ML20149F758
| ML20149F758 | |
| Person / Time | |
|---|---|
| Issue date: | 08/25/1994 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20147B843 | List: |
| References | |
| FOIA-96-351 NUDOCS 9409080198 | |
| Download: ML20149F758 (8) | |
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! INPUT TO THE SAFETY EVALUATIOM REPORT i R00 CONTROL SYSTEM EVALUATION PROGRAM l WESTINGHOUSE OWNERS GROUP WCAP-13864 i
1.0 INTRODUCTION
Salem Unit 2 experienced multiple failures of the rod control system (RCS) during startup following the Cycle 7 refueling outage. The most serious failure occurred on May 27, 1993, when Salem Unit 2 experienced uncontrolled withdrawal of a single rod cluster control assembly (RCCA). As a result of this event, the Nuclear Regulatory Commission (NRC) issued a Generic Letter (GL) 93-04, " Rod Control System Failure and Withdrawal of Rod Control Cluster Assemblies, 10 CFR 50.54(f)." NRC also activated the Westinghouse Owners Group (WOG) Regulatory Response Group (RRG) to address the staff's concerns with RCS. In order to respond to the staff's concerns, WOG initiated the evaluation and testing of the RCS. By letter dated July 12, 1994, WOG submitted the results of their evaluation and test program in Topical Report WCAP-13864, Revision 1, " Rod Control System Evaluation Program". The WOG evaluation program consisted of three parts which are identified below:
- 1. RCS Performance Review
- 2. Failure Assessment l 3. RCS Test Program l
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Our evaluation covers the review of the last two parts of the report. The first part deals with compliance with the General Design Criterion (GDC) 25, which will be reviewed by the Reactor System Branch. 2.0 EVALUATION WOG continues to believe that the current RCS design meets GDC 25 requirements. However, in order to resolve the staff's concerns with the RCS design, WOG has proposed two options to enhance RCS performance. .These options are: (a) Current order timing changes and new current order surveillance. (b) New current order surveillance and new safety analysis. Topical Report WCAP-13864 covers option (a) only. Option (b) is discussed in another topical report which will be reviewed by the Reactor Systems Branch. The WOG proposal (a) is based on the failure assessment and RCS testing done at the Salem Training Center. We have reviewed the WOG basis and our I evaluation of the basis is discussed below, j l l 1
2.1 Failure Assessment of Logic Cabinet Current Orders The WOG failure assessment program was done with the following three primary objectives: Determine the failure mode based on the results of historical failures of the printed circuit boards (PCBs). Determine if any other corrupted current order condition should be examined as part of the RCS test program.
- Determine if any other corrupted current order condition will result with the new current order.
The failure assessment considered single failure in all the PCBs in the logic cabinets with both existing and new current orders. Since it is almost impossible to predict the failure effect of a signal or component that intermittently changes state or generates random noise during the fixed 780 milliseconds (ms) period of a slave cycle, WOG has incorporated this effect by considering the failure of decoder diode that shifts the point at which the current order changes state during the 780 ms period. However, since the diode failure is an undetectable failure, the staff, during a conference call on February 3,1994, asked WOG to justify this failure mode. WOG explained that the failure of one diode is based on the meantime between failure data from military specifications which exceed the time period of one refueling outage. The failure of the diode will be detected during the new surveillance I
l testing which will be performed every refueling outage. Based on this, multiple diode failures is not considered credible for this analysis. The failure assessment has considered all failures that can either cause one rod to move or not move out on an insertion current order or cause several rods to move out or not move out. WOG has analyzed failure of chips in the PCBs and determined that failure of the chip will not result in an unwarranted rod movement. WOG's review and failure analysis appears complete, reasonable and incorporates the Salem event. Based on this, we have concluded that the i new current order will fix the Salem problem. WOG performed tests (discussed in Section 2.2) at the Salem Training Center to demonstrate the fix and has committed to do similar testing under actual plant conditions at a nuclear power plant. 2.2 Rod Control System Test Program Following the RCS failures at Salem Unit 2, tests were performed at the Salem Training Center to determine the root cause of the failures. During these tests some differences were identified between the behavior of the rods in the plant and in the Training Center. WOG, in order to respond to GL 93-04, developed a test program to determine the corrective actions necessary to fix l the uncontrolled single rod movement in the plant. These tests were done at i l the Salem Training Center. The test program consisted of the following five basic tests: ?
l l -s-l
- Baseline cycle tests l
Coil current timing tests Effects of load on drive rod motion Drive line latching tests Effects on initial drive line heights WOG dropped the last two sets of tests based on the results of the first three sets of tests. The NRC staff witnessed the test at the Salem Training Center. l During these tests, WOG also verified the response of the RCS to the many failure modes which were identified in the failure assessment. WOG also i verified the response of the RCS to a range of timing values for each corrupted current order. However, since the response of the RCS in the plant differs from that in the Salem Training Center, WOG planned to verify the new current order in a lead plant before making a final recommendation. South Texas agreed to be the lead plant for this verification testing. During the tests at South Texas, Unit 1, on February 13 and 14, 1994, with the Salem type fault, it was determined that some rods may have moved inward rather than remaining stationary. However, the acceptance criteria for the test was that with the Salem type fault the rods will remain stationary. Based on this, Westinghouse, in consultation with WOG, decided to change the acceptance criteria to require that the control rods move in with the Salem type faulted current order (DNSPX fails low, with out motion demand). During i a meeting on March 9, 1994, between the staff and WOG at N7C headquarters, WOG I
l l presented the basis for this change and stated that Ginna will be the test i plant to demonstrate the acceptability of the change. I t l By letter dated May 11, 1994, WOG submitted the summary of the successful ' testing done at Ginna on April 14 and 15, 1994. This testing has demonstrated i that the new current order will not affect normal rod operations and will ; i preclude unwanted rod withdrawal in the presence of a Salem type failure. By i letter dated July 22, 1994, WOG also submitted the safety evaluation for the current order changes. We have reviewed this safety evaluation and find it acceptable. In their letter of July 12, 1994, WOG has provided a copy of Technical Bulletin (TB) NSD-TB-94-05-R0 dated May 6, 1994, and a copy of the
" Recommended Rod Control System Surveillance Test," MUHP-6002. The TB provides guidance to utilities about changing the current orders and the document on surveillance test provides guidance for the required testing.
The staff's review of TB identified two problems with the document. First, the TB referenced WCAP-13864, Revision 0, dated September 24, 1993, while the current orders are based on WCAP-13864, Revision 1, dated June 7, 1994. Second, the current order for the stationary gripper in the TB shows that the current reduces at 128 counts for both the "IN" and "OUT" cycle, while WCAP-13864, Revision 1, and surveillance test guidance document MUHP-6002 show that the current reduces at 127 counts for both the "IN" and "0UT" cycle. l
i e l During a conference between the staff and Steve Fowler of Westinghouse on August 11, 1994, Mr. Fowler explained that the counter steps from 1 to 127 and then resets to 0. Hence, 128(0) shown in the TB is the 0 step shown in the i other documents. We find this explanation acceptable. Mr. Fowler also agreed that Westinghouse will revise the reference to Topical Report-13864, Revision 1, instead of Revision 0. We find Westinghouse's commitment ] acceptable. i In the recommended rod control system surveillance test document, WOG i l j discussed three different surveillance tests; (A) slave cycle current order i
- test, (B) power cabinet V ref test, and (C) coil current test. WOG has recommended that either Tests A and C or Tests B and C should oe performed to 1
determine the failure in timing, communication and regulation. These tests 4 could be done in combination or separately according to the schedule i flexibility of the licensee. These tests are required to be performed once per refueling outage. We find the WOG recommendation acceptable.
3.0 CONCLUSION
Based on our evaluation of Topical Report WCAP-13864, Revision 1, and confirmation of the failure analysis by testing done at the Ginna plant, we have concluded that WOG has demonstrated that if individual licensees implement the current order timing changes and perform surveillance tests (A t and C) or (B and C) at every refueling outage, then the RCS will likely not
experience failures similar to that at Salem. WOG should revise the TB to include the correct reference to Revision 1 of Topical Report WCAP-13864 and issue it to all the Westinghouse plants with solid state RCS.
