments had not been calibrated since before startup.
The licensee found, in June 1938, that two of the instruments had not been calibrated but f ailed to promptly include these instruments in the schedule and perform the calibrations.
Failure to perform the calibrations was cited as a violation. Also during the review, it was noted that the licensee did not have a single source program that describec how the requirements of TS 6.7.4.e were met. This TS required a program to provide certain periodic maintenance, surveillance, and operating procedures for accident monitoring instrumentation required by Regulatory Guide 1.97.
The initial review of implementation of the program revealed that one instrument, one of the three noted above, was not being calibrated. The licensee is conducting a review of the various plant programs covering periodic maintenance, surveillance, and operations
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procedures to confirm that all Regulatory Guide 1.97 instrumentation is covered. This review was identified as an unresolved item (VRI).*
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Violations were also issued (1) when a licensee employee removed and
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left his dosimetry and picture badge while working in a radiation
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control zone inside the protected area; and (2) for failure to
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- Unresolved items are matters about which more information is required
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'i to determine whether they are acceptable or may involve violations or
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deviations.
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REPORT DETAILS I.
Persons Contacted Licensee Employees
- J. Beasley, Outage and Planning Manager i
M. Bellamy, Plant Manager
- G. Bockhold, General Manager
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C. Cross, Nuclear Procedures Supervisor J. D'Amico, Support Outage and Planning Manager C. Eckert, Health Physics and Chemistry Manager
"G Frederick, QA Site Manager
- M. Griffis, Maintenance Manager i
W. Gabhard, Senior Regulatory Specialist
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- T. Greone, Plant Support Manager
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C. Griffin, Senior Plant Engineer
- C, Hayes, Vogtle Quality Assurance Manager M. Hobbs, Instrument and Controls Superintendent
- W. Kitchens, Operations Mana5er M. Lackey, Work Planning and Control Supervisor
- R. Lide, Engineering Support Manager
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- W. Nicklin, Reguistory Compliance Specialist
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- W. Marsh, Deputy Operations Manager
- G. McCarley, Independent Safety Engineering Group Manager
- C. McCoy, Vice Presicant, Nuclear
- C. Meyer, Operations Superintendent
- A. Mosbauyn, Assistant Plant Support Manager
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- K. Pointer, Senior Plant Engineer
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P. Rushton, Training and Emergency Planning Manager i
- J. Swartzwelder, Nuclear Safety and Cocpliance Manager
- C. Wreath, Superintendent, Nuclear Operations NRC Representatives
- R. Aeillo, Resident Inspector - Vogtle, Region II
V. Brownlee, Branch Chief, Division of Reactor Projects (ORP), Region II
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- A. Gibson, D. rector, Division of Reactor Safety (ORS), Region II
'J. Rogge, Sector Resident Inspector - Vogtle, Region II t
M. Shymlock, Chief, Operational Programs Section DRS, Region II
- M. Sinkule, Chief, Projects Section 3R, DRP
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Other liunsee employees contacted during this inspection included engineers, operators, mechanics, technicians, security and office personnel,
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Acronyms used throughout this report are listed in the last paragraph.
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Operations (42700, 71707, 71715)
The inspectors performed extended observations of control room activities (including back shifts), observed shift turnovers, and reviewed applicable operator logs. The inspectors monitored Operations personnel performance, awareness of plant status, use of procedures, and the maintenance of required logs.
Interviews were conducted with licensed operators and plant ;quipment operators during control room observations, system walkdowns, plant tours, control room observations of surveillance testing and tagging and removal of equipment from service.
During these interviews, the operators indicated that their training and retraining, procedures and drawings, communications, and management support were all adequate. They felt that overtime was not excessive ard identified no serious problem areas.
Interviews were conducted with the Operations Manager and the Deputy Operations Manager.
They were knowledgeable of current plant status, improvement programs planned and under development, event trending, and sta f fing levels.
The goals and objectives programs were effectively translated into first line supervisor performance elements.
The following procedures were reviewed:
10000-C, Conduct of Operation, Rev. 8
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10001-C, Logkeeping, Rev. 5
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10002-C, Plant Operating Orders, Rev. 7
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10003-C, Manning the Shift, Rev. 5
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10004-C, Shift Relief Rev. 5
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10005-C, Operability Status Indication for Plant Safety Systems,
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l Rev. 3 10008-C, Recording Limiting Conditions for Operation, Rev. 5
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10009-C, Operator Aids, Rev. 4
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10016-C, Component Identification, Rev. 6T
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10017-C, Operations Reading Book, Rey, 2
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34223-C, Channel Calibration of the Gaseous Effluent Monitors,
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Rev. 4 and Rev. 5 a.
Control Room and Local Plant Operations (1) Control Room Demeanor Control room activities were carried out in a professional manner.
Reactor operators were attentive to control room conditions, promptly responsive to annunciators until proven l
false, and made use of procedures. When leaving the "at the l
controls area" the operators performed an adequate turnover to a qualified indhidual.
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The SSs were knowledgeable of plant conditions and displayed the same positive qualities as the reactor operators. Additionally, the SSs maintained posit've control over access to the "controls area."
In general, control room operations were noted as a strength.
The provision of a fourth shift supervisor, the SSS, in addition to the two SSs and the On-Shif t Operations Superintendent (0505), has eliminated the non-essential administrative tasks from the Unit 1 SS, thus allowing his concentration on the status of Unit 1.
Also contributing to this favorable work climate in the Unit I control room was the provision of an on-shift clerk.
The very low level of non-essential administrative tasks that were performed in the Unit I control room was judged a strength.
No violations or deviations were identified.
(2) Status of Control Board and Local Instrumentation The inspectors noted that the "dark board" concept was being vigorously pursued.
During the inspection a typical number of lit annunciators in the controls area was 8-10 annonciators out of the approximately 900 total. An additional 10 annunciators, which were color coded green because they are expected to be lighted during normal operations, were specifically exempted from the "dark board" concept.
The inspector reviewed procedure 10018-C, Annunciator Status Control, Rev. 6, and the control of disabled annunciators in the control room.
A total of 41 annunciators were logged, in accordance with procedure 10018-C, as disabled.
Approximately 20 of these were in the "at the controls area."
Operators were aware of lighted and disabled alarms and the reason for the annunciator being lit or disabled. The inspector verified that the log accurately reflected those annunciators labeled as out of service (and observed during annunciator checks to be disabled).
One minor administrative error was noted in the log and it was immediately corrected. While the log was reviewed as required to ensure the contisued need for each disabled annunciator, the review was not always documented in the log index as required.
Four annunciators were disabled in response to de grounds.
The licensee replaced these cards during the inspection in an attempt to trace the ground to a particular component but was unable to locate the ground. The cards were again removed to disable the annunciators.
Several other annur.ciators were removed from service due to "inability of the battery chargers to load share." The inspector closely reviewed the disabled annunciator log to ansure that annunciators were not being disabled primarily due to any
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singular cause, such as nuisance alarms.
The inspector concluded that only a small portion of the total disabled annunciators were disabled as nuisance alarms. The reasons for the remaining disabled annunciators were divided among annunciator malfunctions, pending design changes, equipaent problems, or other reasons.
The inspector noted that 16 annunciators were disabled during the inspection period, and 11 were repaired /raturned to service during this period.
On further investigation into one of the disabled annunciators, the inspectors identified a concern with the licensee's procedures for disabling annunciators.
10 CFR 50.59 allows changes to be made to the facility as described in the FSAR but requires that a safety evaluation be written in these cases.
The annunciator under review, which was disabled due to a ground that could not be cleared on the vital (IE) 125V de bus, was labeled "125V DC PNL 1AD12 Trouble".
Stickers attached to the annunciator indicated that tha alarm had been disabled by pulling a card and that an F# had been written to initiate repair.
The operators stato that the annunciator had been disabled because it had been continually alarming.
Ka'0 18801652, dated March 18 1988, stated that the problem was a ground in the "A" train de. Maintenance performed under this Kn'0 included monitoring for grounds while Operations selectively opened breakers.
This resulted in a March 19, 1988, determination that the ground was in a circuit supplied from vital de panel 1AD11 or IAD12. The Kn'0 indicated that neither Engineering nor Operations wanted to take responsibility for opening breakers on these panels with the reactor at powar. As a result, the Ma'0 was scheduled for the next outage in October 1988.
The annunciator was disabled by disconnecting the annunciator card on June 28, 1988.
The 125V de panel 1AD12 trouble alarm had three separate inputs, as described in FSAR Section 8.3.2.2, and also described in procedure 17034-1 Annunciator Response Procedure ALB34, Rev. 2.
The inputs included bus ground f ault, panel undervoltage, and breaker trip. Since the innunciator had no reflash capability, leaving it lit due to the de ground fault essentially disabled the alarm capability of the other two inputs. Disconnecting the card to disable the annunciator did disable the alarm capability of the other two inputs.
All of the breakers on panel 1AD12 had vital de loads.
The circuit from breaker 07 to emergency shutdown panel A was traced through electrical prints to determine if there would be any remaining control room alarm or indication if that breaker tripped..It was determined that power from breaker 07 was used on the shutdown panel for scram breaker position indicatio _ _ _ _ _ _
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With the 1AD12 trouble annunciator disabled, there was no other control room indication of breaker 07 tripping.
The "125V DC PNL 1AD12 Trouble" annunciator was disabled per
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procedure 10018-C, Annunciator Status Control. Rev. 6.
This procedure provided for implementation of the "dark board" concept by removal of control room annunciator cards as
authorized by the SS. No other review or safety evaluation was required to disable any of the control room annunciators.
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procedure stated, "If an annunciator has multiple inputs, an annunciator card may be removed provided, prior to shift relief, action is initiated to correct or disable the malfunctioning
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input."
The requirement to initiate corrective action was satisfied by writing an MWO.
The procedure stated that annunciator cards were to be removed for conditions such as instrument loop malfunctions, abnormal system lineups, or related component maintenance. In essence, any annunciator that
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was lit because of equipment malfunction was to have an >fn'0
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written and the annunciator card disconnected to maintain a
"dark board".
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The inspector noted that, instead of disabling the 1A012 trouble j
annunciator, the bus ground fault input could have been l
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disabled. This would have restored the alarm capability of the j
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undervoltage and breaker tripped inputs.
Disabling of the bus r
ground fault input would have involved the use of a jumper, and i
the licensee's procedures for temporary jumper and lifted wire control would have required a safety evaluation to be performed.
The licensee stated that control room annunciators were not classified as 1E safety equipment, and therefore, were not required to be operable.
The licensee cmcluded that the annunciators did not require a safety evaluation prior to being dissbled.
The inspectors observed that this reasoning was j
flawed in that many annunciators have safety importance and many have related licensee commitments ir the FSAR.
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10 CFR 50.59 allows the licensee to make changes to the facility, as described in the FSAR, under certain conditions.
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But when such changes are made, a written safety evaluation is required.
10 CFF. 50.59 does not distinguish between safety-related and non-safety related equipment but rather addresses all equipment doscribed in the FSAR.
