ML18087A624
| ML18087A624 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/01/1982 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18087A623 | List: |
| References | |
| NUDOCS 8301140418 | |
| Download: ML18087A624 (36) | |
Text
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PDR OSURE 2 U.S. NUCLEAR REGULATORY COMMISSION REGION I SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE PUBLIC SERVICE ELECTRIC AND GAS COMPANY SALEM NUCLEAR GENERATING STATION NOVEMBER 1, 1982
l I
TABLE OF CONTENTS I. Introduction 1.1 Purpose and Overview..
1.2 SALP Board and Attendees 1.3 Background..
II. Summary of Results III. Criteria IV. Performance Analysis 4.1. Plant Operations 4.2. Radiological Controls 4.3. Maintenance 4.4. Surveillance.....
4.5. Fire Protection 4.6. Emergency Preparedness 4.7. Security and Safeguards 4.8. Refueling/Outage Activities 4.9. Licensing Activities..
V. Supporting Data and Summaries 2
2 3
5 6
7 10 12 13 14 16 17 19 20 5.1. Licensee Event Reports.
22 5.2. Investigation Activities 25 5.3. Escalated Enforcement Actions 25 5.4. Management Conferences During the Assessment Period 25 TABLES Table 1 - Tabular Listing of LER's by Functional Area 26 Table 2 - Violations Table 3 - Inspection Hours Summary Table 4 - Inspection Activities..
ATTACHMENTS - Enforcement Data.....
28 29 30 33
I.
INTRODUCTION
- 1.
Purpose and Overview
- 2.
The Systematic Assessment of Licensee Performance (SALP) is an inte-grated NRC staff effort to collect the available observations on an annual basis and evaluate licensee performance based on those obser-vations with the objectives of improving the NRC Regulatory Program and licensee performance.
The assessment period is September 1, 1981 through August 31, 1982.
This assessment, however, includes pertinent activities and NRC ob-servations of licensee performance through October 1982.
The prior SALP assessment period was July 1, 1980 through June 30, 1981.
Sig-nificant findings of this assessment are provided in the applicable Performance Analysis Functional Areas (Section IV).
Evaluation criteria used during this assessment are discussed in Section III.
Each criterion was applied using the 11Attributes for Assessment of Licensee Performance 11 contained in NRC Manual, Chapter 0516.
SALP Board:
Other Attendees:
R. W. Starostecki, Director, Division of Project and Resident Programs, Region I T. T. Martin, Director, Division of Engineering and Technical Programs E. J. Brunner, Acting Chief, Projects Branch No. 1, Division of Project and Resident Programs R. R. Keimig, Chief, Projects Branch No. 2, Division of Project and Resident Programs W. Ross, Licensing Project Manager, Operating Reactors Branch No. 1, Division of Licensing, Office of NRR L. J. Norrholm, Senior Resident Inspector, Salem Nuclear Generating Station R. Summers, Resident Inspector, Salem Nuclear Generating Station W. J. Lazarus, Project Engineer, Projects Section 2A, Division of Project and Resident Programs 2
r
- 3.
Background
(1)
Licensee Activities Unit 1 Unit 1 operated in a power coast-down during the period November -
December 1981 until it was shutdown for refueling on January 1, 1982.
The outage, which included a number of NUREG 0737 TMI Action Plan modifications, concluded on April 12, 1982 when the unit went critical on the Cycle 4 core.
Leaks in Boron Injection Tank isolation valves resulted in a shutdown for repairs and the unit returned to service on April 19, 1982.
During the evaluation period, Unit 1 experienced nine reactor trips which resulted in short-duration shutdowns.
Three safety injections were associated with loss of lA Vital Instrument Bus precipitated by tripping of the output breakers caused by control system interference from an enclosure cooling fan.
The problem was corrected by re-routing fan cables in the enclosure.
Unit 2 Unit 2 completed powe_r ascension startup testing on September 2, 1981 with the 100% trip test and the last natural circulation test.
During the period September 21 - October 7, 1981, Unit 2 was shutdown for steam generator modifications due to indicated high moisture carryover.
Unexpectedly high steam flow indication resulted in limiting power to 90 - 95% during the last 3 months of 1981 until the problem was resolved as a combination of carryover and calibration errors.
Unit 2 was declared commercial on October 13, 1981.
Between October - December 1981, Unit 2 tripped on seven occasions caused by low steam generator level following loss of one or both steam generator feedwater pumps as a result of low suction pressure.
Based on data from a number of monitored load reduction tests con-ducted in December, the licensee confirmed that secondary system stability was such that minor perturbations in the heater drain system could cause significant swings in feedwater pump suction pressure.
With added awareness of the problem, addition of low suction pressure alarms and modifications to procedures, short-term corrective a~tion appeared effective.
Of four additional reactor trips caused by loss of a feedwater pump since the first of the year, only one was due to low suction pressure.
Long-term system modifications are being deve-loped.
Four additional Unit 2 reactor trips during the period resulted in short-term shutdowns.
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Site During the period May 1 - June 11, 1982, all bargaining unit employees represented by International Brotherhood of Electrical Workers (IBEW) Local 1576 were on strike.
The IBEW represents all personnel on site with the exception of security and office workers.
Plant operators, up to the level of reactor operator, were included.
The licensee retained approximately 390 management and engineering personnel on site and continued to -0perate the two operating units in two 12-hour shifts.
Adequate numbers of management personnel were available to cover licensed and unlicensed operator positions.
Management operators assigned in the control room had recent or current operating experience.
For.the duration of the strike, both units continued to operate at nominal full power.
The licensee initiated a planned transfer of corporate management and engineering functions to the site vicinity during the evaluation period.
All functions related to the facility are being included in a new Nuclear Department, headed by a Vice President located on site.
By the end of the evaluation period, functional transfer had been completed; however, some vacancies still existed in the new organization which were being filled by corporate office personnel on a temporary basis.
(2)
Inspection Activities Two NRC resident inspectors were on site for the entire appraisal period, with a change in resident inspector taking place in January 1982.
Total NRC Inspection Hours:
3824 (Resident and region based)
Distribution of Inspection Man-hours is shown in Table 3.
During the period April 29 - June 18, which included the entire duration of the strike, 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage by NRC inspectors was maintained.
A tabulation of Inspection Activities is attached as Table 4.
A tabulation of Violations is included as Table 2.
Specific enforce-ment data is presented in Attachment 1.
Two investigations of apparent tampering with plant equipment were conducted during the period April 28 - September 15, 1982.
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.1 II.
SUMMARY
OF RESULTS SALEM NUCLEAR GENERATING STATION FUNCTIONAL AREAS CATEGORY CATEGORY CATEGORY 1
2 3
- 1.