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UNITED ST/.TES s a NUCLEAR REGULATORY COMMISSION
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k*...*,/ wAsmW4 TON, D.C. 30806 0001 September 28, 1994 Docket Nos. 50-272, 50-311 License Nos. DPR-70, DPR-75 l Mr. Steven Miltenberger Vice President and Chief Nuclear Officer . Public Service Electric and Gas Company l P.O. Box 236 l Hancocks Bridge, NJ 08038
Dear Mr. Miltenberger:
SUBJECT:
NRC PERFORMANCE ASSESSMENT OF SALEM i Between July 11 and August 25, 1994, a special team under W direction of the Special Inspection Branch of the Office of Nuclear Reactor Regulation completed a comprehensive assessment of perfomance et ti.e Sales Nuclear ' Generating Station. This assesseerd was conducted under a pilot NRC program designed to develop a customized inspection plan t,ased on an objective, integrated review of performance insights confirmed through an onsite assessment. The results of the team's in-office review of documentation were l sent to you on August 4, 1994. The team than performed a 2-week onsite ! evaluation which was concluded on August 25, 1994. The results from the first phase docue ntation review have been combined with the results of the team's onsite evaluation and assembled on a Final Performance Assessment / Inspection Planning Tree which is included with ?.he enclosed assessment report. The team determined that increased NRC inspection i is warranted in the areas of licensee control systems and maintenance, normal NRC inspection is warranted in the areas of operations and engineering, and reduced NRC inspection is warranted in the area of plant support. Within the above areas, we are particuiarly encarned about the failure to establish aggressive quality oversight of the Salem facility and to proactively correct system and equipment dr7tciencies before such deficiencies lead to challenging plant events. We are Liso concerned with the many , weaknesses identified with ycur maintenance progr.am. Weaknesses were noted in procedural adherence, post-maintenance testing, and control of work activities. In the area of operaticas, we are encouraged by many of your recent initiatives and the improved performance in the conduct of operations in the control rooms; however, many operational "workartwnds" still exist that require operators to take nonroutine actions to ccuper., ate for degraded equipment conditions. Current engineering design work appea,5 to be good, but t effective engineering oversight of vendor-designed modificti 3ns was not i l always apparent. The plant support areas of radiation prot stion, . emergency t j preparedness, security, and fire protection continue to show strong p i 9' i
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_. _ _ _ __ _ ~. _ _ _ _ _ _ _ - . _ _ . .. l b Mr. Steven Miltenberger . performance. No response to this report is required. Any enforcement actions resulting from this assessment will be issued by Region I via separate correspondence. Should you have any questions cencarning this assessment, i please contact Mr. Robert Gallo at (301) 504-2967 or Mr. Jeffrey Jacobson at (301) 504-2977. 1 i Sin rely, Agh,O 1 n . D1re l Division of Reactor Pro e ts I/II Office of Nuclear Reactor Regulation l
Enclosures:
As stated l l l l
9 Mr. Steven Miltenberger Salem Nuclear Generating Station, Public Service Electric Units 1 and 2 and Gas Company i ! cc:
- Mark J. Wetterhahn, Esquire Regional Administrator, Region I Winston & Strawn U.S. Nuclear Regulatory Coinnission
- 1400 L Street, NW 475 Allendale Road l Washington, DC 20005-3502 King of Prussia, PA 19406 i Richard Fryling, Jr., Esquire Lower Alloways Creek Township
) Law Department - Tower SE c/o Ms. Mary O. Henderson, Clerk i 80 Park Place Municipal Building, P.O. Box 157 Newark, NJ 07101 Hancocks Bridge, NJ 08038 1 j Mr. J. Hagan, Acting Mr. Frank X. Thomson, Jr., Manager j General Manager - Salem Operations Licensing and Regulation . Salem Generating Station Nuclear Department P.O. Box 236
- P.O. Box 236
{ Hancocks Bridge, NJ 08038 Hancocks Bridge, NJ 08038 l Mr. Charles S. Marschall, Senior Mr. David Wersan
- Resident Inspector Assistant Consumer Advocate
- Salem Generating Station Office of Consumer Advocate i U.S. Nuclear Regulatory Commission 1425 Strawberry Square i Drawer I Harrisburg, PA 17120 1
Hancocks Bridge, NJ 08038
- Ms. P. J. Curham, Manager i
- Dr. Jill Lipoti, Asst. Director Joint Generation Department i Radiation Protection Programs Atlantic Electric Company
- NJ Department of Environmental P.O. Box 1500 l Protection and Energy 6801 Black Horse Pike
! CN 415 Pleasantville, NJ 08232 i Trenton, NJ 08625-0415
- Mr. Carl D. Schaefer l Maryland People's Counsel External Operations - Nuclear l American Building, 9th Floor 1 Delmarva Power & Light Company j 231 East Baltimore Street P.O. Box 231 l 2 Baltimore, Maryland 21202 Wilmington, DE 19899 J
l Mr. J. T. Robb, Director Public Service Commission of l Joint Owners Affairs Maryland , Philadelphia Electric Company Engineering Division . 955 Chesterbrook Blvd., 51A-13 Chief Engineer ! Wayne, PA 19087 6 St. Paul Center Baltimore, le 21202-6806 , Richard Hartung Electric Service Evaluation Mr. S. LaBruna Board of Regulatory Commissioners Vice President - Nuclear Engineering 2 Gateway Center, Tenth Floor Nuclear Department Newark, NJ 07102 P.O. Box 236 Hancocks Bridge, NJ 08038
cc: (con't) Mr. Steven E. Miltenberger Mr. Dennis J. Zannoni, Supervisor Vice President and Chief Nuclear Bureau of Nuclear Engineering Officer Radiation Protection Programs Public Service Electric and Gas NJ Department of Environmental Company Protection and Energy P.O. Box 236 CN 415 Hancocks Bridge, NJ 08038 Trenton, NJ 08625-0415 Mr. A. C. Tapert, Program Adm. Ms. Corinne P. Davis Office of Radiation Control 841 Main Street - Canton Division of Public Health Salem, NJ 08079 Bureau of Environmental Health Cooper Building P.O. Box 637 Dover, DE 19903
ENCLOSURE FINAL PERFORMANCE ASSESSMENT RESULTS - SALEM Report Nos.*50-272/94-201 and 50-311/94-201 Licensee: Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, NJ 08038 Docket Nos. 50-272 and 311 License Nos. DPR-70 and DPR-75 Facility Name: Salem Nuclear Generating Station Units 1 and 2 Assessment Conducted: July 11, 1994 - August 25, 1994 Team Members: R. Gallo, Team Manager, Special Inspection Branch, NRR J. Jacobson, Team Leader, Special Inspection Branch, NRR J. D. Wilcox, Jr., Special Inspection Branch, NRR J. Zimmerman, Project Directorate I-2, NRR G. Galletti, Human Factors Assessment Branch, NRR F. Huey, Region IV 1 T. Stetka, Region IV R. Westber , Region III Prepared by: f/ o a 9/26/f> JeffreyA .~ c son D ean Leader Date Team Irfspe t n Section A Special Inspection Branch Division of Reactor Inspection and Licensee Perfomance Office of Nuclear Reactor Regulation i;;teiC' 2d Robert M. Gallo, Chief 9/uh4 Date Special Inspection Branch Division of Reactor Inspection and Licensee Performance Office of Nuclear Reactor Regulation 4'4 id :W -H67'
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4 1 l 4 TA8LE OF CONTENTS , l EXECUTIVE
SUMMARY
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, PURPOSE AND SCOPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 5
1.0 LICENSEE CONTROL SYSTEMS . . . . . . . . . . . . . . . . . . . . . . 2 i l.1 Problem Identification . . . . . . . . . . . . . . . . . . . . 2 l ! 1.2 Root-Cause Analysis ..................... 3 i j 1.3 Trending and Evaluation ................... 7 1.4 Corrective Action Tracking Systems
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i 2.0 OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 l 2.1 Safety Focus and Management Involvement ........... 8 2.2 Problem Identification and Resolution ............ 9 1 2.3 Quality of Operations .................... ,10 2.4 Programs and Procedures ................... 12 3.0 ENGINEERING ............................ 13 l 3.1 Safety Focus and Management Involvement ........... 13 ' 3.2 Problem Identification and Resolution ............ 14 3.3 Understanding of Design ................... 15 3.4 Quality of Engineering Work ................. 17 3.5 Programs and Procedures ................... 18 4.0 MAINTENANCE ............................ 18 4.1 Safety Focus / Management Involvement ............. 19 4.2 Problem Identification / Problem Resolution .......... 20 4.3 Material Condition . . . . . . . . . . . . . . . . . . . . . . 4.4 Quality of Maintenance Work 21
................. 22 4.5 Programs And Procedures ................ . 24 5.0 PLANT SUPPORT ......................... . 26 5.1 Safety Focus and Management Involvement ........... 27 5.2 Problem Identification and Resolution ............ 27 5.3 Quality of: ......................... 27 5.4 Programs and Procedures ................... 29 6.0 EXIT MEETING . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 PERFORMANCE ASSESSMENT / INSPECTION PLANNING TREE. . . . . . . . . . . . . . 30
~ EXECUTIVE SUpeiARY Between July 11 and August 25, 1994, a special team under the direction of the Special Inspection Branch of the Office of Nuclear Reactor Regulation conducted a comprehensive assessment of performance at the Salen Nuclear Generating Station. The team comprised six NRC inspectors, a team leader, and a team manager, all whom were independent of the normal oversight of the Salem site. The purpose of the assessment was to develop a comprehensive evaluation of performance at the Salem Nuclear Generating Station to aid in focusing future NRC inspection resources at the Salen site. The overall assessment results are presented on a Performance Assessment / Inspection Planning Tree which is included at the end of this report. The details of the team's findings are in the assessment report. In summary, the team determined that increased NRC inspection is warranted in the areas of licensee control systems and maintenance; normal NRC inspection is warranted in the areas of operations and engineering; and reduced NRC inspection is warranted in the area of plant support. In the area of licensee control systems the team determined that, although the framework for effective control systems is in place, management and implementation of control systems have been ineffective. Nanagement oversight of corrective action program activities has been weak, adequate root cause evaluations have not been consistently performed, and effective corrective action performance indicators do not currently exist. In addition, key positions within the quality oversight organization remain unfilled, and key personnel in other organizations involved with corrective action system implementation are new to their positions and lack clear guidance with regard to their corrective action enhancement responsibilities. The team noted that recent improvements have been made in the area of operations, specifically in the conduct of operations in the unit control rooms. Control room demeanor, sensitivity to equipment anomalies, and communications all seem to have improved significantly from the period covered by the team's in-office documentation review. Weaknesses were, however, identified in management oversight of operational enhancements and resolution of operational workarounds and bypasses. The team noted that the large number of operational enhancements recently instituted to improve performance, combined with a recent increase in emergent work activities presented a challenge to some operations personnel. Operational workarounds, which require operators to take nonroutine actions to compensate for degraded equipment conditions, have only recently begun receiving appropriate attention. Overall, current engineering work, programs, and procedures. appear to be acceptable, but engineering has not demonstrated the ability to proactively ; seek out and correct system and component deficiencies before they lead to increasingly challenging plant events. For example, longstanding problems l associated with the circulating water system, rod position indication, and I excessive reactor cooldown transients are only recently being resolved. In addition, engineering work priorities do not seem to be driven by the needs of the plant, and errors made during the original plant design and during recent vendor-engineered design modifications continue to challenge plant operations. 1
Significant weaknesses were found in both maintenance programs and in maintenance program implementation. These weaknesses included an overreliance on the use of generic troubleshooting procedures, ineffective use of the procedure feedback process, inadequacies in the post-maintenance testing program, the inexperience of backshift personnel, and procedural adequacy and adherence concerns. The team also expressed some concern regarding the control and oversight of the numerous groups and organizations that perform maintenance and modification type work on site. The maintenance organization performed well in prioritizing work, disseminating operating experience feedback information, identifying equipment problems, and general plant housekeeping. The plant support areas of emergency preparedness, fire protection, security, and health physics continue to perform strongly. During the team's in-office review, few concerns were raised about the plant support area and, as a result, only limited time was spent onsite evaluating these activities. Management and communications within the various plant support organizations were noted to be effective. Problem identification was proactive and effective, and programs and procedures were good. Performance indicators in the health physics area continue to show good ALARA results and good contamination control. Security, in spite of some incidents, has aggressively pursued identified issues. A. team review of the emergency preparedness facilities was favorable. Response to Appendix R fire protection issues was also acceptable. 1 11
1 PURPOSE AND SCOPE The purpose of the assessment was to develop a comprehensive evaluation of performance at the Salem Nuclear Generating Station to aid in focusing future NRC inspection resources at the Salem site. The assessment was based on an in-office, integrated review of documentation, followed by a broad-scope onsite performance-based review. The in-office portion of the assessment consisted of a 3-week review of NRC l inspection reports, licensee event reports, performance indicators, event l investigations, licensee self-assessments, and other documentation. The documentation review covered the period between January 1,1992, and July 31, 1994. Upon completion of the in-office assessment, the team issued a preliminary assessment report by letter dated August 4, 1994, which detailed the team's findings. A 2-week onsite assessment was then conducted between August 15 and August 25, 1994. The onsite assessment focuseo on programmatic
- areas determined to be weak during the in-office review, as well as on those areas that were indeterminate.