The 125V de panel trouble annunciator and its three inputs were described in the FSAR as part of the de electrical power system.
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No safety evaluation was required by the licensee's procedures
nor was one done.
The failure to perform a safety enluation i
for a chanje to an annunciator described in the FSAR is identified as violation 424/8S-33-01.
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An additional inspector concern was that the plant had been operated for approximately five months with a ground fault on the vital 125 volt de bus. The FSAR described an ungrounded
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vital 125 volt de bus. Procedure 17034-1, Annunciator Response
Procedure, Rev.
2, required certain action to be taken in i
response to a "125 V DC PNL 1AD12 Trouble" alarm. The procedure
stated:
"If a bus ground protection alarm is indicated,
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selectively de-energize components to locate the ground and notify maintenance." This procedure was not promptly completed in that the ground was not located in five months (March -
August).
As previously noted, some breakers were opened within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in an effort to locate the ground.
A decision was made to not open breakers on panels 1AD11 or 1AD12 while the plant was operating to avoid a risk of tripping the plant.
No DC was written.
The W'O was then deferred to the
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next outage without further evaluation.
Review of operation with a ground on a vital de bus is identified as inspector
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followup item (IFI) 424/88-33-02.
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(3) Logs and Records The SS's log and unit control log were reviewed and found to be
completed in accordance with the applicable plant procedure.
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i The logbook entries were neat and legible and adequately
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j reflected the plant status.
Significant operational events,
unusual parameters, and alterations to safety related system
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alignments were recorded. Logbook entries were being made on a
real time basis with periodic reviews being completed as
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required by procedure.
The number and classification uf i
Operation's personnel on duty on each shift was logged in the SS logbook and was found to comply with procedural manpower
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requirements.
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Log sheets kept by the CR0s were found to be complete with no missing parameter entries. Maximum and minimum limits for each sntry ware specified on the blank log sheets.
Parameters
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outside the expected range were highlighted by the CR0 j
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completing the log sheet.
Log sheet entries by CR0s were current Lnd real time, properly reviewed and signed.
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completed log sheets were reviewed and signed by the SS.
The Night Order Log, Book 1, dated July 29, 1988, was reviewed
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and the entries seemed to be appropriate, to the proper level of
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detail and being read by operators.
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Reviews of control room logs were not always documented as
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required by the applicable procedure.
Three examples of this were noted. The first was the monthly review of the Information Tag Log.
Two entries, January and June 19SS, were not l
documented as required by procedure 10009-C, Operator Aids, Rev. 4.
Other examples were the reviews required by procedures
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10021-C. Temporary Valve Order Book, Rev.
1, and 10018-C, Annunciator Status Control, Rev. 6.
Examination indicated that all required reviews were being conducted, but the documentation of each review was not in accordance with the applicable administrative procedures.
Operations Procedure 10008-C, Recording Limiting Conditions for Operation, Rev. 6, required that if actions are to be taken by another department to meet an LCO, the SS shall contact the responsible supervisor and have that individual sign, date and record the time in the SS log, acknowledging notification of required actions. The inspectors observed two active LCO Status Sheets which had not been signed by the Chemistry Department Supervisor, ihe Chemistry Department Supervisor was recording the requirement for completion of the action in chemistry logs.
This situation was promptly corrected by the licensee by procedural change.
The inspector performed a review of log sheets to confirm that TS required surveillances were performed in the proper time period.
Control room temperaturo readings were required by Technical Specification (TS) 4.7.10 every 12 brs.
However, under the licensee's current eight-nour shif t rotation, this requirement could be exceeded.
Administrative Procedure 14000-1, Operations Shift and Daily Surveillance Logs, Rev. 15, required logs to be started within two hours of shift relicf.
The inspector considered this direction adequate to ensure the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> period would not be exceeded.
Inspector observations and discussions with operators confirmed that this two hour requirement was being followed.
The inspector reviewed the Temporary Valve Order Book and Procedure 10021-C, Valve Orders, Rev. 1.
These orders were used to control the operation of valves when not covered by operating proceduces or clearances. The inspector noted that all such orders were routed, after completion, to the Operations Superintendent for consideration for incorporation into plant procedures.
No violations or devittions were identified, (4) Overtime j
procedure 00005-C, Overtime Authorization, Rev. 3, provided I
guidelines and restrictions on the use of overtime for the plant staff and contractors responsible for performing safety-related functions.
To determine the adequacy of the licensee's adherence to these overtime guidelines, the inspector raviewed time sheets of randomly selected Operations tarsonnel.
No examples were identified where personnel exceeded the overtime guideline _ _ _ _ _ _ _
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No violations or deviations were identified.
(5)
Review of Drawings, As-Built-Notices and Controlled Documents An audit of twenty randomly selected control room drawings was performed.
The drawings were reviewed for the latest revisions a t, compared to the copy maintained by Document Control.
All twenty drawings were current. The drawings were also reviewed for legibility. Of the twenty prints reviewed, three (1X4DB187, Rev.
4, 1X4DB142-1, Rev. 18, and IX40B150-1, Rev. 9) were partially illegible due to poor quality reproduction of the prints.
The drawings were kept on stick files in the control room.
Since these drawings are for opetator usv, they must reflect the current plant status. Changes to these drawings as a result of plant modifications, problems found during system walkdowns, etc., were accomplished by the issuance of a sep Ata document called an As-Built-Notice (ABN).
The ABN was the interim document between drawing revisions. During the period of time that any ABN was in effect, the licensee included that ABN with the applicable control room drawing to reflect current plant status.
This was accomplished by placing the ABN af ter the affected drawing in the stick tile.
The affected drawing was then marked with a large red stamr to ensure that the operators using the drawing were cognizant of the fact that the drawing currently had an outstanding ABN(s).
The inspector reviewed a sample of ABNs and the affected drawings and noted the following:
ABNs 88-VI000A138T (dwg. 1X4B179-2) and 88-VA000A003T (dwg.
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AX3D-AA-F19A) were filed with their associated drawings, however, the drawings were not marked with the red stamp alerting the operators to the presence of the ABN.
Drawings AX3D-AA-F07A, Rev. 8, and AX3D-AA-F18A, Rev. 5,
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were marked with the ABN stamp, however, no ABNs were attached to the drawing.
ABNs 87-VI000A305T (dwg. CX4DS173-2), 88-VI000A215T (dwg.
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1X3D-AA-F25A), 87-VI000A321T (dwg. 1X3D-AA-F35A) were hard to recd due to poor reproduction.
The above discrepancies were provided to the licensee for corrective action.
Durirg the inspection, the previously identified discrepancies were reviewed to assure corrective action was completed and an additional sixteen drawings were selected for legibility review. One of the drawings previously identified was still difficult to read, however, the drawing was of the condenser tube cleaning system and was not safety-significant. Although all other drawings reviewed were
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legible, it was noted that the quality of some drawings could be
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improved.
Twenty-five controlled copy adminstrative and operating procedures in several facility locations were selected for audit. All contained the latest revision, except uhere recent
revisions were issued but not yet filed.
During observation of work in the S$5's of fice on August 26, 1988, an inspector noted that the copy of FSAR Table 3.2.2-1, Classification of Structures Components and Systems was not a controlled document and, in fact, did not contain the latest
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FSAR amendments.
Table 3.2.2-1 was utilized by the $55 to
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determine if components required independent verification, as well as other information.
This problem was brought to the
licensee's attention and the copy was replaced by controlled copy 125 of Volume 6 of the FSAR. A subsequent audit of the SSS's controlled copy of Volume 6 of the FSAR Indicated that
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nine pages were either missing or had the incorrect revision l
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number.
The failure to control the issuance of documents, including changes thereto, which prescribe activities affecting
quality and to assure that changes are distributed to the
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location where the prescribed activity is performed is a
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violation of 10 CFR 50, Appendix B, Criterion VI, Document
Control.
This is identified as violation 424/88-33-03.
(6) Temporary Changes The inspector evaluated the licensee's process for making temporary changes to procedures (TCP). The process is covered by procedure 00052-C, Temporary Changes to Procedures, Rev. 4.
While examining the TCP process, the inspector discovered that TCPs were not issued with the working copies of procedures issued at Document Control. This was due to the fact that the set of procedures from which working copies were.eproduced did not contain copies of the temporary changes. Each employee was responsible for verifying that the procedure used was current and applicable TCPs were obtained.
The control room ccpy of procedures did include the applicable ICPs.
The licensee comitted to include the TCPs in the Document Centrol wo king copies so that any further working copies of procedures issued from Document Control would have TCPs issued with them.
Procedure 00054-C, Rules for Performing Procedures. Rev. 3, required that any temporary changes applicable to a r e edure be used with that procedure. The process for obtaining W curreat revision of a procedure, the Nuclear Operatioa Records Management System (NORMS), did not contain information on the existence of TCPs to procedures.
Instead, this information had to be obtained from tne control room clerk who controlled issuance of TCPs, Therefore, when checking on a procedure for
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use in the field, it was possible to overlook the existence of a TCP.
The licensee has committed that TCPs will be placed in NORMS so that TCPs, as well as the current revisica to a procedure, can be verified prior to the performance of the procedure.
The inspectors reviewed four TCPs for content and adherence to TS 6.7.3.
During this review the inspector noted that a temporary procedure change had beere used to update a Unit 1 procedure to include Unit 2 components.
The licensee issued a Standing Order requiring Unit 1/ Unit 2 interface procedure revisions to be processed under the permar.ent procedure change process.
No violations or deviations were identified.
(7) Jumpers and Lifted Leads The jumper and lifted leads log was inspected.
This log was being maintained in the control room by the SS in accordance with procedure 00306-C, Temporary Jumper and Lifted Wire Control, Rev.
7.
Six items were outstanding, none for an extended period of time.
No violations or deviations were identified.
(8) Control Room and Plant Labeling During tours of the operating unit, the inspectors observed valve labeling to be generally good but labeling of other components needed improvement. Some components did not have any labels while others had labels which did not conform to the Unit 1/ Unit 2 distinguishing label policies of 10016-C, Component Identification, Rev. 6T.
This issue will become even more important as Unit 2 start up approaches.
During the course of the Inspection the inspectors observed the performance of many operating procedures. Only one discrepancy between installed labels and prc edural nomenclature was noted (the boron concentration meter in the control room was not labeled with the same number as that stated in the procedure).
To resolve this, the operators immediately filled out a procedure change request to corren this discrepancy.
The inspectors reviewed the licensee's action plan for completing a sign and labeling program.
The licensee has established a sign and label facility with permanent and contract employee staffing.
Completion of labeling for Unit 2 is targeted for Unit 2 startup and additional labeling for Unit I should be completed by December 1989 with other plant informational signs completed by March 199 _ - _ _ _ _ - _ _ _. _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _..__ _ ____ ____________
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No violations or deviations were identified.
(9) Observation of Fire Protection Measures The desigr.at*en of the Fire Brigade Team was appropriate and in accordance with requirements.
The designated personnel did not include the CR0 nor the Balance of Plant Operator.
The designated Fire Brigade Team Leader was the SSS for each shif t observed.