Plant 012erations x
- 2.
Radiological Controls Radiation Protection Radioactive Waste Management x
Transportation Effluent Control and Monitoring
- 3.
Maintenance x
- 4.
Surveillance (Including Inservice and Pre-x 012eration Testing)
- 5.
Fire Protection x
- 6.
Emergency Pre12aredness x
- 7.
Security and Safeguards x
- 8.
Refueling/Outage Activities x
- 9.
Licensing Activities x
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J I I I. CRITERIA The following evaluation criteria were applied to each functional are:a:
- 1.
Management involvement in assuring quality.
- 2.
Approach to resolution of technical issues from a safety standpoint.
- 3.
Responsiveness to NRC initiatives.
- 4.
Enforcement history.
- 5.
Reporting and analysis of reportable events.
- 6.
Staffing (including management).
- 7.
Training effectiveness and qualification.
To provide consistent evaluation of licensee performance, attributes associated with each criterion and describing the characteristics appli-cable to Category 1, 2, 3 performance were applied as discussed in NRC Manual Chapter 0516, Part II and Table 1.
The SALP Board conclusions were categorized as follows:
Category 1:
Reduced NRC attention may be appropriate.
management attention and involvement are aggressive and toward nuclear safety; licensee resources are ample and used such that a high level of performance with fespect tional safety or construction is being achieved.
Licensee oriented effectively to opera-Category 2:
NRC attention should be maintained at normal levels.
Licensee management attention and involvement are evident and are concerned with nuclear safety; licensee resources are adequate and are reasonably effective such that satisfactory performance with respect to operational safety or construction is being achieved.
Category 3:
Both NRC and licensee attention should be increased.
Licensee management attention or involvement is acceptable and considers nuclear safety, but weaknesses are evident; licensee resources appeared strained or not effectively used such that minimally satisfactory performance with respect to operational safety and construction is being achieved.
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IV.
Performance Analysis
- 1.
Plant Operations (56.4%)
Analysis of this area includes direct plant operational activities as well as operational support activities.
The operations area was under continual review by resident and region-based inspectors during the assessment period with inspections covering the following areas; compliance with license and procedural requirements, design changes and modifications, quality assurance, training, housekeeping and cleanliness, drawing control, audits, corrective action systems, on-site and off-site committees, reporting systems, and operations during an employee strike.
During the assessment period, significant improvements were noted in management attention to and control of dissemination of policy and tracking of commitments to final resolution.
With respect to the latter, clearly defined and functional department and station-wide systems have been established.
A large portion of inspection activities were associated with plant events.
During these followup activities, licensed operators displayed a detailed working knowledge of the plant and an ability to explain transient response, reflecting a good state of training.
Forty-one LER's are attributed to personnel errors; only 6 of those were ascribed to licensed operators.
The training staff is well managed and operates with clearly defined policy and authority.
An effective system is in place to disseminate operational events and design change information to licensed operators.
The licensee's commitment to quality operator training has been demon-strated by the on-going construction of a modern training facility which will house a plant-specific simulator in 1983.
This facility, opened late in the assessment period, consolidate previously scattered training activities.
The level of training was further demonstrated by the operators' ability to work around the problem of a lack of current as-built information available in the control room.
Since drawing updates take over a year, the licensee files outstanding design change information with the most recent drawing revision, leaving interpretation to the operators.
These files were found incomplete.
This problem appears to have been resolved in response to an inspection finding toward the end of the assessment period.
One violation dealt with a failure to make timely application for operator license renewal, but is considered an isolated case.
Inspection of licensee reviews and QA audits found evidence of planning and priority lacking in that the QA audit section had no management system to ensure coverage of Technical Specification required audits.
Audit reports do not address the required area of 7
J program effectiveness, nor is the effectiveness of the corrective action system addressed.
Management of the audit program appears to focus on getting scheduled audits done, at the expense of effective-ness and completeness.
On site and off site review committees (SORC and NRB) are properly constituted, meet frequently, and, based on results, ask cogent questions.
Safety evaluations, particularly in support of design changes, were well documented and generally sound.
Six violations during the period deal with failures to prepare, properly issue, or use procedures.
Three of these stemmed from failures to effectively communicate system status to field personnel or contractor maintenance forces, resulting in tagging or system alignment errors.
Tagging and alignment errors have been recurrent problems over the past few years.
Corrective actions, including the use of an independent verifier have not been effective in some in-stances.
An additional violation since the end of the assessment period occurred in early October, 1982; when the auxiliary feedwater flow path to one steam generator was valved out due to auxiliary operator error.
Verification of valve tagouts was not independent and failed to detect this error.
The remaining three violations in*
this area dealt with failure to review and approve procedures and failures to prepare ~quired procedures.
The licensee practices a documented policy of strict procedure adherence as evidenced by inspector observation and the large number of authorized on-the-spot changes found in the procedures.
The above failures to prepare and approve procedures had no commonality and do not suggest programmatic problems.
The isolated procedure adherence problems appear to be rooted in the fact that management holds some personnel outside the control room insufficiently accountable for this area.
The licensee is generally responsive to NRC reporting requirements.
Four violations identified with respect to reporting were not indica-tive of programmatic failure.
Some LER 1 s were received which provided insufficient information to fully understand and assess the event.
Based on reports received toward the end of this period, these report-ing inadequacies appear to have been corrected.
Continued management attention in this area is necessary to ensure that the quality of LER 1 s is not degraded.
In resolving safety issues, the licensee 1 s engineering department shows a lack of responsiveness to operational concerns.
When presented with a safety concern by the operating or safety review group, a rapid response is obtained only when plant shutdown or power reduction is imminent.
However, the licensee has never failed to initiate a plant power reduction or shutdown when dictated by regulation, license, or safety considerations.
The following examples of untimely response to potential safety issues were observed:
an evaluation of the ability to test of redundant diesel generator air start solenoids, begun in July 1981, is not complete; no effectjve 8
J corrective action has been implemented to preclude frequent air lock seal failures which has been a recurrent problem for several years; no corrective action, beyond weekly radiography, has been implemented to solve the problem of failing auxiliary feedwater steam supply check valves since the problem was first identified in June 1981; an evaluation of both BIT inlet valves* failure to open on a safety injection in November 1981 has not been completed; an evaluation of vital heat trace surveillance acceptance criteria and technique has not been completed since identification of the potential problem in July 1981; the solution to a potential VCT level control problem identified in May 1981, has only been procedural in nature, to date; 52 Licensee Event Reports discuss inoperability of Containment Fan Coil Units for various reasons and corrective measures for the pre-dominant cause are still to be implemented in Unit 2.
Such delays in providing engineering resolution have resulted in additional burdens on the operating staff.