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The assessment team was comprised of six NRC inspectors, a team leader, and a : team manager, all whom were independent of the normal oversight of the Salem l site. a After the completion of the onsite assessment, the team performed a comprehensive evaluation using the findings of both the in-office review and the onsite assessment. The results of this evaluation are presented on a Performance Assessment / Inspection Planning Tree, which is attached to this report. The tree is divided into five individual performance areas: licensee control systems, operations, engineering, maintenance, and plant support. These individual performance areas have been subdivided into individual I elements. Each performance area, as well as each individual element, has been assigned a rating based upon the assessment results. Areas and elements where reduced, normal, and increased NRC inspection appear to be warranted have been assigned green, yellow, and red ratings, respectively. The bases for the individual ratings are given in the following report. I 1
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l 1.0 LICENSEE CONTROL SYSTEMS ] The licensee has not demonstrated the ability to identify, evaluate, and ! correct plant problems before they result in significant plant events. ! Although senior licensee management recognizes this deficiency and has j implemented a corrective action enhancement program to improve performance in l each of the licensee control system areas (e.g., problem identification, root-cause evaluation, trending, and corrective action tracking), these measures have not yet been fully implemented or had sufficient time to take effect, and significant plant problems continue to recur. Key positions within the licensee's quality oversight organization remain unfilled, and many people in other organizations involved with corrective action system implementation are new to their positions and lack clear guidance with regard to their specific corrective action enhancement responsibilities. As a result, the licensee's approach to implementation of its corrective action enhancement program has been fragmentary and uncoordinated, and the various program elements have not been properly integrated into an effective corrective action system. Quality oversight of corrective action program activities has been weak, appropriate root-cause evaluations have not been consistently implemented, and - effective corrective action performance indicators do not currently exist. As a result, implementation of effective corrective action for routine problems remains inconsistent, with continuing examples of significant or recurring plant problems. Senior licensee management has recognized this problem and has made consiitments to correct it. Better definition and prioritization of the involved tasks, clearer assignment of individual responsibilities, and more effective use of corrective action performance indicators are needed to ensure more timely and effective completion of this effort. 1.1 Problem Identification The licensec's systems for identifying plant problems were well defined with good procedures and problem-reporting tools within each of the several , organizations involved in site activities. Although in the past, personnel have been reluctant to fully utilize available problem reporting tools, the i team noted that license management has recognized this reluctance and is addressing the concern. l Weaknesses were, however, identified in oversight, evaluation, and management l of quality oversight activities. The weaknesses were indicated by repetitive, 3 significant plant problems and were confirmed by the assessment, which ' determined that recent quality oversight audits and surveillance activities have not been effective in identifying existing plant problems. For example: l The Sales quality assurance (QA) organization has not audited the ! licensee's significant event response team (SERT) process, and the ! nuclear safety review (NSR) organization has audited the SERT process at Sales only once, in September 1993. This audit addressed only whether corrective actions recommended in the SERT report had been satisfactorily completed. The audit was not sufficiently performance-2
l s 2 based or probing of the SERT implementation process to identify problems
- similar to those noted during this assessment and described in Section j 1.2 of this report.
j
- The site QA organization observes ongoing plant activities using a QA
- surveillance checklist. The checklist does not include a specific j requirement to verify that deficiencies or problems encountered during j observed work activities are appropriately documented and reported. The
) absence of such a requirement is significant considering the history of problems described in recent licensee event root-cause evaluations. l !
- The team reviewed approximately 20 recent QA surveillance reports, involving approximately 250 hours' of site QA surveillance activities, and noted that this effort revealed only two deficiencies (one related
- to a turbine part number documentation discrepancy and one related to i clearance tagging discrepancies). These site QA surveillance results j appear inconsistent with the number of problems identified by the 4
licensee during recurring plant events and with the types of problems observed during this NRC assessment.
- Although currently being addressed by management, significant operations department weaknesses were not identified during QA surveillances.
The team determined that normal NRC inspection effort is warranted in this area. The team recommends that the inspection effort focus on how effectively licensee quality oversight activities identify significant performance j weaknesses, and how well licensee management evaluates the effectiveness of ' quality oversight activities. 1.2 Ep.phCause Analysis The licensee has developed a good-root cause analysis capability, which, when proparly implemented, was considered to be effective in establishing the root causes of problems associated with significant plant events and important equipment failures. The licensee has trained site personnel on root-cause i methods and applications and solicits outside expert help for complex l component failure analyses. The licensee has also implemented the root-cause ' process for some human performance problems. > Nevertheless, the licensee has not taken full advantage of this capability. For example, the significant event response team (SERT) is the highest level tool used at Sales to independently assess significant plant events. As described by the licensee's administrative procedure (NAP-0061), the SERT is intended to be independent of other investigative processes at Sales and to produce.a " stand alone" document which gives an " accurate and comprehensive" report of the root causes of concerns contributing to or complicating an event, as well as associated corructive actions to preclude recurrence. The team concluded that Salem is not realizing the full potential benefit of the SERT process. Corrective action system deficiencies are allowing uncorrected plant problems to escalate into significant plant events, and the SERT process is not identifying deficiencies in the corrective action systems. 3 l I
The team identified the following generic problems affecting the licensee's implementation of the SERT process: Some SERT reports have incorrectly identified the root cause of events (i.e., identified the wrong root cause or identified only a symptom). Some SERT reports hava not addressed any root cause or corrective action l for significant contributing or complicating problems identified by the SERT report. Some SERT reports have identified precursors to significant events (i.e., the same problem occurred before with less significant results); however, the SERT reports did not identify why existing corrective action systems failed to previously identify and correct the earlier problem. 1 The corrective actions recommended by some SERT reports have not been l tracked or completed as required. ' The team leader and several members of one of the SERT teams had no documented training on how to perform root-cause evaluation. l
- The SERT implementing procedure was deficient in not (1) clearly l defining SERT membership qualification requirements, (2) specifying I that the SERT report should clearly describe the SERT charter or l objectives, and (3) clearly requiring that the SERT report should l specifically describe the root cause and needed corrective actions for all problems which were identified as resulting in, contributing to, or complicating an event.
l l Two SERT reports illustrate the concerns noted above: SERT 94-01 (Reactor Trin on Low Steam Generator Level - 1/27'M1 The SERT report noted that the #14 steam generator (SG; level control loop hac' experienced control problems on January 27, 1994, causing the 14BF19 feedwater (FW) regulating valve to close rapidly when placed in automatic. (The same problem occurred on May 25, 1993, but was not severe enough to trip the reactor.) However, the SERT report did not l address the root cause of why an adequate root-cause and corrective-l action evaluation had not been performed after the May 25, 1993, problem. During an interview with tha system engineer, the team discovered that, although a troubleshooting work order (WO) (WO 930527169) had recommiended K2 relay replacement, the relay was not replaced. The vendor evaluatsd the SG 1evel error controller after the January 27, 1994, trip and found that the controller had failed because of a defective K2 relay. These detail. were not discussed in the SERT report. l
- The team reviewed previous problems with BF19 FW regulating valves and i identified several problems which indicated that the root causes of l recurring or potentially generic problems were not properly evaluated 4
i l
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! when the problems first occurred. These failures to effectively j
identify and correct the root causes of routine problems before they resulted in significant events were r.ot addressed by the SERT report. l In particular:
' (1) Incident Report (IR) 92-367, dated June 6, 1992, stated that valve 24BF19 had failed to control in automatic; however, i referenced W0s described no troubleshooting, and the IR was closed
{ without any root cause being identified. l (2) 1R 93-195, dated March 11, 1993, stated that valve 13BF19 failed i full open in automatic and that a control board was replaced 1 (4111194-001). A similar control board (4111194-002) had to be
! replaced after the failure of valve 14BF19, which resulted in the j reactor trip :ddressed by SERT 94-01.
I (3) When valve 148F19 failed to control on May 23, 1993, no IR was 1 written, and WO 930525090 failed to identify any apparent reason i or root cause for the problem. The licensee's administrative { procedure (NAP-0006) requires an IR for component malfunctions j involving potential design or maintenance deficiencies. ! (4) WO 930720171 replaced a bad summator (IFM500H) on valve 14BF19,
! which had failed to properly control in automatic; however, no IR i was written to address the root cause.
(5) IR 94-044, dated February 9,1994, stated that valve 13BF19 failed to control in automatic and that control board 4111194-002 was )' replaced. However, the root-cause evaluation did not address why j similar control boards had to be replaced in the past. i
- (6) The reactor tripped again on June 6, 1994, valve 218F19 failed to
{ control in automatic (IR 94-182 and SERT 94-06). i i
! The SERT report stated that the root cause of the January 1, 1994, reactor trip was failure of the #14 steam generator level error l controller, which was replaced. However, the SERT report did not 3 address the root cause of the controller failure or prescribe corrective i action to prevent recurrence.
i
- The SERT report noted that SERTs 92-01 and 92-03 had recommended 1 corrective actions involving steam generator level control system preventative maintenance (PM), but these were not implemented before the January 27, 1994, event. The SERT report neither addressed the cause of the failure to implement the earlier SERT report recommendations nor identified corrective actions to prevent recurrence. The team noted that, as of August 23, 1994, the recommended PMs 'iad still not been implemented as issued procedures.
The SERT report incorrectly determined that the failure to perform the Pas recommended by SERTs 92-01 and 92-03 did not contribute to the reactor trip on January 27, 1994. In fact, the team determined that a 5
recommended PM to monitor steam generator level control system components for AC noise on the DC analog signals was designed to detect capacitor failure similar to that which contributed to the January 27, 1994, event.
- The SERT report stated that steam generator feedwater flow transmitter sensing line blockages (air pockets and sediment) resulted in sluggish auto level control and contributed to the January 27, 1994, event. The report recommended periodic blowdown to prevent recurrence, but did not address the root cause of why appropriate blowdowns had not been required before the trip. The team noted that Sales had experienced prior instances of sluggish steam generator auto level control.
- The SERT report noted that the Hagan 7100 system installed at Salem was recognized as being unreliable. Although the SERT report stated that eventually the licensee would replace the system, the SERT did not ask
,' the other utilities having the Hagan 7100 system whether or how they had been able to avoid problems similar to those affecting Salem.
SERT 94-05 (Reactor Trio Due to Generator Transformer Failure - 6/10/94) The SERT report stated that nos. 11 and 12 AF21 valves failed to open because the pressure transmitter in the pressure override defeat circuit failed. However, the SERT report did not address the root cause of the failure of the pressure transmitter. The SERT report identified several potential contributors to the problem of excessive plant cooldown after the reactor trip (steam dump control system overshoot, failure of the moisture separator reheater purge valves to close, steam losses). However, the SERT report did not address the root cause or correction of these individual problems. The SERT report identified numerous recurring equipment problems (13MS10 setpoint adjustment problems; nos. II, 13 and 14 MS167 salves drifting ! off their open limit after a turbine trip; unreliable event times from the P-250 computer; llHV3 FW heater channel head relief valve lifting and staying open after turbine trip). However, the SERT report did not address the root cause or correction of these recurring problems. ; The SERT report stated that breaker IEPX for the #12 pressurizer backup heater failed to close because of spring charging failure; however, the SERT report did not address the root cause of this problem or discuss why plant operators did not detect the problem earlier. The SERT report identified apparent inadequacies in design change packages (DCPs) IEC-3326 and IEC-3327 to correct problems associated with reactor coolant system (RCS) overcooling after reactor trips; however, the SERT report did not fellow through with cny a sessment or root-cause analysis of the DCP inadequacies, merely noting that main steam isolation valve closure is still required after trips. The SERT report stated that the root-cause evaluation of the potential 6
i . i i 1 l transformer failure which caused the reactor trip had not been i completed; however, the SERT report did not appear to list this as an i action to be tracked in the action tracking system. l l The team determined that increased NRC inspection effort is warranted in this
! area. The team recommends that the inspection effort focus on ensuring that i the licensee has appropriately identified and corrected the root causes of
] recurring problems. 4 1.3 Trendina and Evaluation l l The licensee has not done a good job in the past of trending and evaluating data from the many problem identification systems at Salem. The licensee has recognized this weakness and has established a comprehensive corrective action
- enhancement program. However, it is too soon to conclude whether this program i will fully correct past problems. Some of the licensee's enhancement ideas, i such as the computerized QA data base, are insightful and if promptly 1 d
implemented might help reduce the high volume of recurring problems at Salem. J j Although the correctiv'e action enhancement program is set forth in the
- licensee's Nuclear Department Tactical Plan (business plan), the overall i effort is behind schedule, and the licensee has not clearly implemented a i
useful detailed plan for identifying, prioritizing and tracking the key steps in the program implementation. Senior management guidance of this type is
- viewed as being especially important at this time, since several of the people tasked with this program are newly appointed to their current positions.