During a walkdown of a clearance in the control building, the inspectors discovered a fire door partially open. The door was located off a corridor going to room 50 in control building level B.
Af ter closing the door, the inspectors observed two different instances where a security guard passed through the door and left it partially open each time. The door apparently would not swing fully shut on its own and required positive action by personnel to assure it was shut.
The licensee promptly issued an interna! memorandum to all security force members reminding them of the requirements for closing fire doors.
During observations of plant rounds conducted by PEOs, the inspector determined that an inoperable fire door was not included on fire watch rounds.
This door, to room RD 105 on level 0 of the auxiliary building, had an orange "maintenance required" tag on it, dated August 7,1988, which stated, "door knob not working properly." Ma'0 V1210SL1053, dated August 7, 1988, had been written for repair of this door. On the Ma'0, the block for "Fire Protection Related (Y/N)" had been erroneously marked "N".
The fire protection technician in the control room, who was coordinating fire watches, stated that he had no record of a problem with this fire door. Af ter notification by the inspector of the problem with fire door RD 105, the fire protection technician initiated a fire watch on the door and also initiated a DC for investigation into the missed fire watch.
No violations or deviations were identified.
(10) Control and Plant Operating Panels The inspectors observed that the following recorders un a control room "back panel" were not inking properly:
1UR-12627 Piping Penetration Filter 1 1UR-12132 Control Room Filter 1 Outlet 1UR-12133 Control Room Filter 2 Outlet Procedure 10001-C, Log Keeping, Rev. 5, required operators to ensure each recorder was marked at the start of each shift with
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L time and date, checked for proper operation, and initialed.
While these charts had been faithfully marked and initialed every shif t, the charts had not been inking properly for at
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least several days, i
The inspectors observed that the following indications (lighted
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indicating needle on dark display meter) were not indicating any k
value:
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1 Il-40088 CRDM Cooling Fan 4 (amps)
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1 TI-12559 CB El Penetration Filter (degrees F)
1 P01-2561 El Penetration Train B (inches Hg)
Maintenance work orders were written for tnese instruments after l
the inspector pointed them out.
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While these chart recorders and instruments were not critical to
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safe plant operation, the fact that these indicators were
obviously not operating properly and had not been addressed
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previously by operators indicated a lack of attention to detail on the part of the concerned operators.
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No violations or deviations were identified.
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(11) Plant Rounds t
The inspectors accompanied non-licensed PEOs on rounds of the i
following watch stations: Auxiliary Building, Control Building,
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and Turbine Building.
i PE0 compliance with radiation protection and security requirements was observed to be adequate. One fire protection
door that was ajar on August 9,1908 (and lef t that way by the
PEO) was found by the inspector to have no fire watch assigned, t
(See paragraph 2.a(9).
Shift turnovers by PEOs were observed to be thorough, and
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included:
(1) Shift betefing by the OSOS covering current plant status, f
recent plont events, and expected operations / maintenance
during the oncoming shift.
l (2) Review of log sheets and log book, plus signing over the (
watch in the log book.
(3) Completion and review of a Plant Equipment Operator Relief Checklist form.
This form included time and date, unit, shift, position, work station status, special instructions, procedures in progress, fire team status, rounds status,
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logs reviewed, keys turned, and names and initials of the offgoing and oncoming PEO.
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The eight-hour shifts were started by making a round of assigned machinery spaces and completing log sheets. The log sheets were adequate in describing activities to be accomplished and in containing minimum and maximum limits for parameters to be recorded. PEOs were knowledgeable about equipment, systems, and general conditions in their assigned watch areas. Abnormal log readings that were encountered were circled in red; comments were written on the log sheet; and, the CR0 was kept informed.
During rounds of the Auxiliary Building, the PE0 checked heat tracing panels, as required by his log sheets.
The inspector observed that some heat tracing panels had off normal lights lit that were not covered by the orange "maintenance required" tags attached to the panels, and the PE0 had made no log enti*ies nor initiated Mats for these conditions. When asked about the off normal heat tracing lights, the PE0 stated that the heat tracing system had never worked right and was not needed during the After the inspector exprtssed concern to the 0505 about summer.
i PEOs failing to implement operational procedures, i.e., f ailing to log off normal conditions and to initiate Mats, the 0505 directed the PE0 to initiate Fats.
The heat tracing under review was determined to be non-safety-related, nor was any of it required to be operable by TSs. The OSOS and Operations Manager confirmed that the heat tracing systems were not needed in the summer.
The itcensee also verified that at least one train of heat tracing to safety-related systems was operable. Based on the licensee's review, the heat tracing had been inoperable for some period of time and confirmed that several PEOs had checked these panels without taking the procedurally prescribed actions.
The inspectors considered the failure of the PEOs to implement operating procedures a weakness and a further example of inattention to detail.
The iteensee initiated an action plan for accomplishing repairs to the heat tracing system prior to winter.
This plan was brought a the attention of the OMC for evaluation and assignment of responsibility.
No violationi or deviations were identified.
(12) Communications Communications between the PE0 and the CR0 were accompitshed by use of:
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a-14 (1) CR0 paging for the PE0 using a plant public address (PA),
also called paging system. PEOs stated that the PA system could be heard in most areas, but would work better if speaker volumes were adjusted better for various areas.
(2) CR0 contacting the PE0 by use of a pocket beeper carried by the PEO.
This beeper could be set to give an audible or vibration signal.
The use of a vibration signal would unable the PE0 to be contacted in a high noise area. PEOs stated that the beeper worked in most of the watch areas.
(3) PEOs communicated to the CR0 by use of telephones, which were located throughout the machinery spaces. PEOs stated that some of these telephones were in noisy areas and needed sound protection (phone booths) to enable effective communication.
A communication system weakness was observed during Residual Heat Removal System (RHR) surveillance testing (paragraph 2.d).
In that instance, a CR0 was unable to contact a Pio via the paging system during an important part of the test due to the failure of a pager. A maintenace work request was written to repair the pager and the licensee agreed to review plant paging, beeper, and phone cot.munication coverage.
During observation of operators in the control room, the only weakness observed was that repeat backs required by procedure 00004-C, Plant Communications, Rev.1, were not consistently utilized by operators.
No violations or deviations were identified.
(13) Key Control The licensee's measures of establishing access to security doors leading to the power block and control room were reviewed.
Currently, these areas can be accessed in two ways, via the magnetic card reader associated with the specific door or via a security key in the event power to the card reader is lost.
Those individuals currently assigned keys are the $5 and the 0505.
Additionally, there are keys maintained in the main (
control room as well as the guard house.
The inspectors l
expressed a concern that PEOs weuld have to return to the l
control room before they could obtain a key if a security power failure were to occur.
In this instance someone would have to
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l respond and open the necessary doors to allow individual access i
to the control room, The licensee responded to this concern by l
agreeing to review the feasibility of issuing PEOs keys or by assuring that the present methods allowed timely access.
Followup on this concern is identified as IFI 424/88-33-04.
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No violations or deviations were identified, b.
Emergency Operating Procedure Review The inspectors observed licensed operators perform the actions prescribed by E0Ps for the following scenarios:
a) Saturated Cooldown b) Steam Generator Tube Rupture c) Anticipated Transient Without Scram d) Main Steam Line Break Inside Containment The operator actions were satisfactory, procedural compliance was good and the E0P3 were found to be adequate for the limited depth of this observation.
At the conclusion of each scenario, the simulator instructor systematically and very thoroughly critiqued the actions of the operating crew.
These critiques were conducted in a professions)
manner, were frank, well received and made a very cositive contribution to operator training. No deficiencies in the portions of the E0Ps observed were noted.
No violations or deviations were identified, c.
Required Reading procedure 10017-C, Operations Read'ng Books, Rev. 2 stated that licensed operators should read the assigned required reading materials within seven days. This procedure required that the Senior Clerk perform an audit of the required reading book every two weeks and send a notification to dehnquent persons (those who had not initialed the log within the seven day period). If, after four weeks from the date of the required reading document, the person had not responded by reaoing the document and initialing the log, the clerk would send a memo to the Operations Superintendent notifying him of the delinquent individuil(s).
The inspectors reviewed the compliance of four licens id opera tors who were on shif t during the inspection; two SR0s and two CRos. Twelve documents were selected at random from the list of required roading. These documents had dates ranging from March 18, 1988 to.luly 21, 1988.
Of 46 required entries, 26 did not mer,t 'he seven day reading inte* val. Of these
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26, eight had not been sigrad >*. all and were at that time 3 to 3 1/2 weeks past the posting date.
The inspector also reviewed selected required reading documents to determine if any documents had not been initialed.
The longest overdue reading item by a watchstanding Unit I licensed operator was document SS-024 posted March 18, 1983 (approximately 20 weeks before the inspection).
Other documents with missing initials by one or
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more licensed operators were dated March 29, June 23, June 28, and i
i July 5, 1988.
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An additional review was performed to determine the effectiveness of f
the management control systems being applied to the required reading
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program. This management control audit was induced by a need to know
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whether. previous correccive actions had been successful. Similar l
deficiencies in the required reading program had been reported in NRC
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Inspection Report 424/88-07 dated March 30, 1988.
That report i
documented an apparent procedural violation in January 1988 in that
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the licensee's required reading procedure for operators had not been
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adequately followed.
Many operators had not read the requirea
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reading materials in a timely manner.
Since the licensee i
demonstrated that this deficiency had been self-identified and I
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corrective actions were planned, a violation was not cited.
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For this review, one licensed operator's file was chosen.
Several l
i conclusions were reached:
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1.
Approximately one-third of the new entries of initials were
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missed when the clerk's audit was performed.
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3 2.
The audits were performed every two weeks as required by
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procedure. However, since the purpose was to notify persons who
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were more than two weeks past the posting date, this frequency
was too low for that purpose. A person could be nearly four
weeks in arrears upon first discovery, and four weeks was the
)j trigger point for escalation to Operations Superintendent
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notification.
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3.
The procedure provided for the following escalated management I
attention:
Notification of the individual when 2 weeks in i
arrears and notificatier of the Operations Superintendcat when 4 weeks in arrears. Howeve;, the usefulness of this provision as f
a nanagement control was found to be inadequate in that no
record of these notifications was available for management j
review and action, nor was any record required.
I a
j 4.
Contrary to the provision of the procedure, the four week remo was being sent to the Operations Manager rather than the i
Operations Superintendent as the procedure required.
The licensee indicated that the procedure would be changed to I
require this notification be sent to the Operations Manager.
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On February 29, 1983, the Op. ations Manager, in response to the
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Jar.uary 1988 NRC inspection discussed above, informed all Operations
personnel by memo of the need to comply with procedure 10017-C.
Also, it identified those who at that time were more than 6 weeks
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delinquent and stated.
"Another audit of reading lign-offs will be
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performed in the near future.