Each of these issues was referred to the Engineering Department.for evaluation and resolution.
Since this Department enjoys independence under a separate Vice President within the company, little motivation to respond could be imparted by station staff as evidenced by their responses to questions from the inspectors.
The recent reorganization to place engineering support within the Nuclear Department should resolve this lack of responsiveness.
Operations first line supervisors are aggressive and knowledgeable.
This was demonstrated by their ability to maintain both units opera-ting and in compliance during a seven-week strike by bargaining unit employees, including control room (licensed reactor operators) and field operators.
In general, the operating crew has several years of experience at Salem with a minority of license holders who lack Salem field operator backgrounds.
Operator licensees include 28 SR0 1 s and 26 R0 1 s.
5 SR0 1 s and 4 R0 1 s hold licenses for Unit 1 only.
Management strengths include positive steps to establish controls over intra-departmental activities including qualification of pers~nnel, tracking of commitments, adherence to procedures, com-pliance with Technical Specifications.
Significant failures to completely address issues occur when corporate inter departmental communication and cooperation are required.
This aspect requires management attention at the highest levels.
Conclusion Category 2 Board Recommendations None.
The Board notes that had deficiencies not existed in engineering support, this conclusion would have been Category 1.
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- 2.
Radiological Controls (8.2%)
During the assessment period, regional Health Physics Specialists conducted four inspections of the radiation protection program and portions of the radioactive waste management, transportation, and effluent control program.
A transportation inspection was conducted by a Resident South Carolina State Inspector at a burial ground and reviewed by a Regional Health Physics Specialist.
Resident inspectors conducted monthly reviews of selected program areas.
Man-rem exposure data in a draft NRC report show the total personnel radiation dose at Salem Unit 1 in 1981 decreased 43% from 1980 levels.
The Salem 1 total dose of 254 man-rems was the second lowest of all power reactors in Region I in 1981, significantly below the national PWR average of 656 man-rems.
Radiation dose data was not included in the draft report for Salem Unit 2, which started commercial opera-tion in October 1981.
No major outage involving primary systems was conducted on either unit during 1981.
Although three violations in radiation protection were identified in the areas of:
(1) work permit compliance, (2) posting, and (3) per-sonnel contamination surveillance, no programmatic problems were identified in the radiation protection program during the assessment period.
The license~ conducted prior planning for major outage tasks and maintained explicit procedures for health physics activities.
Radiation protection records for personnel radiation exposure, respiratory protection, and radiation surveys were complete, well maintained, and available.
Radiation protection procedures were rarely violated.
Program audits were timely and corrective actions were prompt.
Radiation protection staffing is adequate, with backlog and overtime under control.
The licensee maintains and implements a training and qualification program for radiation protection personnel and radiation workers which contributes to work understanding and adherence to procedures.
The radioactive waste management program received minimal inspection effort during the assessment period.
No violations were detected in the area.
Program audits were timely and corrective action prompt.
The licensee's organization and administration of the chemistry program (responsible for effluent analysis and monitoring) changed during the assessment period.
A new Senior Supervisor of Chemistry and a Chemistry Engineer have been named.
In addition, foreman positions have been staffed.
Staffing is adequate.
Current chemi-stry supervision is responsive to NRC comments and suggestions and appears committed to improving the quality of the overall chemistry 10
J program.
All effluent measurement comparisons were in agreement with the exception of one tritium measurement due to an improper calibration of the liquid scintillation counter.
This contributed to a violation.
Two violations were cited during the assessment period for unmonitored effluent releases from a gas decay tank and from steam generator blowdown.
While technical specification release limits were not exceeded, minor programmatic breakdown may be indicated.
The events were promptly and completely reported.
Overall, effluent program policies were rarely violated.
One transportation violation (Severity Level III) for failure to package LSA waste in strong, tight packages was detected during the assessment period, however, no programmatic breakdown was indicated.
Transportation records were complete and available.
After the violation in this area, a training program was implemented for trans-portation personnel which contributed to understanding of work and few personnel errors.
Strong and direct management involvement is evident in this area.
Conclusion Category 1 Board Recommendation None 11
- 3.
Maintenance (4.2%)
During the assessment period, one region-based inspection was performed in this area and routine monthly inspections of maintenance activities were conducted by the resident inspectors.
Management involvement and control in assuring quality is evidenced by prior planning and assignment of priorities.
Decision making is usually at a level that ensures adequate reviews.
Quality related records were complete and well maintained; reviews were generally timely and technically sound.
Key positions in the maintenance staff are identified and staffing level is adequate as evidenced by minimal corrective maintenance backlog.
The licensee has a well established maintenance training program which contributes to an adequate understanding of work and adherence to procedures.
The training program is well defined and has been implemented for the major portion of the maintenance staff.
Work is assigned and supervised so as to apply the correct level of training and experience to a given job.
Management and control of the site maintenance contractor is included in this area although the majority of contractor work deals with design changes and plant modifications.
In general, the contractor's activities appear to be more closely monitored than in the past.
One violation was identified with respect to the use of a metal filler compound to repair Containment Fan Coil leaks.
While the process was later found to be acceptable, repairs were made and the units returned to service prior to completion of a safety evaluation in accordance with 10 CFR 50.59.
While maintenance management practices are generally sound, this violation resulted from an over zealous attempt to fix the problem.
The licensee's deficiency report/corrective action system had failed to explicitly require a review of the design implications attendant with short term problem resolution.
As a result, the repair had received engineering review and approval but the 50.59 review was not done.
This oversight was a singular program deficiency which has since been corrected.
Maintenance activities are accomplished in a controlled, procedure-oriented, technically sound, and closely supervised manner with adequate quality group involvement.
Conclusion Category 1 Board Recommendations None 12
- 4.
Surveillance (4.2%)
One region-based inspection and continual review by resident inspectors occurred during the assessment period.
In general, management control was evident.
Adequate staffing, planning and prioritization were in place.
Procedures affecting safety equipment are thoroughly prepared, are reviewed by SORC, and are rigorously used for surveillance activities. All periodic surveillance testing, including those tests dictated by Technical Specifications, are scheduled by means of a computer-based Inspection Order system which provides reminders to perform the tests within a given time frame, and also provides management reports which flag nearly overdue tests so that timely action can be taken.
The licensee's resolution of technical issues in this area is generally conservative but relaxes once the immediate concern is addressed, usually through procedure additions or changes.
Staffing levels are adequate in that, generally, required tests are performed on time with no backlog.
Technicians, especially in the I&C area, are specifically trained and qualified to perform designated tests.
Two violations in this area dealt with the measuring and test equip-ment program.
In one case, sufficient control was not exercised in issuing the equipmen~ to retain a complete, documented history of where the equipment was used.