3 l The licensee has not defined useful performance indicators to gauge the j effectiveness of corrective action programs. Although the licensee has j currently defined an indicator for recurring equipment problems and these ! programs have improved, the licensee may also need to establish other 4 i indicators to highlight recurring problems within each of the major plant i organizations. In addition, since several recent SERT reports and irs j indicate continued repeat equipment problems, the current indicator for
- recurring equipment problems may need to be validated.
! The team determined that increased NRC inspection effort is warranted in this i area. The team recoamends that the inspection effort focus on assessing the i effectiveness of the licensee's implementation of the new QA data base, l validating selected corrective action system performance indicators, and i ensuring the new QA data base is coordinated with other trending and j evaluation efforts within other site organizations. 1 1 1.4 Corrective Action Trackina Svsi ng_ l 1 The licensee has established procedures for ensuring that corrective actions are completed for items captured within the corrective action systems. However, the team noted that tracking and carrying out commitments and i corrective actions has been a problem in the past and continues to be one, as
- some recent SERT reports show. The primary reasons for these problems are a j lack of consistency in the manner in which some action tracking system items
- are closed and insufficient commitment by cognizant managers to ensure that
{ all identified items are completed. Senior management has recognized this j 7 l l
~
problem and is working to correct it. The team reviewed the findings of ) several licensee self-assessment reports, NRC reports, vendor bulletins, and ' QA audits, and noted that appropriate corrective actions were captured by the licensee's action tracking system and appeared to have been completed in a timely manner or were being appropriately tracked. The team determined that normal NRC inspection effort is warranted in this i area. The team recommends that the inspection effort focus on verifying that the licensee has implemented an effective followup process to ensure that the corrective actions not only have been tracked and signed off as cot:1ete, but . have actually corrected the original problems. l 2.0 OPERATIONS Historically, the operations department at Sales has been challenged by longstanding equipment and design concerns, organization and management l changes, and unanticipated transients and events. As a result, operations ! management informally initiated numerous enhancements and modifications to operations programs. The team's onsite assessment of Sales operations noted marked improvement in control room activities, compared to the recent historical record. Facility operation was generally satisfactory. However, l based on team's review, weaknesses were identified in the site management's oversight of operations, the QA assessments of operations activities, and the resolution of the operations workaround and bypass list. 2.1 Safety Focus and Manaaement Involvement The team's historical review indicated that the licensee's performance in outage planning and consideration of shutdown risk (i.e., outage risk management) appeared adequate. However, certain past activities indicated weaknesses in safety focus and management involvement. Examples are (1) the decision to restart Unit 2 after four aborted reactor startups due to rod control failures, (2) the intenticoal entry into Technical Specification (TS) 3.0.3 by repeatedly closing containment isolation valves and for troubleshooting rod position indication system failures, and (3) the failure to recognize temporary modifications associated with providing temporary power to the No.12 auxilliary building fan and installing a blank flange in the service water system as changes to the updated final safety analysis report. During the site visit the team reviewed portions of Salem's program for outage risk management and the licensee's process for equipment and system operability determinations. The team also reviewed a representative sample of justifications for continued operations (JC0s), Salem technical specification interpretations (TSIs), and operations personnel overtime records. The team'detemined that the licensee's implementation of JCOs and TSIs was adequate. The JC0s and TSIs were clear, concise, and appropriately documented. Overtime usage, except as discussed below, was not excessive. Based on the historir.al infomation and the site observations, the team determined that site management needs to improve its general oversight of
- operations activities. This determination was based in part on the following
8
l l There was evidence that a large amount of emergent work coupled with implementation of programmatic improvements into operations was being performed without a well-defined systematic process. During the assessment, the licensee developed a list of improvements and modifications planned or being considered. The licensee had not ensured that these programmatic improvements were being implemented in an orderly, deliberate manner and that measures were in place to assess their effectiveness.
- There was a lack of clear guidance for operability determinations. As a result, Sales management recently issued an operator aid via the standing night order process. This aid should assist operations ,
personnel in making standardized operability determinations. Operations management encouraged feedback from the operating crews on the use of and effectiveness of this aid. These comments had not yet been incorporated into a revision of the operator aid, or put in a procedure. A large amount of emergent work in addition to normal operations l activities resulted in a saturated workload for the operating crews. l Because of the workload, shift supervisors needed longer than I hour to l turn their shifts over and effectively worked greater-than-13-hour i shifts. The outage risk management program was in its initial stages of development and was undergoing refinement. The team noted that the licensee had trained only two of the five operating crews on outage risk i before the last planned outage. The team determined that normal NRC inspection effort is warranted in this area. The team recommends that the inspection effort focus on management oversight of programmatic improvements, implementation and use of the operability flowchart, and implementation of the outage risk management program. l 2.2 Problem Identification and Resolution l The team's historical review indicated that operations responded adequately to event-identified issues. However, weaknesses in the licensee's resolution of longstanding concerns and the inadequate pursuit of problem resolution have apparently contributed to the overreliance on operator "workarounds." The terms "workarounds" and " bypasses" are defined in this report as nonroutine actions performed by the operating crews due to equipment not functioning as designed. Examples of longstanding concerns are (1) the excessive RCS cooldown events that have made operator transient response activities unneces'sarily complex, (2) rod control problems, (3) radiation- monitoring system anomalies, and (4) grass intrusion in the circulating water (CW) system. The last two concerns have contributed to operating events. During the site visit, the team reviewed portions of the licensee's process for identifying and formally tracking operator workarounds and bypasses. In addition, the team evaluated a representative sample of recent QA assessmeMs 9
~
r h; of operations activities, reviewed the operations department self-assessment process called the operator observation program, and conducted numerous plart tours. Based on the historical information and the site observations, the team determined that there appeared to be an increased sensitivity in identifying problems at Salem. This increased sensitivity was shown in two ways: s )
- The licensee had instituted plant tours to identify deficient plant J conditions. This effort increased the number of work requests issued and in turn increased the amount of emergent work and the need for increased planning and preparation.
In a questionnaire Ullas management asked the operating crews about the number of operator workarounds and bypasses at both Salem units. The
" results of the questionnaire revealed more than 50 operator workarounds.
Operations management determined that the workarounds had been previously identified and documented by operations personnel, but until recently, had not received appropriate attention. Because in the past responses to identifta concerns had not been adequately b addressed, the licensee decided that additional interdepartmental coordination was warranted, and had begun to implement a program to consolidate and ( prioritize all outstaadini work requests, design change requests, and operator workarounds and bypasses. The operations department recently implemented a revised operator observation program, governed by AD-01, " Operator Observation Program." The program sensitizes operations personnel to the importance of being self-critical and e of decumenting weaknesses and strengths in performance. Operations management was assembling this performance information into a database for trending and analysis. The team noted that quality assurance surveillance of operai. tons had not been performance based and that the surveillances had been ineffective at identifying significant previously existing operations department weaknesses. Plant tours by the team revealed the plant housekeeping to be generally acceptable. However, in low-traffic areas, the licensee's attention was occasionally warranted. The team determined that normal NRC inspection effort is warranted in this area. The team recommends that the inspection effort focus on operations self-assessment activities and resolution of the operator workaround and bypass list. 2.3 Quality of Ooerations The team's historical review indicated that the quality of operations du?ina event response and during outage activities appeared generally adequate. I However, deficiencies in operator performance during the recent grass 10
l intrusion event, numerous examples of operators failing to comply with procedures and technical specifications during routine operations, and the reliance on operator workarounds and bypasses pointed to weaknesses in the overall quality of operations. Additionally, inadequacies in normal and emergency operating procedures, deficiencies in simulator fidelity and in operator training, and the existence of longstandin contributed to weaknesses in operator performance. g plant equipment problems During the site visit the team reviewed portions of the licensee's safety tagging program, includinji the computerized system "TRISS" for work control and the current unavailab e equipment log. In addition, the team observed several operating crews performing noma operations, witnessed several shift turnover briefings, teured the Sa'en plant-reference training simulator, and discussed the operator training program with cognizant training personnel.
-Based on the team's obse N ation, the conduct of operations in the unit control rooms appeared to havs improved significantly recently. This determination is based in part on the following; Management had emphasized to operators its expectations for the operating crews; and the team noted an increase of sensitivity to acknowledgement of annunciators, more aggressive identification of l equipment anomalies, a heightened attention to crew communications, and l an overall professional conduct of the operating crews.
During shift turnovers, partinent information was apparently relayed to responsible operators; however, in one case (a manual rod control transient), pertinent information was not relayed to the nuclear control operator (NCO). Multiple turnover meetings between operations supervisors and other department supervisors appeared effective. Intradepartmental i communications, as during shift turnovers, were extremely well detailed. ' Additionally, the team determined that operations had established effective i clearance order and unavailable equipment log programs. Recent changes to ' these programs as a result of past performance weaknesses appeared positive, as evidenced by the following: Walkdowns of selected portions of systems indicated that valves, breakers, and components were appropriately positioned as indicated on the clearances. However, the team noted one exception in the fire protection area. This exception is described further in Section 4.0 of this report. The current unavailable or out-of-service (005) equipment log was being appropriately controlled by the work control center.