Those delinquent in reading required reading by more than 6 weeks will no longer be qualified for shif t
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duties." At the exit interview, the licensee stated that it was not intended that this be interpreted as meaning that such persons would be removed from licensed duties at exactly 6 weeks but did not provide an alternate interpretation. Contrary to the provision of this memo, as of August 10, 1988, at least one licensed SRO had been standing watch during this inspection while more than 12 weeks in arrears on one required reading route sheet (88-025) and 20 weeks on an additions' one (88-024). These two route sheets covered important information, including four of the licensee's Licensee Event Reports (LERs) and one Design Change Request (DCR),
One other licensed person was more than 6 weeks in arrears on one routing (88-067) and two licensed persons were more than 6 weeks in arrears on an additional routing (88-070). While not documented, the senior clerk stated that audits were perforced approximately every 2 weeks between the date of that memo and the date of this inspection.
Second4ry information reviewed during this inspection supported the contention that those audits were being performed.
The cases cited above indicate that the licensee failed to take adequate corrective actions to assure that required reading was performed in a timely manner. This is identtried as a violation of the requirements of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, which requires that in the case of significant conditions adverse to quality, corrective actians shall be taken to preclude repetition. This is identified as violation 424/88-33-05.
During this inspection, the seven day period allowed for reading the material was changed to 71 days to pravent violations of the procedure caused by vacations, sickness, days off, and other short term absences.
d.
Surveillance Testing Selected survei' lance tests were rev'ewed and/or witnessed by the inspector to verify that; approved procedures were available and in use; test prerequisites were met; administrative approvals were obtained p'ior to initiating the test; testing was accomplished by qualified personnel; measuring and test equipment was properly calibrated, data and test results met TS requirements; any test discrepancies were rectified; and, the system was properly returned to 50rvice upon completion of the test.
The following tests were either reviewed and/or witnessed:
24546-C Triple Range Catalytic Combustion Analyzer AAIC-1118 Analog Channel Operation Test, Rev 4 28911-C Class 1E Seven Day Battery Inspection and Maintenance
"C" Train 11806B3BYC, Rev. 6 24909-C Personnel Airlock Door Seals Leak Rate Test, Rev. O
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24955-1 Containment Penetration No. 83 Quarterly LLRT, Rev. 4 34226-C Technical Specification and Routine Surveillance Channel Checks and Source Decks of DRMS Monitors, Rev.10 14803-1 CCW Pumps and Discharge Check Valve Inservice Test, Rev. 4 14825-1 Quarterly Inservice Valve Test, Rev. 8
>
14810-1 Turbine Driven Auxiliary Feedwater Pump and Check Valve
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Inservice Test, Rev. 6 l
14546-1 Turbine Driven Auxiliary Feedwater Pump Operability Test,
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Rev 4 e
i The following problems were identified:
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All prerequisites and steps of the Analog Channel Operational Test l
(ACOT) on the Catalytic Combustion Analyzer conducted under procedure 24546-C, were satisfactorily completed up to equipment restoration step 4.4.6.g.
The technician noted that steps had been added to the restoration section to adjust flow to the analyzer. The technician L
felt that this was inappropriate as part of the ACOT. The technician
stopped work and notified the shift supervisor and his foreman as t
required by steps 2.10.
The foreman reviewed the procedure and (
directed the technician to delete steps 4.4.6.f through j, which
covered the equipment return to service.
The inspector questioned the deletion of these steps since procedural
step 1.4.1 stated that this section was required for restoration of k
the equipment af ter completion of the channel test.
The licensee
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then conducted a review of these restoration steps and determined l
that the steps contained in the procedure for adjusting the back j
pressure regulator to obtain adequate flow to the analyzer were incorrect.
Failure to perform these steps or use of the steps as written would not have resulted in achieving s correct flow to the r
analyzer. These errors would have been identified and corrected if
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the calibration portion of thi procedure had been co% )eted prior to i
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usir.g the procedure to complete the ACOT.
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f The licensee stated that when the procedure was revised for Rev. 4 on i
July 15, 1988, the intent was to first perfore a system calibration
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using procedural sections 1.0, 2.0, 3.0, 5.0 and subsections 4.1, 4.3
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and 4.4.
After successful completion of the calibration steps, l
subsections 4.1, 4.2 and 4.4 were to be used to perform the 31 day
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ACOT.
Poor cor.nunications resulted in the procedure being used to (
perform the ACOT first and led to this problem.
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After identification of this problem, the licensee documented this
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item on DC 1-SS-2278. The procedure was revised on August 10, 1988,
under TCP 24546-C-SS-1. Instrumentation and Controls (I&C) personnel i
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then calibrated the unit, performed the ACOT, and returned the unit j
to service.
Failure to revise the precedure to contain the correct calibration
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l data is contrary to TS 6.8.1.a which requires that written procedures be maintained covering the activities recommended by Appendix A of
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Regulatory Guide 1.33 Revision 2 February 1978. This is identified
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as violation 424/88-33-06. The licensee should also address whether provisions exist in the procedure review process to ensure that required calibration steps have to be accomplished prior to using
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a revised procedures to perform ACOTs.
)
Surveillance test 28911-1 on the
"C" train Class 1E battery was j
observed on August 10, 1988. No deficiencies were identified in the procedure or task performance.
Discussions with the technician
I performing the test indicated that problems had been experienced with
individual cell specific gravity and voltage readings and that a single cell battery charger had been used at various times to correct j
these problems.
)
A review of the licenst.e maintenance work orders revealed that the i
sin 11e cell charger had been used on at least four occasions under i
Md0 Nos. 18301778, 18710288, 18703537 and 18707642 for periods of up to five days in 1937 and 19S8. The batteries were in service when
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l the single cell charger was used. Interviews with licensee personnel and a record review indicated that the charger was first used with j
temporary modification TMR 1-87-292 in August 1937 in an attempt to j
correct a low specific gravity reading on cell 4 of battery 1801B.
At that time a safety avaluatien was perforced by Engineering l
Support. This evaluation approved this use and identified r-o safety
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concerns.
The evaluation, steps 1.4 and 2.1, stated that the input I
and output breakers on the singis cell battery charger would provide l
adequate isolation of the comercial grade charger f rem the Class 1E battery.
On April 14, 1988, a decision was made to incorporate the us.e of the single cell charger into procedure 27915-C, General Battery Maintenance Procedure, as a part of Revision 4 to the procedure. A t.
that tire a cursory safety evaluation for the procedural r;bange was accomplished with no comments on the use of charger or the need to isolate the charger from the battery.
Af ter review of the above evaluat, ions, the inspector oyestioned the licensee's use of the charger on the Class IE battery and how this componen'. met the requirements of IEEE Standard 354, Criteria for Separation of Class IE Equipment and Circuits, and Regulatory Guide 1.75, Physical Independence of Electrical Systems, which the licensee committed to in FSAR Section 1.9.
The licensee's stated that the single cell charger was a temporary installation, used cnly for a short duration, and that the ac input
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4 i
breaker and de output breaker and fuses should provide sufficient protection to isolate the single cell charger from the Class 1E l
battery.
1he charger also contained an internal current limiting device. Therefore, the licensee stated that this single cell charger
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i met the intent of IEEE 384 and Regulatory Guide 1.75.
The licensee
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also stated that based on the above, use of this charger did not affect the operability of the Class 1E battery.
The licensee prepared a new safety evaluation dated August 22, 1988, to document
the use of the single cell charger.
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The acceptability of the use of a single cell battery charger is currently being reviewed by NRC.
This item will rer in unresolved pending completion of that review.
The Itcens e agreed to i
discontinue use of the single cell charger unet) this item is i
resolved.
This item is identified as URI 424/88-33-07.
The inspector reviewed recent actions taken by Chemistry for missed
)
and late surveillances. The missed surveillances were identified in I
LERs87-046, Waste Gas Decay Tank Sampling, and 87-071, Failure to Sample Diesel Fuel 011.
To correct the problem associated with the f atture to sample the diesel fuel oil, the inspector verified that steps had been added to the procedure for Unit I to ensure that any fuel delivered to the site was sampled and the Unit 1 TS were met prior to placing the oil in the ciesel fuel oil storage tank.
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To correct the problem associated with the missed surveillances.
Chemistry had added steps in procedures to provide trigger; for i
surveillances that must be accomp11shed under special conditions.
l Chemistry had also olaced a special erasable status board in the hot i
lab to track surveillances of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or less duration and other
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special conditions such as TS LCC action statement surveillances.
This provided coitinuously visible status of what surveillances were
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i assigned to each shif t, who was assigned to accomplished it, and when
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it was completed.
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The inspector noted that, the board was maintained current. A review of this board and procedure 34226-C, Technical Specification and
Routine Survet11ance Chanrel Checks and Source Checks of Digital i
Radiation Monitoring System (DRMS) Monitors, Rev.10, identified that all chemistry LC0 action statements were not listed on the status
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board, i.e., action statements 16,18, 33, 37, 45, 46A, 46B and 51.
The licensee stated that those were action statements which were not
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frequently entered and were therefore not i tsted on the board.
The
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inspector questioned this since it appeared that infrequently r
I occurring action statements were Fore likely to be missed.
The
.I licensee agreed to review all action statements for inclustun on the J
status board and revise the beard to include appropriate action j
staterents by September 9, 19SS.
I procedure 14825-1, Quarterly Inservice Valve Test, Rev.
6, was observed on RHR valves 1-HV-SSO4A, 1-FV-610A, 1-HV-8311A and
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1-HV-8812A. All valve stroke times were within 0.2 seconds of the previous tests and were acceptable.
During obsersation of the test it was identified that the main control board monitor status panel light for valve 1-HV-8716A did not work.
The control switch indication and the computer display information indicated that the valve was working correctly.
An MWO was initiated to correct the problem.
During the performance of the above test the CR0 was unable to locate the PE0 via the plant paging system. This resulted in the RHR train A and B hot leg cross connect valves 1-HV-8716 A and B being closed for approximately 30 minutes instead of the 3 minutes approximated in the Vogtle Safety Evaluation Report (SER).
The inspector observed that the procedure contained no note or caution about minimizing the time that these cross connect valves were closed.
The licensee agreed to add a note to assure the operator was cognizant of the limitations described in the SER. An additional operator had to be sent to locate the PE0 and transmit the message. The PE0 was located in the vicinity of 480V Motor Control Center (MCC) 1ABB but had not responded to the paging system and stated that the page was not heard.
Operations personnel stated that the installed paging and beeper systems did not cover all plant areas. The licensee agreed to
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review plant paging, beeper, and phone communications coverage.
The performance of procedure 24909-C, Personnel Airlock Door Seals Leak Rate Test, Rev. 0, was observed. The pre-test of the leak rate monitor was performed in the lab and then portions of the test were perfo-med again in the field after the equipment temperature staoilized.
The procedure did not specify this sequence, i.e., per the procedore, the leak rate monitor pre-test should have been performed at the field temperature canditions in its entirety.
In addition, the procedure required all steps be performed in sequence except as r.oted.
The procedure specified that three "leak test fixtures" were required to perform the flow verification in the pre-and post-tests, however, only two fixtures were provided by the manufacturer with one fixture utilized twice at different pressures.
The supervisor and technicians interviewed stated that step-by-stop compliance witn the procedure was required.