The other item concerned timely review of where test equipment, which failed periodic calibration, had been used.
A programmatic weakness was not evident.
Two violations and seven LER 1 s concern 6 instances of missed surveil-lance tests.
In view of the number of tests required to be conducted and the unique causes of each missed surveillance, program weakness is not indicated.
The Technical Specification concept of periodic surveillance testing to demonstrate operability is well understood by management and opera-tors.
No instance was identified in which a failed surveillance test, or a missed test, resulted in anything short of a declaration of inoperability and application of the appropriate action statement.
The IST program is coordinated by a dedicated and knowledgeable on site group and no problems were identified with the execution of this function.
Needed improvements in the containment local leak rate testing program as identified in a program review and discussed during a combined inspection and licensing evaluation at the end of the assessment period, had already been initiated by the licensee's staff by the time of followup on-site inspection.
Conclusion Category 1 Board Recommendations None 13
- 5.
Fire Protection (4.3%)
This assessment is based on two region-based inspections and routine observations by the r,esident inspectors.
Prior planning and assignment of priorities by licensee management is evident in program procedures with specific assignments made to implement the requirements of those documents.
Decision making was consistently at a level that ensured adequate management review, e.g. review of fire protection supervisor activities by the General Manager-Salem Operations.
However, the licensee's currently docu-mented fire protection program has been in place for several years.
Although the need to update and improve the program has been recog-nized, no modification has been issued.
The new Nuclear Department organization splits responsibilities for the program between the station operating group and the Nuclear Department services group.
This action will provide more attention to the area of fire protection, removing operating personnel from program concerns and permitting them to focus on the continuity of site fire detection/suppression capability.
NRC review of a problem with fire protection system valve supervisory panels 1RP5 and 2RP5 indicates that the design and correction of the design has not been given high priority by the licensee.
The design problems of this system were identified to management by the fire protection supervisor.
However, due to the departmental interface problems discussed in Functional Area 1 (Plant Operations),
engineering resolution of these design problems has not yet been developed.
Regional review of Appendix R indicated that requirements appear to be understood by the licensee with design modifications sent to NRC for review and acceptance.
Three Appendix R exemptions were requested, of which two were granted to date.
The licensee filled key staff positions in a reasonable time.
The fire protection supervisor requires additional dedicated staff to assure that adequate fire protection program requirements are complied with.
A re-organization that the licensee plans to implement should correct problems that were identified in this area.
The licensee's training and qualification program has been adequate to provide the requisite number of qualified fire brigade members on shift.
Planned development and implementation of a new training program are expected to improve understanding of personnel duties and adherence to procedures.
One violation in this area resulted from a failure to adequately post and maintain fire watches at a fire barrier cable penetration which had been opened for plant modification work.
Three LER's detail similar problems with open or breached fire barriers.
Fire 14
doors have historically been a concern dua to high traffic flow and the frequent degradation which results.
In October 1981, the licensee took the position that maintenance of fire doors as presently configured was impossible.
Accordingly, the Technical Specification Action Statement was entered and permanent assignment of contracted fire patrols and fire watches throughout the plant was implemented.
A design change package to upgrade door hardware and modify door designs to alleviate this condition has been issued but work is not complete.
Plant cleanliness and housekeeping is generally acceptable with an evident program of cleanup underway for several months.
The concept of cleanliness and fire prevention is, however, not clearly under-stood by or promulgated to those creating the problem.
Current efforts are aimed at cleanup after the fact rather than preventing accumula-tions of debris in the first place.
Additional management attention in this area is warranted.
One violation of a Unit 2 license condition identified a failure to completely implement a design change to install protective fire wrap*
on selected cable trays.
This problem has its origin in a recurrent failure to verify work completion by contractors.
This aspect is discussed further in Functional Area 8 (Refueling/Outage Activities).
Failure to completely address the design and program concerns outlined suggests that the fire protection program did not have management priority commensurate with NRC concern in this area.
Current organizational initiatives should resolve this situation.
There were no onsite fires during the reporting period.
Conclusion Category 2 Board Recommendation None 15
- 6.
Emergency Preparedness (1.0%)
Due to a schedule delay, the 1982 exercise was held in October 1982, after the evaluation period.
No NRC observed full exercise was held in the period under review and no region-based inspection was conducted in this area.
This assessment is based on the routine observations of the resident inspectors.
The revised Emergency Plan in effect for the period had never been tested in a NRC-observed full exercise.
Some drills, for specific groups (e.g. radiation protection, emergency duty officers), and a practice exercise in April, 1981, were conducted.
The Technical Support Center was moved to an interim location with adequate provision taken for continuity during the move.
Management attention to viable emergency planning was evident.
Emergency Plan training continued to be a significant part of the operator training/retraining curriculum.
Shift manning was observed to meet all requirements for non-operator coverage (shift I&C and maintenance personnel).
Inspector observation during unusual events indicated that the Emergency Plan and Procedures continue to be viable documents with which shift supervisors remain familiar.
Emergency Duty Officer assignments continue to be made and the designated indiViduals were readily available by telephone or page.
The licensee completed installation and initial testing of the Public Notification System by February 1982.
In addition to the siren system, approximately 800 radios have been distributed.
After the assessment period, the 1982 annual exercise was observed on October 13, 1982.
The licensee demonstrated an adequate capabi-lity to deal with a plant emergency.
A number of deficiencies, most of which were recognized by the licensee, were identified relating to timely personnel accountability, communications, and procedure adherence.
The inability to account for station personnel quickly was evident in two drills conducted prior to the exercise, but no significant corrective action was taken.
Conclusion Category 2 Board Recommendation None 16
- 7.
Security and Safeguards (18.4%)
The assessment period included three special security inspections, one routine security inspection, one inspection of material control and accountability, two investigations prompted by security related events,.and observations by the resident inspectors.
Frequent and, in some c~ses, continuous inspection at the start of bargaining unit employee strike and following suspected tampering events provided the inspectors added opportunities to evaluate security plan imple-mentation, management involvement, staffing, shift routines and condition of equipment.
The licensee was found to be ineffective in maintaining certain aspects of the security program.
For example, assignment of only one on-site licensee security manager is apparently insufficient to manage the contractor program.
Corporate security management, although relocated to the site, appeared minimally involved in routine security operations.
Shift supervision of security per-sonnel was provided by the contractor.
Key licensee positions were identified with clear definition of duties and responsibilities and with policy decisions usually made at appropriate management levels.
Contract security staffing with about 200 guards and watchmen would be adequate under most circumstances.
However, the prolonged use of compensatory posts in_ lieu of i nsta 11 ed equipment resulted in significant hours of overtime work.