- The senior operations shift supervisor and the NCOs were aware of the items on the daily 00S leg.
l 11 I
Additional emphasis was placed on revising the process to reduce the large number of items on the 005 log. ) i The team determined that the operations department had recently revised the ' emergency operating procedures Owners Group Emergency Response (Guidelines (WOG During thisERG).E0Ps) revision, to meet with the help of the engineering organization and the computer aided design (CAD) process, numerous set points were changed, calculations made, and { j appropriate modifications to the E0P flowcharts accomplished. Additionally j the licensee was using a consulting firm to develop a detailed basis documen,t to encompass the overall E0P generation process. The team walked down the Salem training simulator and discussed training issues with Sales training personnel. This review indicated that the l i simulator was being maintained in close fidelity to the actual Unit 2 control m room via an annual review process. Databases of hardware and procedural fidelity issues were used to manage the program. Additionally, during crew training on the simulator, the training instructors were emphasizing managements' expectations for control room demeanor and conduct of operations. The training instructors discussed some programmatic improvements planned for the next training cycle, including the use of instructor-facilitated self-assessment techniques by the crews. The team determined that nt.cmal NRC inspection effort is warranted in this area. The team recommends that the inspection effort focus on the E0P upgrade to incorporate the WOG ERG Revision 18, the program for reducing equipment on the unavailable equipment log, and the program for ensuring a high standard of conduct of operations. j 2.4 Proarams and procedures . The team's historical review indicated that, although the licensee's procedure " upgrade program had been completed, procedural adequacy and usage may still be a concern. During the site visit the team reviewed portions of the licensee's procedure i upgrade program (PUP), interviewed procedure maintenance group (PMG) ; personnel, and reviewed a representative sample of normal operating procedures and their use, as well as associated administrative documents and computerized systems established to standardize the composition and untent of procedures. The team determined that in general, the PUP had resulted in the removal of ' unnecessary information and enhanced procedure clarity from operational procedures. Most operators appeared comfortable with existing procedures, but several operators considered that certain procedures were still overly detailed. 8:aed on the historical information and the site observations, the team determined that the PUP was officially completed in August 1993, with a considerable backlog of requests for procedure revisions still outstanding. The PMG inherited this backlog. Because of increased requests for procedure 12
revisions associated with emergent work activities, design changes, and an increased sensitivity to procedure quality, the licensee had not been able to achieve its performance goal of reducing the backlog to a point where new procedure revision requests can be turned around in I to 3 months. The PMG did not have a formalized method for assessing the quality of the improvements to procedures resulting from the PUP and current procedure revisions. However, the team did review the quality index process that was performed at the et,d of the PUP and the 1994 sidyear quality assessment i performed by the PMG which indicated that procedure quality had improved. ! Based on the year-to-date efforts, the PNG had not adapted these indicators as a way of trending the quality of the operating procedures over time. The use of the computer program "PRONET" and the PMG procedure writers training program provided a positive approach to maintaining standardization of l procedure upgrades and modifications after the forthcoming decentralization of l the group's function to each department. - The team determined that normal NRC inspection effort is warranted in this area. The team recommends that the inspection effort focus on the effectiveness of the PNG activities and the program to ensure the high quality , of operating procedures. l 3.0 ENGINEERING Current engineering design work, programs, and procedures were determined to ; be acceptable, but engineering has not demonstrated the ability to proactively seek out and correct system and component deficiencies before they lead to increasingly challenging plant events. For example, longstanding problems l with the CW system, rod position indication, and excessive reactor cooldown transients are only recently coming to closure. In addition, engineering work
- priorities do not seem to be determined by the needs of the plant, and errors j made during the original plant design and during recent vendor engineered I design modifications continue to challenge plant operations. Although 43 configuration baseline documents (CBDs) have been issued, use and training on the CBDs within engineering was not always effective. However, the quality of recently performed design engineering work appeared to be good, as did the general engineering programs and procedures.
3.1 Safetv Focus and Manaaement Involvement Safety focus within engineering was not always apparent, as indicated by an
" Engineering Critical Issues List" which does not match the plant's critical issues list and was not prioritized by safety significance. For example, none pf the items currently being tracked by the plant as operator workarounds made the critical issues list. The number one priority on the list was reducing i
the engineering discrepancy (DEF) backlog, mainly due to the large number of j open DEFs. S.dditionally, there was evidence that design engineering is i oftentimes not involved in early stages of problem identification and resolution. Although system engineers were routinely seen following work in the plant, they are not part of the engineering organization and often have 13 l l
limited contact with design engineers except for highly visible problems, such as marsh grass intrusion in'the circulating water system. Senior nuclear engineering management has communicated its expectations well, but the communication of management expectations throughout the engineering organization was not focused. For example, the number one objective for nuclear engineering in 1994 was to improve the plant safety and reliability by accurately interpreting, maintaining, and modifying plant design and licensing bases, but this objective was not mentioned within design engineering. Once again, reducing the DEF backlog was a highly placed objective for both departments. The engineering staff appears to be stable with reliance on contractors decreasing. For example, the current 70-percent rate of contracted engineering is expected to decrease to 62 percent by 1996. Internal engineering evaluations used by the plant for operability determinations were found to be acceptable. f The team determined that normal inspection is warranted in this area. The team recommends that the inspection effort focus on evaluating design engineering work priorities and the interaction between system engineering and design engineering.
?.2 Problem Identification and Resolution Engineering has not demonstrated the ability to identify and resolve problems at an early stage. Several significant issues have become more troublesome to plant operation, and engineering has not provided effective solutions.
Although progress has recently been made on some issues, this progress was oftentimes stimulated by plant events. Additionally, many of the proposed solutions have yet to be proven. Root-cause analyses in scoe cases were off i i target. Weaknesses in the licensee's resolution of longstanding problems are identified below: Circulatina water (CW) system - Problems with the CW system have been going on since 1991. To date, 6 of 10 projects scheduled for the CW < system have been completed. In the next outage on Unit 2, the trash rakes are scheduled to be replaced with rakes better designed to clean the trash racks; the speed of the traveling screens will be doubled, doubling the area that they can protect against grass intrusion; and electrical upgrades to the switchyard and CW substations will be completed. The effectiveness of these modifications is unproven. In addition to the modifications, Sales also completed two studies relative to CW, " Salem Detritus Characterization," dated July 29, 1994, and " Predictive Modeling of Debris Loads at Salen Generating Station " dated August 5, 1994. These studies will enable the station to predict when marsh grass accumulation will be at its highest. These studies appear to be good; however, they appear to be a direct result of the April 1994 grass intrusion event. 14
l 1 1* i . Analon rod nosition indicator (APRI) system - Problems with the APRI ] system stil' exist. Problems with APRI drift have been the subject of j numerous license event reports (LERs) and engineering has been pursuing a direct replacement for the existing system with the nuclear steam
, supply system (NSSS) supplier.
i e Boric acid tank JBAST1 - Longstanding ' level indication problems with the
- BAST eere recentLy solved when it was discovered that filling an empty j cold tank with concentrated boron was causing plugging of the tank j bubbler tube. Since the tank was empty, the heaters were not on and the s 12-percent boron solution crystallized and plugged the bubbler tube.
j Engineering had previously issued a modification to change the boron i concentration to 4 percent, but the boron concentration was not the true j root cause of this problem. 1 l
. Reactor coolant system - ~ Excessive cooldown transients remain a problem i pending implementation of E0P changes. The transients were originally thought to be a problem with leakage on the secondary side and two DCPs to correct leakage on the secondary side by using a block valve and time delays were implemented. These modifications quantified the leakage as minor but did not solve the problem.
- During troubleshooting on unit startup and through use of the computer i program "RETRAN", developed by the nuclear fuels department to model the i Sales plants, engineering has developed the theory that running j auxiliary feedwater (AFW) back sooner after a plant trip would greatly l reduce the cooldown transient. This solution has not been proven to j date; however, recent runs of the RETRAN program show excellent results.
3 The plant is currently pursuing a change to the E0Ps relative to AFW j operation after a plant trip. ! Engineering exhibited good performance in its prioritization of the DEF ! backlog using probabilistic risk assessment (PRA) techniques. Engineering was l responsive to items identified via the operating experience feedback program, and there was no backlog of operational experience items. j The team determined that increased inspection effort should be focused in this i area. The team recommends.that the inspection effort focus on ensuring the i four issues discussed above have been adequately resolved and on the timely identification and resolution of new issues. ! 3.3 Understandina of Desian l The'1arge number of events, licensee event reports (LERs), and recurring i problems attributed to a lack of the understanding of the plant design does i not appear to be the result of any single generic engineering weakness. ! Rather, the problems seem to have been caused by a combination of original plant design deficiencies, dasign deficiencies made during plant modifications, and an occasional lack of understanding of the original design j specifics. Following are examples of these problems: 1 15
The 1992 augmented inspection team (AIT) for the loss of the control room annunciators determined that design deficiencies made by a vendor during design and installation of this modification in 1992 allowed an operator to lock up the annunciator system from a remote terminal. The design of the system was inadequate in not addressing all failure modes or the effects of the software. In addition, the licensee did not fully , understand the system design because they apparently had not been ' adequately involved in the design af the system. In May of 1993 an unplanned rod motion event occurred. Contrary to the I design basis in the final safety analysis report, a single failure of i one slave cycler decoder card of one rod cluster control assembly (RCCA) in conjunction with a rod motion command signal caused an unplanned outward motion of a rod. The potential for this problem had existed since the plant was originally designed and built.
- An LER stated that, during the original design and construction, l
insufficient margin had been specified between the overvoltage protection setpoint and normal electrohydraulic control (EHC) power l supply voltage, resulting in the EHC DC control power failure and I turbine / reactor trip on February 10, 1994. The value used, 17.3 volts, ! was less than the value specified by the power supply manufacturer of 115 percent of power supply voltage plus 1 volt (>18 volts). During service water piping upgrade work on the Unit 2 emergency diesel generators (EDGs) in 1993, the licensee discovered that the setpoint for i the differential pressure coolers which modulate service water flow to the EDG jacket water coolers and lube oil coolers was incorrect. The setpoint had mistakenly been believed to be the manufacturer's value for i both coolers in series; however, the manufacturer had specified the value for each cooler, not the total pressure drop across both coolers i in series. This error caused an approximate 16-percent reduction in the 700-gallon-per-minute design flow rate and resulted in the EDGs being operable only if service water temperatures remained below 60 'F. The electrical distribution system functional inspection (EDSFI) conducted by the NRC in 1993 found that the 30,000-ga11on diesel fuel storage tank could not supply one diesel with enough fuel to run it for 7 days at full load. The EDSFI conducted by the NRC in 1993 found that the Unit 2 EDG combustion air exhaust pipe and intake louvers were unprotected against tornado-generated missiles and unable to withstand the effects of these missiles. Sales currently has 43 configuration baseline documents (CBDs), and these documents are referenced as a possible design input in the DCP process. The CBDs were found to be of good quality and readily retrievable. CBD training is provided to design engineers but the training does not include recent events in which the plant's design was a factor. 16
i During the assessment, the team reviewed an engineering collegial self-J assessment of the Configuration Baseline Document Project No. SA-94-0002P. This assessment found that the CBDs were used by both design engineering and
- contractors, but not as much as suggested by the design engineering procedures, and that technical department personnel, in general, did not find the CBDs useful for their work. The assessment also recommended that engineers reviewing the CBDs should be held accountable for the quality and
- timeliness of their reviews and that this goal could be accomplished either by j stronger emphasis by management or by additional training.
] The team detemined that normal inspection is warranted in this area. The team 4 recommends that the inspection effort focus on the licensee's oversight of and i involvement in modifications designed or installed by vendors and on the use of, and training on, the CBDs. 3.4 Quality of Enoineerina Work i i During the assessment, the team reviewed portions of recently completed mechanical, electrical, and instrumentation and control design change packages (DCPs) and one in-process DCP. The DCPs chosen involved recurring and longstanding corrective action. problems. The following packages were reviewed: l
- IEC-3254, " Boric Acid Concentration Reduction Modification"
- ISC-2269, " Sales Electrical Upgrade Project"
- 2EC-3286, " Diesel Generator Combustion Air"
- IEC-3170, " Replace Containment Isolation Valves"
- IEC-3270, " Overhead Annunciators" The quality of the modification packages and the 10 CFR 50.59 safety reviews was good. Work instructions for installation were generally good, and the in-t process testing instructions for the annunciator upgrade modification were excellent. Drawing changes for the sample of modifications were verified to be accurate using the data management subsystem computer system, which maintains the most current drawings and is user friendly.