The failure to follow the procedure had no safety sign;ficancu, however, additional
.tanagement attention should be placed on the need to follow procedures or change the procedure to reflect what is done in the field.
The procedure triggering mechanism for the special condition surveillance of containment air lock leak rate testing was not clearly documented.
Adminstrative procedure 00303-C, Containment Entry, Rev. 5T, provided for control of entry to the containment during Modes 1, 2, 3, or 4.
The procedure required that the SS ensure tlat I&C performed the air lock surveillar.ce within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following air lock closing and at least once every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> during planc.ed multiple entries; however, implementing directions, such as
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recording of the I&C notification or tracking of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> surveillance time, were not contained it. any operating procedures.
Procedure 14900-1, Containment Exit Inspection, Rev. 5, triggered the air lock surveillance only after an outage and not under operating conditions.
The licensee stated that, in practice, I&C was ensuring that the surveillance was not missed.
I&C would call the control room each Monday, Wednesday, and Friday to find out if and when containment entries had been made.
Then I&C would accomplish the surveillance as required, and document it on a Surveillance Task Sheet.
However, this process was not formally proceduralized. The licensee agreed to formalize the I&C method of assuring that the containment air lock surveillance was not missed.
In addition, a discrepancy had been noted between Vogtle TS 4.6.1.3.a and 10 CFR 50 Appendix J.
...a TS required the air lock surveillance to be done within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of being closed. Appendix J states that testing is to be done within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of being opened.
This discrepancy was brought to the attention of the licensee as documented in NRC Inspection Report 424/88-30.
Inspection of air lock surveillances done for an approximate one year time frame indicated that the Appendix J requirements had been met.
NRC Inspection Report 424/88-30 had stated, however, that the licensee dould utilize the more conservative wording of Appendix J.
Implementation of the requirement appeared to be moot since the licensee immediately closes the containment airlock sfter openin2 in Modes 1, 2, 3 and 4.
The inspector notea, however, that praedure 00303-C required notification of I&C after closing and the surveillance task sheets which control the test state that the surveilance is required 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after entry.
The licensee agreed to revise these documents to assure that the Appendix J requirement was met.
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The review of a written trigger nechanism for containrent air lock surveillance and NRC review of +he discrepancy oetween 10 CFR 50 Appendix J and TS regarding testing after opening or closing the air lock will be identified as IF1 424/88-33-08.
A review of licensee performance in the areas of surveillance conducted prior to the start of the OPA indicated that the licensee had experienced problems in scheduling and completing surveillances within the tima limits allowed by TS. A review of LERs revealed 18 instances since June 1987 where surveillances had been completed outside TS time limits.
Based on the above information the inspectors reviewed QA audits conducted during the past year and QA engineering surveillance conducted in the past six months to determine licensee findings and corrective actions in this area.
The following audits and surveillance reports were reviewed:
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Surveillance Reports Date 1-TSS-88-1012 July 22, 1988 1-TSS-88-011 June 23, 1988 1-TSS-88-010 June 7, 1988 1-TSS-88-009 May 13, 1988 1-TSS-88-008 April 15,1988 1-TSS-88-005 March 1, 1988 1-TSS-88-004 February 29, 1988 1-TSS-88-003 February 29, 1988 1-TSS-88-002 February 9, 1988 1-TSS-88-001 January 7, 1988 QA Audit Reports Date OP09-87/21 July 17,1987 OP09-87/46 December 22, 1987 OP09-88/17 June 9, 1988 OP09-88/25 July 1, 1988 The above reports identified that: some surveillance procedures lacked mechanisms to trigger surveillance required under special conditions; temporary procedure changes were being designated as permanent without being incorporated; re-surveillances vere not being completed after maintenance or repair of equipment; dedicated surveillance coordinators were not assigned in all departments; Nuclear Plant Management Information System (NPMIS) computer data for post maintenance testing was not fully developed; procedures contained errors; and, personnsi errors and lack of attention to detail were causing many of t.he deficiencies.
The licensee formed a task force in June 1988 to determine the root causo and provide recommendations to correct the problems associated with surveillances-The task force determined the root cause of the late / missed surveillances to be a lack of attention to detail at the technician and sup+rs isor level. The task force also identified the need for additionai.'Jaagement attention te ensure that surveillances were accomplished as scheduled; that procedures were reviewed and appropriate trigger mecFanisms incorporated; and that a better scheduling and tracking system was implemented.
The licensee is in the process of developing and implementing a 28 day surveillance scheduling system. This system will schedule tests on a rotation that is within the TS requirements and will make surveillances more repetitive.
For example, the weekly battery test for Train "C" will be accomplished every Wednesday. This system will be fully developed by September 16, 1988.
The licensee plans to implement this schedule by the end of 1988.
To keep management better informed, an overdue surveillance attention list had been developed to inform management of any surveillance that
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had less than 25 percent of the grace period time remaining. An alert list also had been developed to identify surveillances on which the grace period is due to expire within one day.
Licensee management believes that this will lead to a reduction in missed surveillances.
The success of these changes will require further evaluation.
The inspector expressed a concern regarding the acceptability of a program that consistently allows use of the grace periods for surveillance testing rather than accomplishing the task when scheduled.
On August 22, 1988, the General Manager issued an internal letter to all managers, superintendents and supervisors to ensure that all employees were aware of the management position on timeliness of surveillance testing.
This letter placed responsibility on the b 7 to ensure that all surveillances are c.ompleted and on the responsible work group supervisors to notify the 0505 of problems in meeting deadlines for surveillance testing.
Management authorized the OSOS to prioritize and redirect work activities of all departments to ensure that surveillances are not deferred unless prudent operations or plant conditions warranted deferral.
In addition, a reporting mechanism for deferrals was established and the letter promulgated a managerent policy to accomplish surveillances without the use of the grace period unless prudent operation or plant conditions warranted deferral, e.
Equipment Clearance and Tagging The inspectors observed the installation of several clearances, ulked down exist'ng clearances and verified selected tags to evaluate licensee performance in these areas.
Procedure 00304-0, Equipment Clearance and Tagging, Rev. 14, provided guidanc.e on clear.r.ces and tagging.
The licensee utilizes a "clearance and tagging" office outside the control room. The office is staffed with an SCO qualified individual designated as Support Shift Supervisor (SSS).
An aggressivo and knowledgeable SSS reduced the work load on the SS and enhanced the effectiveness and efficiency of the clearance process.
Close communications between the SSS and the SS w re usually observed.
During observation of the installation of clearance 18804407, Nuclear Service Cooling Water (NSCW) Piping Penetration Cooling, several weaknesses were noted.
These included difficulty in locating the valves, numerous trips to obtain various required tools and equipment, attempting to drain the piping to an isolated drain, and failure to notify Health Physics of the resulting potentially contaminated overflow.
The inspector attributed some of these problems to inadequate preparation on the part of the PEO, but the majority was caused 'y a lack of coordination and instructions on the o
part of the SSS. Overall the inspector was concerned that inadequate guidance and coordination involving clearances for evolutions other
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than simple equipment. manipulations (draining, filling and venting)
could result in equipment damage or other problems.
Draining or
~ filling and venting of systems frequently requires close coordination between various departments, careful sequencing of valve manipulations and other guidance.
The licensee responded to these concerns by examin? g the clearance process and initiating revisions to the clearance co trol procedure to provide additional guidance on adequate preparation for hanging and removing a clearance and on l
special requirements for unusual evolutions.
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During the installation of a clearance involving NSCW Pump 4, the inspector observed an operator hang a tag on the pump hand switch, located on the shutdown panel, requiring the switch to be in the d
"pull-to-lock" position.
That particular switch did not have a
"pull-to-lock" position. Af ter the inspector pointed this out, the tag was corrected.
The clearance authorization sheet, which was
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computer generated, did state the correct position but the tag was
incorrectly filled out by the SS.
The inspector considered this
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is,ue to reflect a lack of attention to detail by the PE0 hanging the
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tag. Additionally during observations of independent verification actions, operators (in response to questions of..ow they knew they were looking at the correct train or switchboard) stated they "knew" this was the correct component.
Strict adherence to ucilization of proper component identification needs to be more heavily stressed.
The licensee indicated that these errors would be brought to the attention of licensed operators and PR0s, and additional emphasis
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would be placed on verifying tags against equipment.
No violations or deviations were identified.
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3.
Maintenance and Engineering Support of Plant Operations.(62/00, 62702, j
i-92700,71710)
l The inspectors reviewed various aspects of maintenance and engineering I
p ro g-t.m s that support safe plant operation.
These reviews included t-(
evaluations of post maintenance testing, inservice valve testing, control j
of temporary modifications, walkdowns of specific systems and general
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plant walkdowns accompanied by plant equipment operators and system r
i engineers, maintenance work ordar prioritization and backlog, a.
Post Maintenance Functional Testing i
i Procedure 00350-C, Maintenance Program, Rev. 12, stated that upon l
completion of the maintenance task and subsequent review of the work
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package by the Mcdifications and Outage Support Group (MOSG), the MWO package would be returned to the Work Planning Group (WPG) where a i
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functional or special test requirement would be assigned.
A functional test would be required to verify and document that systems
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and components worked on were capable of performing their intended l
functions.
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To determine the functional test assignment, the WPG used one of two reference documents. The first, the Addequip Database, was used for TS related components and specified wnich specific functional test procedure must be performed for that component.
The second, procedure 29401-C Maintenance Work Order Functional Tests, Rev. 2, was more generic in nature and provided general testing guidelines for non-safety related components.
Upon completion of the functional test assignment by the WPG, the MWO was routed to the responsible System Engineer for functional test concurrence.
If the System Engineer disagreed with the functional test assigned, he returned the MWO to the WPG for mutual resolution.
This review by the System Engineer was noted as a strength of the functicnal testing process.
The inspector reviewed the functional testing process with the objective to determine whether equipment maintenance was completed e f fec *.i vely, functional testing was clearly defined, test documents clearly identified acceptance criteria, and test requirements were
met.
To accomplish that review, the inspector selected several completed MW0s, including some related to post-modification testing, associated with the following systems:
ESF chillers, Chemical and Volume Control System CVCS). Containment Spray, Emergency Diesels, Safety Injection System and the Main Steam Isolation Valves (MSIVs).
From this review it was determined that an acceptable functional testing program was utilized by the licensee.
No violations or deviations were identified.
b.
Inservice Valve Testing In order to determine if operability problems existed with any safety-related valves, the inspector reviewed the data sheets for the last 10 months associated with procedure 14825-1, Quarterly inservice Valve Test, Rev. 7.
No significant problems were identified eencerning valve performance.
However, one example was r.oted of an MWO (18800897) where the worr. was completed on February 26, 1988, but had not yet been signed-of f by Maintenance Engineering. The valve, which was a main steam drain valve, had been replaced in a subsequent MWO.
MWO 18800897 had been reviewed by Operations to ensure that work was completed and the valve had been stroke time tested monthly by Operations since the completed work and had tested successfully each time.