While responsibilities are well defined, the resources actually applied to security program oversight were insufficient to detect and correct the following:
Maintenance support for security equipment is sporadic, resulting in extended inoperability of lighting and detection aids and a continuing requirement for compensatory posts.
Security hardware, such as lantern batteries, radios, and inspection mirrors, was not maintained or replaced.
Design problems in the security system were not addressed with any priority.
Fouling of a micro-wave zone by building a new contractor guard house precipitated deployment of two compensatory guards for over a year.
The security training program and security procedures poorly described actual shift security activities.
The procedures do not completely implement the security plan.
Audits of the program are not thorough.
Security documentation was frequently found incomplete in describing events and in many cases was missing.
Responsiveness to NRC findings was short sighted and, as evidenced by a number of repetitive findings, did not provide effective measures to prevent recurrence.
17
Inspection findings during the period included nine violations (one Severity III). Several of these violations were the result of erroneous or misinformed decisions made by licensee site management.
Escalated enforcement has been proposed for five of these items.
Sixteen violations and a $40,000 Civil Penalty during the previous evaluation for similar findings strongly suggests that corrective and preventive measures have not been aggressive or effective.
As a result of the strike by the IBEW and three possible acts of tampering with plant equipment, the security force and on site security management were severely challenged by functioning in a reactive environment for the last four months of the assessment period.
The lack of depth in on-site licensee management during this period may have contributed to breakdown in the program.
Although the security program was severely stressed during the strike and considerable NRC inspection was conducted, the findings themselves reflect chronic lack of management control and involvement.
Investigatidns of three suspected tampering events were not success-ful in conclusively identifying perpetrators.
In response to NRC Region I, the licensee instituted programs to assure continued operability of systems important to safety and programs to improve the probability of identifying any subsequent perpetrator.
Reviews of the events and discussions with personnel have confirmed only the first event, two days before the strike, as an intentional act of malicious tampering.
Demonstrated management control of this area is weak and ineffective in correcting long-standing program deficiencies.
Conclusion Category 3 Board Recommendation None 18
- 8.
Refueling/Outage Activities (3.3%)
One 14-week refueling outage was conducted during the current appraisal period on Unit 1 (during the period January 1 - April 12, 1982).
Originally scheduled for 10 weeks, the outage included a number of TM! Action Plan modifications and the replacement of one component cooling heat exchanger which proved to be the controlling schedule item.
Prior to and throughout the outage, management involvement in scheduling and sequencing of work was evident.
Daily planning meetings were effective in coordinating work to be accomplished and identifying mechanisms to improve schedules on critical path work.
A significant increase in the scope of steam generator tube inspec-tions resulted from degradation found in some peripheral tubes.
Preparation and contingency scheduling was sufficient to prevent this from becoming a delaying item.
Fuel moves, conducted by a Westinghouse team, were accomplished without incident.
Due to a previously identified failure of one in-core thimble tube, all were replaced during this outage.
This work, involving highly activated components, was carefully planned and executed with no attendant problems.
In response to previously identified problems with the reporting of design change work co_mpletion by the contractor, a system of walk throughs and more rigorous reporting system were instituted.
In past outages, verbal statements from contractor supervisors were accepted by licensee management and, on the basis of these statements, assertions were made to NRC that required work had been completed.
Later inspection by NRC and the licensee frequently found that some aspect of the work remained incomplete.
During this outage, the licensee imposed a system of walk throughs by cognizant engineers and documentation of completion before declaring work complete or systems available for operation.
The licensee demonstrated less reluctance to accept 11paper work 11 delays in the interest of assuring the work was satisfactorily completed.
Despite pressures to reduce these delays, quality reviews were not compromised.
One instance of incomplete outage work was identified after the assessment period.
Function of the plant vent Air Particulate Detector (APO) was lost due to Partial implementation of a design change.
The APO would not have provided automatic isolation of containment vent valves if required.
This condition existed for the entire 6-month operating cycle.
Causes for this occurrence are under review.
Inspection in this area identified no adverse findings.
Conclusion Category 1 Board Recommendation None 19
- 9.
Licensing Activities The licensee continued to place a high degree of management attentioh and involvement on most licensing activities.
This has assured prompt attention to site-specific actions.
However, this system was less effective in ensuring timely attention to several dated license condi-tions for Salem Unit 2.
PSE&G has nearly completed an administrative transition that will transfer all nuclear activities to a department on site under a corporate vice-president who is also stationed at the Salem site.
The presence of all key nuclear-oriented people at one location should facilitate focusing of management attention to the nuclear units when needed, and, thereby, improve corporate officer/-
plant operation interchanges.
PSE&G continued to maintain a very effective staff of engineers and scientists at the corporate headquarters and at the Salem site to resolve technical issues.
Most of the employees who have been involved with licensing reviews have had several years experience with operating nuclear plants and working with the NRC..
The licensee has been very cooperative in scheduling technical meetings with the staff to resolve complex licensing issues.
In some reviews (e.g., rod exchange methodology and Appendix R), there have been multiple technical discussions wherein the licensee and NRR staff continue to have significant technical disagreements.
Licensee responsiveness to NRC initiatives has been very good to poor, depending on the individual activity.
The ability previously exhibited by the Salem licensing group appeared to be adversely effected by the reorganization of the Nuclear Department.
The relatively small staff was reduced even further when some members chose not to transfer from corporate headquarters to the station site.
The effectiveness of this group remained reduced during the period that other members transferred their residences.
The activities of the group remained fragmented between the corporate headquarters and the Salem site. At the end of the assessment period, however, there were no overdue responses and all responses during the period were satisfactory in content.
The licensee has shown an acceptable understanding of the reporting requirements and has issued an average of 10 LERs per unit each month.
It is evident that the licensee is alert to problem areas and trends that have been identified by these LERs and is planning corrective action, where necessary, during the next refueling outages.
The licensee has capable operating and support staffs for Salem and these staffs should become even more efficient as the new Nuclear Department matures.
Two potential problem areas remain.
The small residue of the licensing staff needs to be upgraded by replacing personnel who did not transfer to the Salem site.
Also, the 20
licensee is currently shifting many experienced support staff members to new responsibilities at the adjacent Hope Creek site.
Care must be taken to ensure that the capability of the Salem support staff is not decreased.
With respect to training effectiveness and qualification, the results of licensing examinations have been mixed.
In November 1981, the passing rate for 14 ROs and one SRO taking the exam was only 43% (6 ROs and 1 SRO); howeveri when 5 ROs were retested, they all passed.
A new training center near the site has been placed in operation.
The strength of the utility's management licensed staff was evident during the labor strike in May and June, 1982 when licensed management personnel operated the Salem station without any reduction in safety or power generation.
The licensee has implemented the NUREG-0737 requirements for shift manning.