The design engineers and system engineers communicated well about the circulating water and analog rod position indication systems; however, except i for these highly visible systems, good communication did not appear to be the ! norm. During a plant walkdown, the team observed contractor personnel attempting to route cables into an energized control panel. The contractors were removing the potting compound on the bottom of pa.iels nos. IRC-11. -13, and -14 during the implementation of DCP IEC-3298, " Primary Water Oxygen Reduction Modification." The work description in the DCP did not adequately reflect the job, and the work details had not been communicated to. the Unit I work control center nor to the senior operations shift supervisor, creating the potential for a reactor trip and personnel safety hazard. 17
i l
- )
s There have been instances in the past of equipment being replaced without proper safety reviews or work orders. Training for new engineering personnel ' and retraining for existing personnel was acceptable, the one exception being : the weak CBD training previously noted. j l 1 The team determined that normal inspection effort is warranted in this area. I ! The team recommends that the inspection effort be focused on engineering's I control of work activities and ccumunication of DCP work details to the plant ' i staff. 3.5 Procra== and Procedures The team reviewed Salem's design engineering program procedures as outlined by NC.NA-AP.ZZ-0008(Q), " Control of Design and Configuration Change, Tests and Experiments." The procedures appeared to be comprehensive and complete The j. quality was judged to be good. , The team also reviewed the procedures for scoping, evaluating, and
- prioritizing projects. The procedures for project scope proposals, project evaluation packages, and the nuclear department resource allocation process (NDRAP) were acceptable. Prioritization of engineering projects using NDRAP 3 was good, and the more important projects appeared to receive the correct
- priorities. The team verified that the performance indicator relative to the
, NDRAP process (60 percent or greater receiving high priority) was accurate. 2 In addition, the team noted that NDRAP will be the subject of an upcoming l engineering collegial self-assessment. The licensee is just beginniag to use PRA in the design process. The licensee plans on updating the PRA every other refueling outage. The current plan is
- to review all new DCPs and project requests against the PRA to determine the 4
effect on core damage probability. If, after review, an increase in core , damage frequency is found, the DCP sponsor will be notified and requested to i consider another option. Results will be reported and used to update the PRA. j The inservice testing and inservice inspection programs appear to be 1 j functioning adequately. Procedures were found to be thorough and accurate. The team determined that reduced inspection effort is warranted in this area. 4.0 MAINTENANCE Significant weaknesses were identified in both maintenance programs and in their implementation. These weaknesses included an overreliance on generic troubleshooting procedures, ineffective use of the procedure feedback process, inadequate post-maintenance testing training, the inexperience of backshift personnel, and procedural adequacy and adherence concerns. The team also expressed concern regarding the control and oversight of the numarous groups and organizations that perform maintenance and modification work on site. The maintenance organization did a good job at prioritizing work, disseminating operating experience feedback information, identifying equipment problems, and general plant housekeeping. 18
l l The team observed both emergent and ongoing maintenance activities, l interviewed maintenance personnel, conducted several plant tours, attended i selected meetings, and reviewed selected statistical data to determine the effectiveness of the Salem maintenance activities. The team observed the j following maintenance activities: !
- Replacement of the mechanical seal on the no.13 condensate pump in
- accordance with Work Order (WO) 940820047, Activity 01, and Procedure 4
SC.M)-PM.CN-0005(Q), Revision 2 " Condensate Pump Replacement, j Mechanical Seal Inspection / Replacement." Preventive maintenance (PM) on circuit breaker 2A164 for the #21 i switchgear room supply fan motor circuit breaker in accordance with ! WO 941014001, Activity 01, and Procedures SC.MD-ST.230-0003(Q), Revision i 4, "230 and 460 volt ITE K Series Breaker PM," and SC.MD-ST.230-0001(Q), ! Revision 2, "230 and 460 volt ITE K Series Breaker Overload Test."
- Replacement of the motor on the no. 21 turbine auxiliary cooling pump in j accordance with WO 940822167, Activity 04.
i l
- Troubleshooting the failure on the EDG annunciator panel in accordance j with WO 940819109, Activity 01, and Procedure SC.IC-GP.ZZ-0006(Q), 1
! Revision 7, " Controls Equipment - Tr M 1eshooting." l
- Troubleshooting the rod control system rod stepping anomaly in accordance with WO 940811197, Activity 01, and Procedure SC.IC-GP.ZZ- )
0006(Q).
- Troubleshooting and replacement of the governor on EDG 1A in accordance with WO 940816066, Activity 07; WO 940819136, Activity 01; and W1 940819111, Activity 01, and Procedures SC.IC-GP.ZZ-0006(Q),
Revision 7, and SC.MO-CM.DG-0006, Revision 1, " Diesel Generator Speed / Load Control System Alignment."
- Troubleshooting and repair of an inoperable annunciator on the 2C1 125 VDC battery charger in accordance with WO 940822178, Activity 01, and Procedures SC.IC-GP.ZZ-0006(Q), Revision 7, and SC.MD-ST.125-0001(Q), Revision 7, " Preventative Maintenance and 18 Month Surveillance of 125 Volt Battery Chargers."
4.1 Safety Focus /Manaaement Involvement It appears that management has a proper safety focus in prioritizing maintenance activities. The team attended a plan-of-the-day (P00) meeting and a work planning meeting to assess the licensee's methods of scheduling and prioritizing maintenance activities. From these meetings and from a review of the daily and weekly planning activities, the team concluded that production needs were not taking priority over safety. The team noted that management has made a good effort to reduce both the corrective maintenance backlog and the number of overdue PM activities. However, the licensee's efforts to identify problems in the plant have greatly 19
increased the amount of emergent work. This increase has lengthened the time it takes to return equipment to service. The team noted that the licensee was taking positive actions (e.g., through the use of the work planning meetings) to ensure that this emergent work did not adversely impact scheduled work. The licensee considered system availability in planning maintenance activities and is currently developing a method of using PRA in scheduling and planning maintenance activities. The team observed the pre-job briefing for testing the governor on the 1A EDG after its replacement. The team considered this briefing to be comprehensive, , however, it was noted that mechanical maintenance personnel were not involved I in this briefing. While they were infomed of the briefing results later by their supervisors, their absence from the briefing reduced the effectiveness of the briefing. l l Supervisory personnel were observed monitoring work activities; however, the ' oversight was not always effective, as evidenced by an incorrect procedure in the field during the mechanical seal replacement on the no. 13 condensate In reviewing this work package, supervisors failed to notice the pump. ; incorrect procedure. Management was involved in decision making, as evidenced ' by maintenance personnel conferring with their supervisors when problems were identified. 1 Maintenance department staffing is relatively stable, with an increase in l staffing planned due to unitization of the plant organization. The team noted that maintenance personnel, supervisory maintenance personnel, and maintenance ; planners assigned to the back shifts were generally the least experienced 1 personnel. The team concluded that, because the personnel and technical support available on these back shifts is limited, the staffing of the back shift with the least experienced personnel may be inappropriate. Coordination between the maintenance department and other departments was effective, especially between the maintenance department and the system engineers. , During plant tours, the team observed several temporary modifications (T-Mods) ! installed in the field. The team verified that these T-Mods were current and j that the licensee was tracking the modifications to ensure that they were ! intact and would be properly dispositioned. The team noted that the T-Mods l were increasing but concluded that this increase was not excessive and continued to be manageable. The team determined that normal NRC inspection effort in this area is
. warranted. The team recossends that the inspection effort focus on licensee planning activities and on management oversight of maintenance activities, including the back shifts to assure that field supervision is effective and that activities are being conducted by qualified personnel.
4.2 Problem Identification / Problem Resolution The licensee uses a process called the equipment malfunction identification , system (EMIS) to identify equipment problems. The licensee recently trained l its personnel to be particularly observant of such problems and to identify- ; them through the EMIS. As a result of this activity, the team noted a large ! 20 L
number of EMIS tags throughout the plant. The majority of these tags were hung within the last 3 months. Although the team considered the EMIS to be an effective way of identifying equipment problems, the team noticed some degraded equipment without EMIS tags. In one instance, an EMIS tag was hung on the equipment but ditt not get entered into the maintenance tracking system. Another process used by maintenance personnel to identify problems is the feedback foms that are a part of the WO planning sheets. While the purpose of this feedback process is to identify problems that occur during a maintenance activity, the team found instances in which this process was not being implemented. During interviews with field maintenance personnel, the team discovered that they have a low regard for these forms and, as a result, usually do not complete them. The team also found that, when these foms were completed, the information did not always get back into the planning system to ensure that errors were corrected. In some instances, the initiator of the form did not get timely feedback as to resolution of the problem. The maintenance department assesses its perfomance through supervision and
- use of the planning feedback process. The team considered the aggressiveness j of the assessment to be lacking, especially considering the problems with j implementation of the planning feedback process.
,' With regard to problem resolution, the licensee's performance indicators showed that the Sales station has a considerably higher recurrent equipment , failure rate than that of similar plants. The team considered the continuing recurrent equipment failures to be indicative of the licensee's inability to resolve longstanding equipment and system deficiencies. Examples of these longstanding deficiencies are the problems with the radiation monitoring system, the rod control system, the analog rod position indication system, and the main feedwater controllers. The team noted that the licensee has an excellent system to address external organization findings through the operational experience feedback (OEF) program. An OEF meeting is conducted weekly to identify the issues and assign responsibility. The team attended one of these meetings to observe implementation of the program. The team also reviewed various OEF findings and verified that these findings were tracked and properly closed. The team determined that normal NRC inspection effort in this area is warranted. The team recommends that the inspection effort focus on the licensee's control of emergent work activities, implementation of the maintenance planning feedback process, and resolution of longstanding equipment problems. 4.3 Material Condition Plant management realized in 1990 that the plant had material condition problems and as a result developed a Salem Material Condition Study Document. After developing this document, the licensee established the Salem Material Condition Revitalization Project. The goal of this project was to resolve the 21
discrepancies identified in the study document. The team noted that this project is scheduled to be completed by approximately June 1995. During plant tours, the team noted that the plant material condition appears to be good; however, the team did find some evidence of degraded conditions. A tour of the service water intake structure revealed holes in the traveling screen fiberglass covers, corrosion on large bore piping, and some areas of poor housekeeping. The residual heat removal pump rooms were entirely roped off because previous valve and piping leaks had contaminated insulation. The team also noted that four of eight atmospheric relief valves were leaking by their seat and that balance-of-plant equipment had some minor leaks. The continuing recurrent equipment problems have also contributed to a decline in the material condition of the plant. The team noted that some of these failures have resulted in plant safety system challenges and plant transients. The licensee has reduced the number of control room annunciators out of service. The team examined the status of out-of-service annunciators and found that the licensee's attempts at keeping this number low have been effective. According to the NPRDS database, the Sales station has more recurrent equipment failures than the average for similar plants. However, it appears that the total equipment failure rate at the Sales station is below the average for similar peer plants in the same NPRDS data base. Plant systems and components in which degraded material conditions persist include the radiation-monitoring system and the main feedwater controllers. The team noted that these issues are being addressed either by special projects or as a part of the revitalization project. The team determined that normal NRC inspection effort in this area is warranted. The team recommends that the inspection effort focus on the completion of the revitalization project and of other ongoing plant upgrade projects such as the service water system upgrade. 4.4 Ouality of Maintenance Work The team noted that the licensee's practice of developing multiple activities for each WO was cumbersome. For example, a single WO to perform a specific job might have an activity assigned to mechanical maintenance, another to controls maintenance, and another to post-maintenance testing and ratesting. Each of these activities is distinct, and field personnel usually do not know how one activity affects or is related to another. However, the end of the work process was appropriately coordinated. The licensee has also had a history of problems associated with troubleshooting activities. Although these problems appear to have decreasej slightly, they continue to axist. The licensee's practice of using multiple copies of the troubleshoot'.ng procedure to perform a single troubleshooting activity hampered maintenance personnel in following the job progress. The licensee also appears to rely excessively on the troubleshooting procedure to perform repetitive maintenance tasks, in lieu of developing procedures to 22
i
~
} accomplish these tasks (e.g., the replacement of battery charger components ! that have a limited life). j While observing maintenance activities, the team noted instances of personnel j errors, a failure to follow procedures, and excessive reliance upon " skill of i tha trade." The team noted that the control of measuring and testing ^ equipment was adequate. The team also noted that interdepartmental communication was good; howsver, there was some evidence that supervisors did j not comunicate effectively with workers in the field. The Sales station has i had a history of personnel errors, and there are indications that the error i rate is not decreasing. The following examples are indicative of the above l concerns:
- The licensee uses turnover sheets to ensure that oncoming shifts are aware of the status of the work on the job they will be doing. Although in general the use of these turnover sheets appeared to be effectiva, the team observed one instance, associated with the replacement of a condensate pump seal in accordance with WO 940820047, in which the turnover sheet gave ambiguous instructions as to which one of the three mechanical seals left at the work site was to be installed. The team discussed this observation with the field supervisor. The supervisor acknowledged the team's observation and agreed that the information given to the oncoming shift did not meet the licensee's expectations regarding turnover sheets and component control in the field.