The inspector expressed concern regarding exercising and stroke time te. ting of valves as described in procedure 14825-1. This procedure specified that valve exercising would normally precede stroke time testing of the valve.
This practice appeared to deviate from the intent of the American Society of Mechanical Engineers (ASME) Code,Section XI, Subsection IWV, Article IWV-3000, Test Requirements.
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To address that concern, the licensee revised procedure 14825-1, and procedure 14850-1, Cold Shutdown Valve Inservice Test, Rev. 7 to state that: (1) timing should be performed during exercising of a valve unless system conditions and/or other limits prohibit this; then the valve shall be stroke timed first; and (2) that stroke time tests shall be performed first if tests are completely separately.
An entry was also made in the Night Order Book in the control room
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which advised the operators of this procedure change. The corrective actions of the licensee resolved the concern of the inspectors.
No violations or deviations were identified, c.
Temporary Modifications During the assessment, the inspector reviewed the status of temporary modifications. As of August 25, 1988, there were 89 active temporary modifications of which 31 were safety-related. The 31 safety-related temporary modifcations can be further broken down into 18 electrical modifications (the oldest of which became active on October 30,1987)
and 13 mechanical modifications (the oldest of which became active on November 18, 1987).
Two safety related temporary modifications were discussed with the cognizant engineers and walked down in the field.
The first temporary modification walked down was 1-87-479, the replacement of sof tware in the Alternate Shutdown Irdication System.
The second temporary modification walked down was 1-88-030, the correction of phase rotation to 160 relays on the emergency diesels.
Both temporary modifcation; appeared to be adequate and in compliance with procedure 00307-C, Temporary Modifications, Rev.4.
No violations or deviations were identified.
d.
Systen Walkdowns During the assessnelt, the inspector conducted partial system
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walkdowns of the component cooling water system (CCW). A portion of the walkdown, primarily the A train, was conducted with the System Engineer.
In addition, a portion of the walkdown was performed with a PE0 with the majority of the time being spent on the B train of the system.
The walkdowns were conducted using piping and instrumentation drawings IX40B136, Rev. 22, and 1X4DB137, Rev. '; and system procedures 11715-1, Component Cooling Water System Aligratent for Startup and Normal Operation, Rev. 2 and 14551-1, CCW Flow Path Verification, Rev. 1.
The walkdown was performed to verify proper labeling of co.npon e n t s, proper locking of locked valves, general housekeeping, scaffolding, control and overall equipment condition.
Discrepancies noted during the walkdown included missing valve position indicators, labeling discrcpancies, missing haldwheels, bent instrument tubing and inaccessible valves.
Specific examples were provided to the licensee.
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Other than the above items, all attributes checked were found to be satisfactory.
This included the satisfactory review of data l
generated by the performance of the CCW pumps and discharge check i
valves inservice test per procedure 14803-1, CCW Pumps t.nd Discharge i
Check Valves Inservie Test, Rev. 4, performed on August 10, 1988.
Other positive aspects of the system included the absence of any
significant MW0s egainst the system as well as no temporary
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modifications to the CCW system.
Finally it should be noted that i
both the System Engineer and the PE0 that accompanied the inspector
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on the system wal(down nad very positive attitudes about their work l
and were knowledgeable of the CCW system.
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A similar walkdown of selected portMns of the RHR system was
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conducted with the System Engineer. Procidure 11011-1, Residual Heat
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Removal System Alignment for Startup and Normal Operation, Rev. 5,
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was used during the walkdown alcng with Drawing 1x4DB122, P&I Diagram l
for Residual Heat Removal System No. 1205, Rev. 25.
Several
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discrepancies were observed, which were identified to the licensee
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for corrective action, including:
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A valve position indicator showed open when the valve was
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Plastic name tags were reversed on two valves.
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t The NPMIS computer location for four valves was wrong.
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Access to some valves was inadequate without the use of
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A loose ladder was found leaning against piping in an RHR
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An old 'Do Not Operate' tag, apparently left from
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suction valve.
l The RHR system engineer was knowledgeable about the system, including f
current conditions and historical problems.
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No violations or deviations were identified.
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Plant Walkdown i
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j The inspector conducted a walkdown of Levels B and C of the Auxiliary i
Building.
The following observations were made, j
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B Level - Recombiner 2 valve gallery.
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~everal remote valve operators did not have open/close position
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labeling on the valve stem body.
It appeared that the valve
i operators had been painted and new labeling had not been
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installed.
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B Level - SI pump room A Leaking drain valve off CVCS Charging Pump /SI Pump Suction Cross
- Tie Line.
Drip basket under valve with line to floor drain.
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Deficiency tag hung on leaking valve - dated September 17, 1987-nearly a year old.
Valve did not have an identification ac tag.,
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C Level Two ladders stored on floor behind Switchgear INB21 (contained breaker for CVCS positive displacement pump).
No wall bracket or tie-down was available for those ladders.
Could also be a missile hazard when removing ladders from behind switchgear.
Iri general, housekeeping was acceptable. However, several panels and control cabinets had apparently not been repainted since the unit was under construction.
Also, the floor paint at several locations was cracked and peeling. Additional emphasis was needed on applying and
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maintaining coatings for supports and floors.
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On August 12, 1988, during a plant tour, inspectors observed an alectrician who was not wearing the required parsonnel monitoring d
device or picture badge.
10 CFR 20.?02(a) requires that each licensee shall supply appropriate personnel monitoring equipment to, and shall require the use of such equipment by each individual who enters a restricted area under such circumster.ces that he recieves, or is likely to recieve, a dose in any calendar quarter in excess of 25 percent of the applicable value specified.
requires picture badges to be displayed by all individuals while inside the protected area.
Technical Specification 6.7.1 requires that written procedures shall be established, implemented, and rnaintained covering the activities as recommended in Appendix "A" cf Regulatory Guide 1.31, Revision 2, February 1978, Section 7.e.(7),
Personnel Monitoring and Section 1.a. Security and Visitor Control.
Technical Specification 6.10.1 requires that procedures for personnel radiation protection shall be prepared consistent witn the requirements of 10 CFR Part 20 and shall be approved, maintained, ard adhered to for all operations involving personnel radiation exposure.
Administrative procedure 00950-C, Personnel Dosimetry Program, Rev.
6, requires each individual, who has an assigned thermoluminescent dosimeter (TLD), will wear the TLD at all times while inside the Radiation Control Zone (RCZ). Additionally, 00950-C requires that prior to entering the RCZ or any Radiation Control Area (RCA), the individual will select and wear a whole body Direct Reading Device.
Failure to wear the required personnel monitoring device and picture badge is identified as violation 424/88-33-09.
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f.
Maintenance Work Order Control and Backlog Status The inspector reviewed the Kd0 backlog status, method of licensee I
backlog review, adequacy of MWO priority assignments, and percentage of MW0s which were safety-related.
For the eight week period ending August 21, 1988, the average of i
corrective MWO's yet to be worked, which included safety and l
non-safety-related MW0s, was approximately 800.
Approximately 250, or 31 percent, were safety-related. Thirty-eight percent of the 800 were greater than 3 months old which was well below the industry l
average of 52 percent.
When all MWO's are considered, including corrective, preventive, facility and outage, the total backlog was 2094, Of these total MW0s, 38 percent were corrective, 29 percent were preventive, (s 7 percent were facility and 26 percent were outage related.
Approximately 51 percent of all MW0s were assigned to mechanical maintenance, 24 percent to I&C, 19 percent to electrical and 6 percent to the outage support group. Of the 380 MW0s which were restrained from working, 29 percent were due to engineering restraints, 32 percent were related to material restraints, and 39 percent were due to other restraints.
Work schedulers conducted a daily review of outstanding Kd0s by priority code to determine what packages could be worked.
Also reviewed were those Knos identified as the 40 oldest.
The Superintendent of Work Planning conducted a daily review of the 20 oldest Knos for possible work.
It was apparent that several levels of review were in place to monitor Kd0 backlog. The oldest KWO was routinely identified at each Plan nf the Day (P00) meeting and the Daily Operatiens Meeting.
The inspector determined that all outstanding MW0s were adequately reviewed prior to any reactor mode change. Each of the 12000 series Operations procedures, i.t.,
those procedures controlling mode changes, required that all outstanding KnOs related to the mode being entered be reviewed prior to the mode change. Outstanding KnVs were first reviewed by a qualified (licensed or formerly licensed) person in the planning group. Any Kd0 of concern would be identified to Operations where the decision concerning its importance relative to the mode change would be evaluated.
The inspector evaluated those Kats related to a startup mode change which occurred on July 31, 1988.
None of the Kats outstanding at that time would have prevented a startup of the unit.
Work priority was assigned by an Operations Planner in the Outage and Planning Group. Guidance was given for the priority assignment in Procedure 29402-C, Work Planning Group Work Order Processing, Rev. 3.
The Operations Planner reviewed the previous work history on the equipment, then used the Equipment File of the NPMIS to identify TS
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items.
No concernt were-noted ~ with the manner in which work priorities were esta51v,hed.
In conclusion, the. process of reviewing and ultimately controlling the MWO backlog was noted to be well managed by the licensee.
No violations or deviations were identified.
g.
Calibration of Instrumentation The inspector reviewed the instrument calibration program to determine if appropriate instrumentation was in a periodic calibration progru..
The instrument calibration program was comprehensive except for the following discrepancies.
Level transmitters 1-LT-1606 and. 1-LT-1607 and associated instrumentation for the NSCW tower basin were not included in a routine calibration program.
TS 3.7.5 requires that the Ultimate Heat Sink be operable.
The surveillance required by TS 4.7.5 includes verifying the water level of the' NSCW tower basin which is monitored by 1-LT-1606 and 1-LT-1607.
1-LT-1606 and 1-LT-1607 were originally calibrated on June 13, 1986. The licensee stated'that the calibration frequency was once per 12 months, therefore, the calibration had been missed for two years.
The licensee had identified that the level transmitters were not in the calibration program on June 28, 1988 and initiated Planned Maintenance Change Request forms to include the calibrations. However, the transmitters were not incorporated in the calibration program at the time of this inspection in August 1988.
TS 6.7.1 requires that procedures be implemented covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2 including calibration of safety-related water storage tank level instrumentation.
FSAR Table 7.5.2-1, Post Accident Monitoring Instrumentation, lists the instrumentation required to meet Regulatory Guide 1.97, Instrumentation for Light Water Cooled Nuciear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, Rev. 2.
Letdown flow is included in this list.
Flow transmitter FT-132 is utilited by the licensee to nonitor letdown flow.
TS 6.7.4.e requires the licensee to establish a program to ensure the capability to monitor plant variables and systems operating status during and following an accidet.
The program is to include the Category 2 and 3 instrumentation identified in Regulatory Guid) 1.97 and provide for periodic maintenance and surveillance of the instrumentation.
The inspectors determined that letdown flow instrument FT-132 had not been included in the instrument calibration program. The licensee indicated that the calibration frequency for FT-132 should be once every 12 months.