Assessment of this area was based on NRR evaluation of the following licensing activities:
Responses to NUREG-0737 items Operating Events performance Steam generator inspections Calibration of control rod worth by rod exchange methodology Appendix I Fire Protection - Appendix R Snubber operation and surveillance Environmental Protection Plan Heavy Loads In several areas (management involvement, approach to technical issues, operating and technical staff capability) the licensee would appear to be superior.
The licensee, in response to previous appraisals, is attempting to strengthen all operational and safety aspects of the Salem station by concentrating all of the corporate nuclear-related personnel at the site and placing the entire Salem station and adjoining Hope Creek construction site under a corporate vice president.
This assures prompt attention of all of the licensee's expertise to normal or emergency requirements; however, there may be a tendency to dilute the existing capability at Salem by assigning many of the support personnel primarily to the Hope Creek operation.
The licensee is remaining current with all regulatory requirements and actions; however, it is evident that the licensing group is short-handed and needs management attention and support during the reorganization period.
Conclusion Category 2 Board Recommendation None 21
- v.
Supporting Data and Summaries
- 1.
Licensee Event Reports Tabular Listing Unit 1 Unit 2 Total Type of Events:
A.
Personnel Error 19 22 41 B.
Design/Mfg/Constr/Install.
7 12 19
- c.
External Cause 12 20 32 D.
Defective Procedures 2
1 3
E.
Component Failures 61 63 124
- x.
Other 10 17 27 TOTAL 111 135 246 Licensee Event Reports Reviewed Unit 1:
Reports 81-7~, 77, 78, 84, 86 through 122, 82-01 through 66, 68 through 71 Unit 2:
Reports 81-85, 86, 90, 94 through 131, 82-01 through 85, 87 through 90, 94 through 97, 102 22
II f'
Causal Analysis Thirteen sets of common mode events were identified:
- a.
29 LER 1 s (13 on Unit 1, 16 on Unit 2) involve service water leaks in con-tainment resulting from leaks in Containment Fan Coil Unit coils on the supporting service water system.
The licensee completed a program of material upgrades on Unit 1 during the January~April, 1982 outage and plans similar modifications on Unit 2 during the January 1983 first refueling outage.
The LER 1 s in this group are:
(Unit 1) 81-76, 77, 78, 84, 92, 94, 96, 105, 108, 109, 114, 118, 82-18; (Unit 2) 81-90, 94, 114, 115, 82-28, 39, 40, 70, 73, 74, 75, 77, 78, 80, 84, 89.
- b.
10 LER's (3 on Unit 1, 7 on Unit 2) detail inoperability of CFCU 1 s due to low service water flow indication resulting from silt buildup in trans-mitter sensing lines.
Despite weekly blowdown of the lines and daily operation of the units, this is a recurring item.
The LER 1 s in this group include:
(Unit 1) 81-86, 89, 82-61; (Unit 2) 81-99, 103, 110, 117, 82-17, 38 and 96.
- c.
8 LER's (4 on Unit 1, 4 on Unit 2) involve low service water flow to CFCU 1 s resulting from flow control valve problems.
These include LER 1 s (Unit 1) 82-22, 24, 29, 37; (Unit 2) 82-06, 35, 65, 88.
- d.
5 LER 1 s (all Unit 2) involve loss of service water flow to CFCU 1 s resulting from oyster shell blockage of flow control valves.
Incidence of oyster shells to date appears to support a conclusion that a relatively small colony was established in the Unit 2 Service Water System.
The problem does not appear wide-spread nor has the frequency of valve fouling been
-great.
Steps to obtain approval for increased chlorination are underway.
The LER's included in this group are:
(Unit 2) 82-41, 46, 49, 50 and 58.
- e.
15 LER's (5 on Unit 1, 10 on Unit 2) detail inoperability of a containment air lock door, usually due to poor sealing or failure to door hardware apparently resulting from harsh use.
Improvements in personnel training and hardware reliability are underway.
Recently, the licensee proposed the addition of snubbers to prevent slamming of the doors.
The LER 1 s included in this group are:
(Unit 1) 81-89, 116, 82-48, 66, 68; (Unit 2)81-112, 122, 82-21, 44, 45, 47, 51, 55, 56, 102.
- f.
38 LER's (11 on Unit 1~ 27 on Unit 2) involve protection channel instru-mentation, including setpoint drifts, transmitter failures, and functional failures discovered.during surveillance testing.
In each case, redundancy was maintained and frequently the failure was discovered by lack of con-sistency between redundant channels. Operability was restored within required time frames.
The LER 1 s in this group include:
(Unit 1) 81-91, 100, 103, 104, 113, 115, 82-21, 25, 49, 59, 63; (Unit 2) 81-86, 95, 96, 100, 102, 105, 119, 120, 123, 124, 131, 82-01, 05, 08, 12, 14, 18, 19, 42, 52, 61, 66, 67, 69, 72, 85, 94.
23
l I,*
f
- g.
7 LER 1 s (1 on Unit 1, 6 on Unit 2) detail drift in individual rod position indication instruments.
This has been a recurring problem with this type of instrumentation at a number of facilities.
The single event on Unit 1 during the period indicates that the licensee, through recognition of temperature sensitivity, has developed techniques to deal with the problem.
No plans exist for replacing the instrumentation.
The LER 1 s in this group include:
(Unit 1) 82-70; (Unit 2) 81-97, 98, 108, 121, 82-10, 26.
The high number of reports on Unit 2 in the preceding two groups is probably attributable to instrument break-in during the first full year of power operation.
- h.
4 LER 1 s (2 on Unit 1, 2 on Unit 2) deal with errors in construction or design while making plant modifications.
The LER 1 s in this group include:
Unit 1) 82-10, 82-15; (Unit 2) 81-85, 109.
- i.
7 LER 1 s (2 on Unit 1, 5 on Unit 2) deal with missed surveillance tests.
The most frequent cause appears to be a failure to realize that additional tests are prescribed for some Unit 2 systems beyond those required fo~
Unit 1.
The LER 1 s in this group include:
(Unit 1) 82-39, 62; (Unit 2) 82-15, 27, 43, 62, 81.
- j.
7 LER 1 s (all Unit 1 or common) are associated with degradation of fire suppression systems.
Design changes to the fire pump diesels are expected to reduce the number of occasions in which alternate or back-up fire suppression equipment or systems will be required.
These LER 1 s include:
(Unit 1) 81-88, 93, 82-09, 19, 27, 35, 55.
- k.
7 LER's (2 on Unit 1, 5 on Unit 2) detail rapid down-power transient in which axial flux difference was driven out of the target band as an expected result of driving rods into the core.
The LER's in this group include:
(Unit 1) 82-33, 57; (Unit 2)81-130, 82-04, 16, 32, 57.