- While observing the troubleshooting activity on the 2C1 battery charger associated with WO 940822178, the team observed that the procedure prerequisite check-off list had not been completed even though the maintenance technician was already performing subsequent sections of the troubleshooting procedure. When the team asked the technician why the prerequisites were not completed, the technician responded that the i prerequisites had been completed and that he had neglected to sign off '
the check-off list steps as required. The technician then stopped the troubleshooting activities and completed the check-off list. Not completing the prerequisite list before beginning the rest of the procedure was considered an example of a failure to follow the procedure. i This maintenance activity also involved the replacement of defective parts as necessary. As the maintenance technicians were preparing to install new parts, the team noted that one of these parts was designated as non-safety-related. The team questioned the technicians regarding this part. The technicians responded that the part matched the part number listed in the bill of materials (80M) and that they were trained to install a part as long as it matched the part number in the BOM. The team discussed this observation further with senior maintenance management personnel. As the result of this discussion, the licensee determined that the installed part had not been properly qualified.
- While observing the work activity involved with disassembling, cleaning, and adjusting a circuit breaker in accordance with WO 941014001, the 23
team noted that a maintenance technician on a back shift failed to notice that the breaker was slow in closing after the PM was performed. The day shift technician noticed the slow closing and discussed it with his supervision. As a result, it was decided that the breaker should again be disassembled. The team noted, however, that the steps that had to be reperformed were not checked off in the procedure when they were reperformed. In addition, the team noted that the controls technician had apparently not been trained on the function of the breaker pickup point and how that relates to the design function of the breaker. ! l
- During maintenance activities associated with the no. 13 condensate pump mechanical seal replacement performed in accordance with WO 940820047, l the team observed that maintenance procedure MN6, " Turbo-Star Mechanical i
' Seals and Chesterton 123 Mechanical Seal Installation / Rebuilding," was included in the work package. The team noted that the mechanical seal being installed during this activity was a Chesterton 222 and discussed : i this observation with maintenance personnel to determine the reason for i using procedure NN6. As the result of this discussion, the licensee determined that procedure MN6 was not the correct procedure for this , job. The maintenance planner, supervisor, and technician did not recognize that the MN6 procedure was incorrect for the seal that was to ! be installed. The team later determined that a senior licensee manager had previously noticed the inclusion of the incorrect procedure, but the manager's j observation apparently was not properly communicated within the ' maintenance organization, since the procedure was still part of the work package. During a walkdown to verify that the equipment clearance program was properly implemented, the tcan found a clearance (blocking) tag that was no longer attached to the component requiring blocking. The component, fire protection valve FP-141 (hydrant 092-117), was located inside a curb box. The blocking tag had been installed on the curb box because the valve was located approximately 5 feet below ground and was normally operated via a removable valve reach rod. Site services maintenance personnel excavated around the valve and removed the curb box to allow _ access to the valve. These personnel did not, however, remove the blocking tag from the curb box and replace it on valve FD-141. These personnel did not realize that removal of the curb box with a blocking tag attached was inappropriate. The licensee issued IR 94-236 as the result of this event. The team determined that increased NRC inspection effort in this area is warranted. The team recommends that the inspection effort focus on the implementation of maintenance activities, including the maintenance planning i l grocess, with an emphasis on troubleshooting activities and procedural adherence. 4.5 Proarans And Procedures The licensee completed a procedures upgrade plan (PUP) in 1993. The PUP 24
involved both operations and maintenance procedures. Although the PUP has : been completed, the team noted that procedure adequacy continues to be a l problem, apparently because a number of procedures have not been upgraded and because the PUP was not always effective. For example, although an excellent
- troubleshooting procedure has been developed and implemented in the controls area, a similar procedure developed for the mechanical maintenance area has not been implemented. As discussed in Section 4.4 of this report, it appears !
that the licensee relies too much on the troubleshooting procedure to resolve l l maintenance problems, especially recurrent ones. The licensee has made this ! l procedure a type of catch-all procedure. The team found no evidence that the licensee has been developing procedures to address recurring maintenance . problems. The following activities observed by the team illustrate procedure l adequacy and upgrade problems: l
- In reviewing the work package associated with WO 940822178 that involved troubleshooting .and replacement of components in the 2C1 battery l
charger, the team noted that the troubleshooting procedure was being used to replace and initially test the charger. The team noted that the troubleshooting procedure referenced engineering instructions that were needed to provide the initial setup of the charger after the component replacement and before the charger load test (which was to be conducted in accordance with the PM procedure). The replacement of these components was not unique, and from discussions with licensee personnel, the team determined that this type of replacement and testing had been performed in the past. Even though similar components had failed in the past and required replacement, the licensee had not yet developed a procedure for this type of replacement and initial testing. After i reviewinn this issue further, the team found that procedure revision requests to incorporate these engineering instructions into approved procedures were issued twice, on July 15, 1992, and on May 6, 1994. The procedures maintenance group, the group that was responsible for processing such changes, did not process these changes because of an excessive procedure change backlog.
- After the installation of the 1A diesel generator mechanical and l electrical governor, the team observed the performance of the diesel '
generator speed / load control system alignment procedure. While performing the procedure, the licensee had to issue an on-the-spot change (OTSC) to the procedure because the procedure steps were out of order, preventing the test from being properly perfomed. The OTSC was ! needed to allow the electronic governor to be adjusted so that it did not interfere wMh the adjustment of the mechanical governor. The team discussed this psblam with the licensee and detemined that, although 4 this procedure had M en used in the past, the procedure was apparently not cotracted to allow proper adjustment of the mechanical governor. ,
- The licensee categorizes its maintenance procedures as Category 1 or 2.
Category 1 procedures must be followed step-by-step at the work site, while category 2 procedures are required to be at the job site but not specifically open and followed step-by-step. While observing the
- performance of a PM on a non-safety-related breaker in accordance with WO 941014001, the team observed that the procedure in use was a l
25
l Category 2 procedure. The team noted that this same procedure was used to perform Pas on safety-related breakers. In addition, the team noted that there were no provisions in the procedure for quality checks for significant error-prone steps such as the breaker mechanism reassembly. The team further noted that the procedure contained no acceptance criterion for setting the long-time pickup point on the breaker. The team considered the adequacy of this procedure to be questionable because of the use of a Category 2 procedure for maintenance on safety-related equipment, the lack of appropriate acceptance criteria, and the lack of quality check points. The team noted that the performance of maintenance activities wa:; controlled a by the maintenance planning process. In this process, maintenance planners develop the Wo. The WO specified the work to be performed and included the procedures to be used, the 80M, the post-maintenance test (PMT) requirements, and the operability retest requirements. Although the planning program appeared to be developing well, the implementation of this program has been ineffective. Specifically, the team identified weaknesses in the use of the feedback process and in the specification of post-maintenance testing requirements. The team attributed these weaknesses to the inadequacy of the controlling procedures for the planning process, the inexperience of the i ! planning staff, and poor training of planners in PMT and ratesting requirements. In several instances, the team found that maintenance planners failed to specify appropriate PMT requirements, but instead gave generic instructions such as " Operations Perform Appropriate Retest." Interviews with maintenance planners and a review of the applicable PMT procadures also indicated uncertainty regarding maintenance planners' responsibility in specifying PMT requirements. Although plant management stated the intention to improve procedure adequacy and adherence, this intention has not been effectively communicated to the working staff in the field. As a result, station management has not been effective in improving procedure adherence and in implementing the feedback process that is needed to correct deficient procedures. The team determined that increased NRC inspection in this area is warranted. The team recommends that the inspection effort focus on procedure adequacy, the licensee's efforts to improve procedure adherence, and the use and adequacy of PMTs and ratests. i 5.0 PLANT SUPPORT ! The initial document review phase of this assessment indicated that the licensee has implemented strong plant support programs. The strong performance was evidenced by good self assessment, lack of recurring problems, and good root cause assessment and timely correction of observed problems.
.Because of the absencc of negative findings during the initial assessment, the team's onsite assessment of the plant support area was limited to certain ! specific activities. The team's observations of ongoing plant support i activities did not identify any significant problems which reflected ; negatively on the quality of these activities.