The failure to periodically calibrate NSCW 1evel transmitters 1-LT-1606 and 1-LT-1607 and letdown flow instrument FT-132 as
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required by TS 6.7.1 and 6.7.4, respectively, is identified as violation 424/88-33-10.
Also during the review, it was noted that the licensee did not have a single source program that described how the requirements of TS 6.7.4.e were met. This TS required a program to provide preventive maintenance, surveillance, preplanned operating procedures and back-up instrumentation to be used if one or more monitoring instruments became inoperable, and administrative procedures for returning inoperable instruments to an operable status as soon as practical for accident mcnitoring instrumentation required by Regulatory Guide 1.97.
The initial review of implementation of the program revealed that FT-132, discussed above, was not being calibrated. The licensee is conducting a review of the various plant programs covering periodic maintenance, surveillance, and operations procedures to confirm that all Regulatory Guide 1.97 instrumentation is covered.
This review was identified as an URI 424/88-33-11.
h.
Engineering Support Department The Engineering Support Department consisted of approximately 56 engineers who are divided into system or discipline groups. As noted in other sections of the report, System Engineers were knowledgeable of system design, maintenance deficiencies and proposed design changes.
In addition, System Engineers provide concurrence for functional tests assigned to maintenance work orders.
Safety evaluations for several DCR packages were reviewed to determine if the proposed change examined the possible affect on the FSAR and TS or involved an unreviewed safety question.
The appropr', ate considerations had been addressed.
The DCR pac.kares were complete and well documented, and were presented in a manner which was auditable and understandable to a reviewer. DCR packages were correctly assembled and reviewed prior to being released for field trwlomentation.
The licensee stated that there existed t. god. working relationship with the Project Field Engineering Organization which consisted of Becthel and Southern Company Services enginears. The licensce's current backlog of approximately la months of DCRs have been reviewed and prioritized.
Review of this backlog indicated that design changes had been requested by various plant departments.
These changes were directed at improving system reliability and f acilitating operations and maintenance activities.
Goals expressed by the Superintendent of Engineering Support included shortening the response time for answers to Request for Engineering Review (RER) and to keep the requesting individual abreast of the RER's status.
General observations pertaining to the Engineering Support Department include active participation in correcting plant deficiencies, integration with the plant activities and a willingness by various
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plant departments to call upon the engineering support department for assistance in correcting problems and analyzing information.
The licensee has helped to foster cooperation with the engineering depa.rtment via the use of a Duty Engineer which provides the plant with a point of contact to ensure that plant status and required engineering action items are communicated to the appropriate engineering department.
No violations or deviations were identified.
4.
Review of Programs for Management Assessment of Quality (30702, 40700, 37700)
Various programs which are designed to provide management with indications of problem areas and to assure that problems are corrected were reviewed to assure effective implementation of these programs.
In addition, the inspectors reviewed the findings in all areas inspected during the OPA to determine if management was effectively achieving the QA goals set forth in Appendix B to 10 CFR 50.
The findings of this report indicate that plant management was generally effective in establishing and implementing appropriate controls over plant operation.
The licensee had adequate methods to identify major problem areas and action plans (paragraph 4.a) and comprehensive programs to identify, review and resolve other levels of deficiencies (paragraph 4.b and c).
A review of the major issues identified by plant management for action as of July 1988, indicates that many of the weak areas identified by this report have also been identified by the licensee's management.
These include manager and supervisory effectiveness, implementation of plant administrative control and management directives, "in the field presence" o4 managers and supervisors, attentien to detail, and establishment of a
"no missed surveillance" program.
Although many of the planned actions to resolve these problems have been completed, this inspection documents additional examples of inattention to detail and procedural adherence problems that indicate that these problems still exist.
In particular, the findings include many items that should have been observed by managers and supervisors during in-the-field reviews of activities.
In response to these findings, the licensee stated that plant management would re-evaluate their corrective action programs to determine how the current approaches could be changed, strengthened or expedited to resolve the problem areas.
a.
Management Involvement Interviews were conducted with the Plant Manager to discuss short and long term goals, performance indicators used by management,
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communication between management and staff, identification and corrective action for problem areas, management's direct involvement in plant activities, and utilization of engineering support by piant management.
The Plant Manager stated that meetings were held weekly between the General Manager, Plant Manager, Support Manager and Controller.
Weekly meetings were also held between the department heads and plant managers.
Plant management conducted monthly meetings with the approximate 100 supervisors at the plant and produced video tapes which were presented to all plant employees on a quarterly basis. A plaat newspaper was printed and distributed to plant employees monthly.
To further promote communications and teamwork between departments, plant management formed an Operations Management Council (OMC) which consisted of key plant managers.
The OMC identifies and develops action plans to resolve major plant problems and oversees the work of the Plant Review Board (PRB). A list of approxit.4ately twenty top priorty technical items were identified.
In addition, a list of top priority management issues were identified.
The management issues included:
signs and labels
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radiological sensitivity
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manager and supervisory effectiveness deficiency card program improvements
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work control improvements
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Under the manager and supervisor effectiveness action plan, the
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licensee had defined a detailed problem statement which included deficiencies in transmission of direction and expectations from management to the workers, transmission of problems l' rem workers, in-the-field presence of supervisors, knowledge of administrative and management directive control, and attention to detail.
An action plan had been developed for resolution of these issues. The majority of the line items had been completed.
i The Plant Manager stated that a Management Duty Officer (M30) concept was used for response to plant incidents and problems ano to provide management involvement in field activities.
The MD0 program was
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being revised based on the recommendations of an ISEG study to include detciled checklists for field observations of plant activities.
An electronic mail system was available to all managers and was utilized to communicate routine requests for assistance and coordination between managers.
Performance indicators, plant and problem status information and various other information services were available on a real time basis to plant management through the computer system.
One feature involved periodic tests on administrative requirements and procedure changes to ensure management remains cognizant of these areas.
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Plant management had established a meeting policy which restricted the time in each meeting to one hour and required all routine meetings to be held prior to 2:00 p.'.n to ensure that managers had adequate planning time in the afternoons. Attendance in meetings was also controlled to ensure effective use of time.
Management also supported policies to promote direct field supervision by first line and higher management.
No violations or deviations were identified.
b.
Review of Quality Assurance Organization Audits and Activities The inspector reviewed the requirements of TS 6.4.2.8 on the scope and frequency of audits in conjunction with the audit planning matrix and schedule. The inspector confirmed that the planning matrix and schedule addressed all TS requirements.
Review of the QA audits in the operations area indicated audits lacked technical content. QA audit OP06-87/16 examined shif t relief and turnover as required by FSAR and TSs and the incorporation of these requirements into procedures.
Conclusions reached by the audit partain only to the correct incorporation of requirements into procedure and signatures and checkoffs rather than the accurate transmittal and understanding of turnover knowledge.
QA audit OP06-88/25 reviewed various procedures associated with PE0 s turnovers and shift rounds. Again, conclusions reached by the audit pertain only to signatures and check offs rather than the accurate transmittal and understanding of turnover knowledge.
Shift round observations document that the rounds were done and not on the thoroughness and accuracy of information obtained. QA audic OP21-88/01 reviewed the DCR program.
Conclusions reached by the audit concentrated on the mechanics and not the material content of the DOR's.
Examination of the qualifications of the auditors performing the operations audits indicated an overall lack of commercial nuclear power plant operational experience.
The QA manager stated an awareness of the lack of operational experience and outlined plans to correct this deficiency. Plans included the addition of individuals with operations experience and rotation of individuals from the Operations group into QA for period; of tima.
The inspectors consider this an appropriate action to strengthen the ability of the QA departments ability to effectively audit the Operations department.
Review of responses to QA Audit Finding Reports ( AFR) indicated a high threshold for root cause and corrective action responses.
QA AFR 229-11, dated December 22, 1987, delineated the f ailure by the chemistry department to take samples when PERMS monitor RE-0013 read
"zero" for seven days.
The response defined the root cause as the
"procedure was too restrictive in requiring samples when the monitor was operational." The corrective action was to revise the procedure so that when RE-0013 reads "zero" and previous averages also raad
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"zero," then "zero" is a valid reading and therefore sampling is not required.
The QA AFR 229-11 response, accepted by QA, failed to address the failure by the personnel involved to follow the procedure.
Subsequent AFR 236-11 dated February 1988, highl1ghted numerous findings within the chemistry department which were judged to have been the result of the failure of chemistry department personnel to follow procedure.
The licensee's response to AFR 236-II adequately addressed the root cause.
No violations or deviations were identified, c.
Deficiency Card Trending The licensee had in place a deficiency card system governed by administrative procedure 00150-C, Deficiency Control, Rev. 8.
This system provided the licensee's staff with a mechanism for reporting deficient conditions, and the prompt review by the shift supervisor for immediate action or reportability.
Additional review was performed by Nuclear Safety and Compliance (NSAC) to determine if the deficiency was significant.
NSAC issues a quarterly trend report which delineates total DCs written and against which department the DC was written with the associated DC cause codes.
Each department is required to evaluate pertinent data and initiate root cause analysis and corrective actions, as required, lhe trend report provides present and previous quarter trends and rolling year and cumulative total trends.
The trend report does not provide a break down for cause codes on a plant wide basis, but rather only on a departmerital basis.
Information conveyed to the department heads via the trending program will assist in the correction of identifiad problems.
The NSAC manager will review the trending report for the incorporation of plant wide cause codes trending information to further assist plant management in the identification of plant wide deficiency trends. The NSAC manager has taken corrective action to shorten the amount of time between the end of tne quarter and the publication of the quarterly trend report in ordar to provide more timely information to plant management.
No violations or deviations were identified.
d.
Plant Review Board The activities of the PRB were reviewed to determine if it was functioning in accordance with the plant TSs, providing adequate interf ace with various plant disciplines, and performing adequate safety reviews.
The review consisted of inter $ iews with various PRB meubers, review of TS Section 6.4.1, review of administrative procedure 00002-C, plant Review Board - Outies and Responsibilities, Rev. No. 8, observation of a PRB meeting, and review of selected minutes of PRB meeting '
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Administrative procedure 00002-C adequately implements the requirements of TS Section 6.4.1.
The TS specify a meeting frequency of at least once per calendar month.
In actuality the PRB meets Tuesdays and Thursdays, or more often as requested by any member. As noted in the various regularly scheduled plant status meetings, the PRB is also characterized by active pr.rticipation and uninhibited communications.
Membership on the PRB consists of managers /
superintendents or supervisory personnel reporting directly to the department managers / superintendents from NSAC, Engineerica Support, Quality Control, Health Physics, Maintenance, and Operations.
The PRB is of ten assisted in the review of an item by a representative of the department sponsoring the item.
This facilitates communications and provides real time answers to questions raised. A review of items approved by the PRB revealed no discrepancies.
The PRB was observed reviewing and taking action on various reports, procedures and startup test procedures.
It was noted that several safeguards and startup test procedures were reviewed during the meeting.
Items to be to be discussed at the PRB are generally reviewed prior to the meeting.