- 1.
4 LER 1 s (2 on Unit 1, 2 on Unit 2) report DNB parameters out of limits for intervals less than allowable by Technical Specifications due to control system malfunctions or radical power transients.
The LER's in this group include:
(Unit 1)81-101, 82-38; (Unit 2)81-111, 81-128.
- m.
4 LER 1 s (2 on Unit 1, 2 on Unit 2) discuss events precipitated by electrical noise interference resulting in unwarranted and unexpected control system operation.
Additional operating events not resulting in reportable occurrences, have been attributed to these interactions.
A program of signal isolation and decoupling has been initiated to resolve this problem.
As specific interactions were identified, modifications to attenuate the noise or sensitivity of the control system was implemented.
The LER's in this group include:
(Unit 1)81-107, 110; (Unit 2) 82-31, 63.
24
i
.J
- 2.
Investigation Activities Investigation April 29 - May 5, 1982 to followup on apparent deliberate tampering with Steam Generator Feedwater pump on April 28, 1982.
Investigation August 9 - September 15, 1982 to followup on apparent deliberate tampering with Essential Inverter power supply on August 9, 1982.
- 3.
Escalated Enforcement Actions
- a.
Civil Penalties Notice of proposed civil penalty issued on October 27, 1982 based on security inspection findings during the period June 14-18, 1982.
- b.
Orders Prior to the assessment period, an Order modifying the Unit 1 1 icense
.1 was issued July 10, 1981 confirming licensee commitments for TMI related requirements contained in NUREG 0737 (Issued to all licensees).
- c.
Confirmatory Action Letters Confirmatory Action Letter 82-15, dated April 29, 1982 confirming actions in response to an apparent act of tampering which resulted in deliberate trip of a steam generator feedwater pump on April 28, 1982.
Confirmatory Action Letter 82-22, dated August 18, 1982 confirming actions agreed to by the licensee in a meeting with NRC Region. I management on August 17, 1982 following a suspected tampering event involving diesel air start valves on August 16, 1982.
- 4.
Management Conferences Held During The Assessment Period SALP Cycle II Management Meeting at Salem Nuclear Generating Station on October 29, 1981.
Meeting held at the NRC Region I offices on June 29, 1982 to discuss licensee plans for post-strike security and additional steps to preclude plant tampering or vandalism.
Enforcement conference held in NRC Region I office on August 12, 1982 to discuss inspection findings and proposed corrective actions resulting from physical security inspection June 14-18, 1982.
25
JI TABLE I TABULAR LISTING OF LERs BY FUNCTIONAL AREA SALEM NUCLEAR GENERATING STATION - UNIT 1 Area Number/Cause Code Tota 1
- 1.
Plant OQerations 12/A 3/C 14/E 6/X 35
- 2.
Radiological Controls 2/A 2
- 3.
Maintenance 2/A 1/B 3/C 5/E 11
- 4.
Surveillance 3/A 1/B 3/C 1/D 18/E 1/X 27
- 5.
Fire Protection 1/B 5/E 2/X 8
- 6.
Emergency PreQaredness l/C 1
- 7.
Security and Safeguards
- 8.
Refuel in
- 9.
Licensing Activities 1/D 1
- 10.
Other (Original Design Errors and Equipment Failures Not Classifiable Into Areas 1-9}
4/B 2/C 19/E 1/X 26 TOTAL 111 Cause Codes:
A - Personnel Error B - Design, Manufacturing, Construction, or Installation Error C - External Cause D - Defective Procedures E - Component Failure X - Other 26
}'.
1
(
TABLE I TABULAR LISTING OF LERs BY FUNCTIONAL AREA SALEM NUCLEAR GENERATING STATION - UNIT 2 Area Number/Cause Code Total
- 1.
Plant 012erations 14/A 1/B 10/C 12/E 9/X 46
- 2.
Radiological Controls 1/E 1
- 3.
Maintenance 2/A 1/B 6/C 9/E 3/X 21
- 4.
Surveillance 2/A 3/B 4/C 1/D 30/E 4/X 44
- 5.
Fire Protection 4/A 4
- 6.
Emergency Pre12aredness
- 7.
Security and Safeguards
- 8.
Refuel in
- 9.
Licensing Activities
- 10.
Other (Original Design Errors and Equipment Failures Not Classifiable Into Areas 1-92 7/B 11/E 1/X 19 TOTAL 135 Cause Codes:
A - Personnel Error B - Design, Manufacturing, Construction, or Installation Error C - External Cause D - Defective Procedures E - Component Failure.
X - Other 27
f TABLE 2 VIOLATIONS (9/1/81 - 8/31/82)
SALEM NUCLEAR GENERATING STATION A.
Number and Severity Level of Violations
- 1.
Severity Leve 1 Common Unit 1 Only(*)
Unit 2 Only(**)
Deviations 0
0 0
Severity Leve 1 I 0
0 0
Severity Leve 1 II 0
0 0
Severity Leve 1 III 2
0 0
Severity Level IV 12 3
5 Severity Leve 1 v 8
4 1
Severity Leve 1 VI 2
0 1
Total 24 7
7 B.
Violations Vs. Functional Area FUNCTIONAL AREAS I
II III IV v
VI VIG INF DEF DEV 2*
2*
1**
1**
1**
1
- 1.
Plant 02erations 3
2 1*
2*
- 2.
Radiological Controls 1
1**
3 1**
- 3.
Maintenance 2
- 4.
Surveillance 1**
2 1
- 5.
Fire Protection 1**
- 6.
Emergency Pre2aredness
- 7.
Security & Safeguards 1
7 1
- 8.
Refuel in
- 9.
Licensing Activities
- 10.
Others Totals 2
20 13 3
Total Violations = 38 28
I ;
If
- 1.
- 2.
- 3.
- 4.
- 5.
- 6.
- 7.
- 8.
TABLE 3 SALEM NUCLEAR GENERATING STATION INSPECTION HOURS
SUMMARY
September 1, 1981 - August 31, 1982 HOURS Plant Operations 2153 Radiological Controls 315 Maintenance 160 Surveillance 159 Fire Protection 166 Emergency Preparedness 40 Security and Safeguards 705 Refueling/Outage Activities 126 Total 3824 29
% OF TIME 56.4 8.2 4.2 4.2 4.3 1.0 18.4 3.3 100%
~ :
.t_
~*
REPORT UNIT 1 UNIT 2 81-23 81-21 81-22 81-23 81-24 81-24 81-25 81-25 81-26 81-26 81-27 81-27 81-28 81-28 81-29 81-29 81-30 81-30 82-01 82-01 82-02 82-02 82-03 82-03 82-04 82-0:4*
82-05 82-08 82-06 82-05 TABLE 4 INSPECTION REPORT ACTIVITIES SALEM NUCLEAR GENERATING STATION INSPECTOR Resident Specialist Specialist Specialist Resident Specialist Resident Resident Specialist Specialist Resident Specialist Specialist Specialist Resident Resident 30 AREAS INSPECTED Routine Startup Test Program Startup Tests Material Control and Accounting Routine Fire Protection Design Changes Routine Management Meeting (SALP)
Routine Radiation Protection Startup Test Program Routine Chemi ca 1 and Radi ochemi ca 1 Measurements Program Physical Protection Refueling Radiation Protection Routine Routine
Table 4 (Con't)
REPORT INSPECTOR AREAS INSPECTED UNIT 1 UNIT 2 82-07 82-06 Specialist Design Changes and Modifications 82-08 82-07 Specialist Waste Shipment at Chem~Nuclear Systems, Inc. Burial Site
.82-09 82-11 Specialist Physical Protection (Strike Related) 82-10 82-09 Resident Routine 82-11 82-10 Specialist Training Program 82-12 82-13 Resident Routine.
82-13 82-12 Investigator Followup on Steam Generator Feed Pump
- Trip of April 28, 1982 82-14 82-14 Resident Routine 82-15 82-15 Specialist Physical Protection 82-16 82-16 Management Meeting (Post-Strike Security) 82-17 82-17 Resident Routine 82-18 82-18 Specialist Fire Protection/Pre-vention Program 82-19 82-19 Resident Routine 82-20 82-20 Specialist Radiation Protection 82-21 82-22 Investigator Inverter Trip of August 9, 1982
- 31
I I
I UNIT 1 82-22 82-23 82-24 REPORT UNIT 2 82-21 82-23 INSPECTOR Specialist Specialist Specialist Table 4 (Con'tJ AREAS INSPECTED Maintenance and Calibration IST Physical Protection
I t
qi Inspection Number Unit 1 Unit 2 81-23 81-21 81-23 81-21 81-21 81-23 81-25 81-27 81-29 81 81-Z9 81-29 82-01 82-01 82-01 82-01 82-01 ATTACHMENT ENFORCEMENT DATA SALEM NUCLEAR GENERATING STATION September 1, 1981 - August 31, 1982 Inspection Date Subject 8/ 4-9/14/81 Failure to Perform Periodic Survei 11 ances 8/4-9/14/81 Failure to Comply With Technical Specification Requirements Prior to Mode Changes 8/4-9/14/81 Failure to Comply With a License Condition 9/2-3/81 Failure to Monitor Steam Generator Slowdown 9/15-10/19/81 Failure to Post Airborne Radioactivity Area 10/20-11/23/81 Failure to Submit a Report as Required by the License 11/24-12/31/81 Failure to Establish, Imple-ment, and Maintain Procedures 11/24-12/31/81 Failure to Perfonn a Safety Evaluation 1/1-2/8/82 Failure to Follow/Implement Procedures 1/1-2/8/82 Failure to Properly Approve and Issue a Procedure 1/1-2/8/82 Failure to Make a Report in Accordance with 10CFRS0.72 1/1-2/8/82 Failure to Foll ow Radiation Protection Procedure 33 Reg.
Sev.
Area TS VI 4
TS IV 1
TS IV 3
ETS IV 2
10CFR20 v
2 DPR-75 VI 1
TS v
1 10CFRSO IV 3
TS IV 1
TS v
1 10CFRSO IV 1
TS 6.ll
- IV 2
l e
Inspection Inspection Number Date Subject Reg.
Sev. Area Unit 1 Unit 2 82-02 82-02 1/18-21/82 Failure to Have Calibration ETS v
2 Procedure 82-02 82-02 1/18-21/82 Failure to Make Provisions ETS v
2 for Preserving Composite Samples 82-03 82;..03 1/11-15/82 Failure to Maintain the Sec.Plan IV 7
Integrity of the Protected Area Barrier 82-03 82-03 1/11-15/82 Failure to Detennine a Sec.Plan IV 7
Need Prior to Revalidating Contractor Personnel's Access into Vital Areas 82-03 82-03 1/11-15/82 Failure to Completely Sec.Plan v
7 Search a Vehicle Prior to Entry into the Protected Area 82-03 82-03 1/11-15/82 Failure to Provide Adequate Sec.Plan IV 7
Compensatory Measures During the Loss of a Peri-meter Intrusion Detection System 82-05 82-08 3/9-4/5/82 Failure to Follow Tagging TS IV 3
Procedures 82-05 2/9-3/8/82 Failure to Post Fire TS IV 5
Watches at Open Penetrations 82-06*
2/9-3/8/82 Failure to Apply for 10CFRSO IV 1
Timely Operator License Renewal 82-07 82-06 2/8-11 and Failure to Address Program App. B VI 1
17-18/82 Effectiveness in QA Audit Reports 82-08 82-07 1/22/82 Delivery of a Shipment of 10CFR71.5 III 2
Licensed Material to a Carrier for Transport with two Containers of Shipment Not Strong and Tight 34
Inspection Inspection Number Date Subject Reg.
Sev. Area Unit 1 Unit 2 82-10 4/6-5/11/82 Failure to Make a 50.72 10CFR50 IV 1
Report 82-10 4/6-5/11/82 Failure to Monitor Gaseous TS v
2 Release 82 82-13 5/12-6/8/82 Failure to Review and TS v
1 Approve Procedures 82-13 5/12-6/8/82 Failure to Perfonn Sur-TS IV 4
veillance Tests on Containment Valves 82-14 6/9-7/6/82 Failure to Follow Proce-TS v
1 du res 82-15 82-15 6/14-18/82 Failure to Maintain Vital Sec.Plan III 7
Area Barrier 82-15 82-15 6/14-18/82 Failure to Report Security 10CFRS0.54 IV 7
Plan Changes 82-15 82-15 6/14-18/82 Failure to Provide Adequate Sec.Plan IV 7
Illumination 82-15 82-15 6/14-18/82 Misuse of Photobadge Sec.Plan IV 7
82-15 82-15 6/14-18/82 Failure to Secure Vehicles Sec.Plan IV 7
82-17 82-17 7/7-8/3/82 Failure to Provide As-Built 10CFRSO, IV 1
Drawings App. B 82-17 7/7-8/3/82*
Failure to Follow Report-TS v
1 ing Procedures 82-19 82-19 8/4-31/82 Failure to Follow Radia-TS 6.11 v
2 tion Protection Procedures 82-22 82-21 8/23'-27 /82 Failure to Control Test App. B v
4 and Measuring Equipment 82-22 82-21 8/23-27/82 Failure to Effect Timely App. B v
4 Corrective Action 35