The issue of procedures not being reviewed prior to the PRB was addressed by the OMC. Other items addressed by the OMC concerning the manner in which the PRB conducts business included meeting attendance, the tabling of issues, staff rotation, and in meeting review of procedures.
The aggressive approach taken by the OMC through the monitoring and constructive feedback are positive steps te ensure the PRB effectively executes its responsibilities.
No violations or deviations were identified.
e.
Independent Safety Engineering Group An ISEG was established for the plant as required by TS 6.2,3.
Staf fing of the ISEG complied with TS raquirements.
The inspector interviewed members of the ISEG staff and examined ISEG reports which documented reviews of LCO's, draft LER's and Special Projects.
Review of the carious reports generated by ISEG indicate a wide range of topics examined, including some of noted positive herefit to the plant. Such projects included a safety system functional inspection on the auxiliary feedwater system, review of the management duty officen program, and expansion of the trending program for the DC program.
The narrow scope of other ISEG examinations effectively eliminated the opportunity to fully examine the subject area for additional problem areas. Reports generated on LCOs, met the stated objectives and were completed in a short time period, but examined only the entrance and exit from the LCO.
The aspects of equipment failure, prior H40 and engineering involvement were not addressed.
While it is understandable that all areas of ISEG examination will not receive exhaustive exam nation, it was apparent that some warrant more consideration than others.
Discussions with the ISEG manager
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conveyed knowledge of the LCO report's brevity, and that the reports were intended to document only the correct entrance and exit for LCOs.
Future objectives for ISEG were also discussed with the ISEG manager.
These objectives included:
1)
Examination of industry and plant issues to identify potential areas for improving plant safety and reliability.
2)
Performance of independent technical reviews and surveillances of plant activities to verify quality performance and to identify areas for improving safety and reliability.
3)
Assessment of the uverall quality and safety of plant activities and advise management.
4)
Training and development of ISEG personnel to increase their technical expertise.
Completion of the projected ISEG objectives will assist in an organized and independent assessment of plant activities, adding to improved plant safety.
No violations or deviations were identified.
f.
Plant Status Meetings Various regularly scheduled plant status meetings were attended to determine the amount of direct involvement of management in the resolution of identified deficiencies, the accuracy and adequacy of the status information presented, and whether day-to-day plant activities and planned future activities were beirg adeauptely disseminated to the appropriate staff members.
These meetings inci;ded a 7:00 am satus, 8:00 am engineering staf f, 9:00 an daily operations and s 1.00 pm scheduling for +he POD.
Some problems
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addressed in the 9:00 am daily operations meeting received hoichtened attention at an ensuing "break out meeting."
All meetings were characterized by active participatio.1, uninhibited communication, and adequate multi-disciplinary attendance.
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Additionally, it was apparent that individuals were accountabla for their their specific area of responsibility and able to address questions pertaining to their current status and scheduling needs.
Overall, members of the plant management staff were cognizant of plant status, ongoing or planned activities, specific and general problem areas, and directly involved in the resolution of identified deficiencies.
The various meetings effectively allowed management to disseminate information including short and long term goals.
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g.
Operating Experience Review The inspector evaluated the licensee's program for reviewing and r-
.. ding to NRC I&E notices (IEN).
Procedure 00414-C, Operating Experience Program, Rev. 5 established organizational responsibilities and implementation instructions to ensure that pertinent operating experience information was supplied to appropriate plant personnel.
To accomplish the evaluation, 18 IENs
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were selected to audit the licensee's responses and corrective actions. Based on the thoroughness of the responses to those 18 IENs it appeared that the licensee had a good program for IEN review. The following IENs were therefore closed.
IEN 84-44 IEN 86-04 IEN 87-28 IEN 84-58 IEN 86-64 IEN 87-53 IEN 84-88 IEN 86-74 IEN 87-59 IEN 85-02 IEN 86-80 IEN 87-60 IEN 85-50 IEN 87-01 IEN 88-20 IEN 85-72 IEN 87-23 IEN 88-39 The licensee developed a program to address the recommendations of Institute of Nuclear Power Operations (INP0) Significant Operating Experience Report (SOER) 86-3, Check Valve Failures or Degradation.
Preventive maintenance procedures had been established for check valves in those systems recommended by the SOER, The 50ER further ecommended that a design review be performed for those check valves in the concerned systems.
The licensee plans to have the initial design review completed by each designated system engineer by January 31, 1989 and the final design review completed by April 1,1989.
No violations or deviations were identified.
5.
Action on Previous Inspection Findings (92701, 92702)
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(Closed) IFI 424/86-11/-07, 01screoancies in Equipment Labeling. Items b through h of the IFI were closed in NRC Inspection Report 424/87-42.
Item a involved a name tog that was missing fro.n RHR valve HV-87018. The t
inspector observed that a nee name tag for the valve had been made, and was scheduled for installation during the next outage.
This IFI is closed.
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(Closed) Deviation 424/88-07-01, Natural Circulation Cooldown Limitations.
The deviation identified that the E0Ps which cover natural circulation cooldown lacked adequate direction on the use of the cooldorn limitations curve. Specifically, each of these E0Ps direct the operator to maintain Reactor Coolant System (RCS) temperature and pressure withit. the limita of TS 3.4.9.1, Figure 3.4-3 (cooldown limitations curve).
Figure 3.4-3 was not labeled as to which temperature instruments should be used for comparison to the curve, nor did the information appear in the E0Ps.
To resolve this concern, the licensee has revised the E0Ps to direct the l
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operators to maintain cooldown rate based on cold leg temperature.
The licensee has also initiated the necessary action to revise TS figure 3.4-3 to be more specific.
A draft copy of this figure was reviewed and the inspector determined that the reference included in the~ figure to the lowest indicated RCS cold leg temperature was adequate.
(0 pen)
IFI 424/86-117-09, Implementation of Reactor Vessel Level Indication System (RVLIS) Vendor Manual Requirements. This IFI identified a concern with the apparent lack of a control room annunciator to alert operations personnel of a RVLIS hydraulic isolator failure.
This alarm would annunciate when the hydraullic isolator reached a displacement of
+0.4 cubic inches. The Westinghouse Technical Manual indicates there are no alarms provided for RVLIS. In addition, it is recommended that a main centrol board annunciator should be installed.
Discussion with the licensee and a review of the RER generated as a result of this concern indicated that the licensee believed the alarm function was provided for within the remote plasma display monitor.
The remote plasma display, located in the control room, depicted among other items, the RVLIS system and its associated components.
The alarm function discussed by the licensee is located on "detail data page three," one of several available screens, The alarm consisted of the word "offscale" which would appear below the component if a failure were to occur.
It should be noted that this screen must be manually selected and that there was no audible signal associated with the alarm.
The alarm function described above would be sufficient only if the "detail data page three" screen was selected at the time of a failure. However, the concern remains since the operator could have another screen selected at the time of the failure and therefore not be aware of the alarm.
This item will remain open pending further review by NRC.
(0 pen) IFI 88-07-03, Use of Technical Specification Cooldown Limits Curyc in Requalification Training for Licensed Operators.
Discussion with the licensee indicates the lesson plans associated with this concern have r.ot
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bean developed yet.
This item will remain open pending completion and review of the applicable lesson plans.
6.
Exit Interview (30703)
The inspection scope and results were summarized on September 13, 1988, with those persons indicated in paragraph 1.
The inspectors described the inspection findings and discussed in detail the inspection findings below.
No proprietary information is contained in this inspection report.
Item Number Description / Reference Paragraph 424/88-3..J',
Violation - Failure to perform a safety evaluation for a change to an annunciator described in the FSAR.
(paragraph 2.a.(2))
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424/88-33-02 IFI - Review of operation with a ground in the vital de bus.
(paragraph 2.a.(2))
424/88-33-03 Violation - Failure to control the issuance of dacuments, including changes, which prescribe activities affecting quality, specifically controlled copy 125 of the FSAR.
(paragraph 2.a.(5))
424/88-33-04 IFI - Examine.the licensees evaluation of PE0s ability to gain access in the event power is lost to the card readers.
(paragraph E.a.(13))
424/88-33-05 Vialation - Failure to take corrective act'ons in the case of significant conditions adve'se to quality in order to preclude repetition.
(paragraph 2.c)
424/88-33-06 Violation - Failure to revise the ACOT procedu'e to contain the correct calibration data.
(pa,agraph 2.d)
424/88-33-07 URI - Review of the acceptability of the use of a single cell battery charger on Class 1E batteries.
(paragraph 2.d).
424/88-33-08 IFI - Review of the written trigger mechanism for containment air lock surveillance and NRC review of the discrepancy between 10 CFR 50 Appendix J, and TS regarding testing after opening or closing the air lock.
(paragraph 2.d)
424/38-31-09 Violation - Failure to wear the required personnel monitoring device and picture badge. (paragraph 3 4)
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424/88-33-10 Vie 1ation - Failure to periodically
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calibrate N$CW level transmitters 1-Li+1606 and i-LT-1607 and letdown flow instrument FT-132 as reqaired by TS 6.7.1 ann 6. /.4, respectieely.
(paragraph 3 9)
424/88-33-11 URI - Review of plant programs covering periodic maintenance, surveillance, and
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operations procedures to confirm that all Regulatory Guide 1.9/ instrumentation is covered.
(paragraph 3.g)
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ABN As-Built Notice ac Alternating Current ACOT Analog Channel Operational Test AFR Audit Finding Report ASME American Society of Mechanical Engineers CCW Component Cooling Water CR0 Contral Room Operator CVCS Chemical and Volume Control System DC Deficiency Card de Direct Current DCR Design Change Request DRMS Digital Radiation Monitoring System
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E0P Emergency Operating Procedure FSAR Final Safety Analysis Report I&C Instrumentation and Controls IEN Inspection and Enforcement Notice IFI Inspector Followup Item INPO Institute of Nuclear Power Operations ISEG Indeper ent Safety.Engineerfng Group LCO Limit',ng Condition for Operation LER Lice.nsee Event Report MCC Motor Control Center MD0 Management Duty Officer MOSG Modifications and Outage Support Group MSIV Main Steam Isolation Valve MWO Maintenance Work Order NDRMS Nuclear Operation Records Management System NPMIS Nuclear Plant Managenent Information System NRC Nuclear Regulatory Commission NSCW Nuclear Service Cooling Water OMC Operations Management Council OPA Operational Performance Assesment 0505 On-Shift Operations Superintendent PE0 Plant Equipment Operator l
900 Plan of the Dry PRS Plant Review Board QA Quality Assurance RCA Radiation Control Area RCS Reactor Coolant System
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RCZ Radiation Cnntrol Zone
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RER Request for Engineering Review
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RHR Residual Heat Remoaal System RVLIS Reactor Vessel Level Indication System SALP Systematic Assessment of Licensee Pteformance SER Safety Evaluation Report SOER Significant Operating Experience Report SRO Senior Reactor Operator SS Shift Supervisor TS Shift Support Supervisor
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,CP Temporary Change to Procedure
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TLD Thermoluminescent Oosimeter TS Technical Specification VHS Ultimate Heat Sink URI Unresolved Item WPG Work Planning Group
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