4 26
i l l 5.1 Safety Focus and Manaaement Involvement The team noted that management safety focus was appropriate and that management and supervisors were involved in plant support activities. Their , involvement was particularly evident for physical security activities during periods of increased personnel access processing and vehicle inspections. The team also observed that cosmiunications within the various plant support organizations were adequate. The team detemined that reduced NRC inspection effort is warranted in this area. 5.2 Problem Identification and Resolution The emergency preparedness, fire protection, and health physics organizations appear to have implemented proactive and effective problem identification and resolution programs, as shown by r. lack of recurring problems, and good root cause assessment of observed problems. The security organization has also demonstrated good problem identification through a comprehensive audit program. However, in the past, problem resolution of audit results have not-been aggressively pursued. The team reviewed eight security audits that were conducted between May 12, 1993 (Audit QA 93-033), and August 5, 1994 (Audit SQA 94-0074). Of these eight audits, three had discrepancies that required corrective actions. The team's reviews noted that these discrepancies were properly addressed and resolved in a timely manner. In addition, the licensee has noted that detection and assessment aids have been deteriorating with age without timely resolution. The team noted that the deterioration was limited to certain equipment. The licensee is addressing this problem through a phased-in replacement of new equipment. The team observed that this replacement was on schedule. To verify the effectiveness of the existing assessment aids, the team observed activities at the secondary assessment station (SAS). All equipment provided appropriate surveillance capability. 1 The team determined that reduced NRC inspection effort is warranted in this area. ! 5.3 Ouality of. I Emergency Preparedness ! The initial document review indicated that the licensee had demonstrated a high level of competence during emergency preparedness training drills. Emergency response facilities (ERF) and equipment were effectively maintained, and ERF support and command and control were appropriately implemented. Both the document review and site observations indicated that the emergency preparedness program is of high cuality and adequately maintained. The licensee demonstrated a high level of competence during the team's walkdown of the emergency facilities. The ERFs and associated equipment were effectively maintained, inventoried, and staged. However, two areas supporting the emergency operations facility exhibited poor housekeeping. Additionally, several copies of the E0P flowcharts in the technical support center were outdated. The emergency preparedness (EP) staff were observed to be very 27
responsive in correcting identified problems and were knowledgeable of all aspects of the EP process. The team determined that reduced NRC inspection effort is warranted in this area. Fire Protection l Response to Appendix R issues has been acceptable. Performance of t compensatory measures was good. Drill and fire protection scenario performance by the fire department was excellent. Training was very good. The team observed several fire doors held open by ventilation and a fire door propped open by a trash can; however, the team did not observe any other problems which reflected negatively on the quality of fire protection I activities. The licensee is currently working on solutions to the ventilation system problems. l The team determined that reduced NRC inspection effort is warranted in this l area. Security The team's observations of ongoing security activities indicate that the level of security was appropriate. Site security personnel performed well during personnel access and vehicle search activities. The team noted that, during high traffic periods, additional security personnel and supervision were stationed to assist with personnel access. Supervisors was also observed to l be present during periods of increased vehicle search activity. l The team discussed with licensee personnel the resolution of the recent security events involving personnel access and vehicle searches. The team identified that the licensee did not consider these events to be isolated. The licensee is treating these events as a generic concern and showed evidence that their security contractor will be taking positive action in the form of additional audits and training. The team considered the actions being taken by the licensee to be responsive and conservative. The team determined that reduced NRC inspection effort is warranted in this area. Health Physics The licensee has consistently performed health physics activities in a manner that demonstrates a high level of management expectation. These efforts are characterized by a good program for limiting radiation dose, good contamination controls, and good health physics training and qualification. l The team's observations of ongoing site herith physics activities did not identify any problems which reflected negatively on the quality of health j physics W.ivities. i j The team determined that reduced NRC inspection effort is warranted in this l area. i ! 28 I
i l l i l 5.4 Procranc and Procedures The licensee has consistently implemented strong plant support programs characterized by good procedures. Few problems han been identified in the plant support areas, and the more significant problems have been identified : and corrected by the licensee. The team's observations of' ongoing plant I support activities did not identify programs or procedures whose effectiveness l was questionable. l l The team determined that reduced NRC inspection effort is warranted in this area. 6.0 EXIT MEETING On August 25, 1994, upon conclusion of the assessment, the team held a preliminary exit meeting with the licensee. At a final exit meeting on September 9, 1994, the team presented the final assessment results. The final exit meeting was open to the public. The following is a list of the principal attendees: HE H&ME P05ITION J. White Section Chief, Project Branch No. 2, DRP, Region I I C. Marschall Salem Senior Resident Inspector J. Jacobson Inspection Team Leader, Special Inspection Branch, NRR ! J. Wiggins Deputy Director, Division of Reactor Safety, Region I , E. Wenzinger Chief, Project Branch No. 2 DRP, Region I R. Gallo Chief, Special Inspection Branch, NRR l f.1GE S. Miltenberger Vice President & Chief Nuclear Officer S. LaBruna Vice President, Nuclear Engineering J. Hagan Vice President, Nuclear Operation & GM Salem Operations F. Thomson Manger, Licensing and Regulation M. Morroni Maintenance Manager, Controls l A. Orticelle Maintenance Manager, Mechanical P. Ott Operating Engineer
- T. Ce11mer Rad. Pro / Chemistry Manager R. Griffith Manager, Salen QA C. Lambert Manager, Nuclear Engineering Design
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The Honorable Joseph R. Biden United States Senator 844 King Street Wilmington, DE 19801
Dear Senator Biden:
I am responding to issues you raised in your letter of September 26, 1994, to i Mr. Dennis K. Rathbun, in which you requested the Nuclear Regulatory ' Commission (NRC) to assist you in a matter involving Amer Industrial Technologies, Inc., of Wilmington, Delaware. In your letter, you stated that i Amer has a problem understanding the intent and guidance in NRC Generic Letter (GL) 89-09, "American Society of Mechanical Engineers (ASME) Section III Component Replacements." You also stated that Amer officials believe GL 89-09 should be withdrawn because foreign vendors do not have to meet the same requirements as those imposed on domestic vendors and, therefore, have a competitive advantage. The NRC licenses the construction and operation of domestic nuclear power plants under Part 50 of Title 10 of the Code of Federal Reaulations (10 CFR Part 50). Subsection 50.55a to 10 CFR Part 50 (10 CFR :6.55a) requires nuclear powv plants to be designed and constructed to Section III of the ASME Boiler and Pressure Vessel Code. The ASME Code Section III requires that original and replacement components in nuclear power plants be procured from ; vendors who maintain an ASME-issued certificate of authorization and N-symbol stamp. These certificates of authorization are intended to provide assurance that the components supplied by these companies are designed, inspected, and certified to ASME Code standards. This also ensures that these components have a consistent and traceable materials and qualification record commensurate with the high-quality standards required in the nuclear power industry. Prior to May 14, 1984, paragraph (a)(2) of 10 CFR 50.55a, permitted an exception to Section III of the Code: 650.55a(a)(2) provided that the Code N-symbol need not be applied when constructing Class A or Class 1 nuclear reactor components to comply with the ASME Code. This exception was initiated in 1971 to permit qualified foreign manufacturers to supply components to domestic nuclear plants because at that time, the ASME had no provisions for issuing Certificates of Authorization and the Code N-symbol stamps to firms outside of the United States and Canada. This Code requirement was waived by the NRC when the Code was first incorporated by reference in the regulation in 1971; however, the Commission always intended that items within the scope of the Code comply with all other Code provisions. As of September 11, 1972, the ASME instituted provisions for making Certificates of Authorization and symbol stamps available to foreign manufacturers, making the exemption to 10 CFR 50.55a unnecessary and permitting the regulation to be revised accordingly. As of May 14, 1984, any components or parts required by the procurement document to meet the requirements of ASME Section III, Code Class 1, 2 or 3 f j must meet all the requirements of Section III, including stamping. f
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The Honorable Joseph R. Biden 2 However, because of the decline in the construction of new nuclear power plants in this country, many vendors of nuclear-grade components have found it , unprofitable to maintain their certificate of authorization. Other companies have discontinued or sold a product line to another company that does not have a certificate of authorization. Consequently, some licensees may face undue hardship in obtaining replacement components that have all the qualifications required of certified N-stamped nuclear-grade components. Many licensees were forced to submit requests for relief from the provision of 10 CFR 50.55a due < to the decrease in the number of certified vendors of nuclear-grade components. The NRC must address these relief requests while continuing to provide an adequate level of safety. The NRC, in recognizing the potential difficulties utilities may encounter when obtaining certain replacement products, issued GL 89-09 on May 8, 1989. 4 GL 89-09 states that, in replacing nuclear-grade components, licensees must first seek out an equivalent ASME N-stamped replacement from a certified vendor, such as Amer. If a licensee determines that replacements are no longer available in full compliance with the stamping and documentation requirements of Section III, a replacement without a stamp can be substituted provided it is procured under the licensee's quelity assurance program that is in conformance with Appendix B to 10 CFR Part 50. Furthermore, non-stamped replacements must meet all applicable requirements of Section III of the ASME Code, including third-party inspection by an authorized nuclear inspector, except that the ASME Code N-symbol need not be applied. The guidance contained in GL 89-09 should only be used by licensees who have i found it impossible to replace certain nuclear-grade components from the original vendor or other qualified vendors who provide N-stamped components. l The NRC position in GL 89-09 does not distinguish between foreign and domestic ! vendors of nuclear-grade components. All vendors, foreign or domestic, of i such replacement components are subjected to the same quality assurance program requirements. Therefore, GL 89-09 does not provide any competitive advantage to foreign vendors seeking business opportunities in the United States by not requiring them to meet the same requirements as those imposed on domestic vendors. ' I trust this information addresses the concern of your constituent. Sincerely,
/
s ecutive Director for Operations
l l 6209Frotaa-. B ac%s saa us smar w, - c- ,co...... 1 9s - JC3EPH R OIDEol. J0- .302r!33-6385 eeuwm united Etates senate ! WASHINGTON, DC 20510-0802 l f September 26, 1994 Mr. Dennis K. Rathbun Director Office of Congressional Affairs Nuclear Regulatory Commission ) I Washington, D.C., 20555 f Inc., Re: Amer Industrial Technologies, l 100 South Madison Street Wilmington, Delaware, 19801
Dear Mr. Rathbun:
assistance on a matter I am writing to ask for yourcompany Amer Industrial involving the Delaware-based Technologies, Inc. . .is comrany has been serving commercial for the nuclear power plants in the United States and overseas last 18 years and has the Nuclear Certification to do so. fArom copythe American of the , Society of Metallurgy Engineering (ASME)to me is enclosed for your revi letter Amer sent letter the NRC issued Amer has a problem understanding acomponents f rom manuf acturers who allowing utilities to purchasenuclear quality programs which are do not have certification or Inspection audited regularly by ASME and thethis Authorized Nuclear regulatory guide should be Agency. Amer ofitficials believe gives foreign companies an opportunities to deleted because business without having to meet the same obtain American guidelines required by American companies, like Amer. information or assistance that might I am requesting any Inc., with their problem. I help Amer; Industrial Technologies Please send look forward to hearing f rom you in the near future. i tant your response to the attention of Todd Turner, my Stafffor Thank you Ass s at 844 King Street, Wilmington, Delaware, 19801. your attention to this inquiry. Sincerely, e h i E / $-h-- Joseph R. Biden, Jr. United ;tates Senator t
. lll$ r AMER INDUSTRIAL TECHNOLOGIES, INC.
1000 SOUTH MADISON STREET WILMINGTON, DE 19801 TELEPHONE: (302) 652-3900 FAX: (302) 662-6400 4 September 15, 1994 The Honorable Joseph R. Biden, Jr. U. S. Senator Wilmington, DE
Dear Joe:
As you know, we are always proud of you here in Delaware. In my travels throughout the country I always mention your name as one of the leading sena' ors in 'ur country. Your pioneer ideas and opinions for world peace, better living in the United States and the comfort of Delawareans is highly regarded. You stood tall, brave and sometimes alone in controversial and important issues. You spoke about Bosnia 1.ike no one else. You pushed the Biden Crime Bill (congratulations to you and us). We were, we are, and will stand always behind you on those issues. We also stand behind you in creating independent nuclear safety board separate from the NRC. We at Amer Industrial Technologies have been serving the commerical nuclear power plants here in the United States and overseas for the last 18 years, and we still have the Nuclear Certification from ASME to do so. We are not happy also that NRC issued Reg. Generic Letter 89-09
/ which allows the utilities to purchase components from manufacturers who do not have certification or nuclear quality N programs which are audited regularly by ASME and the Authorized Inspection Agency. This regulatory guide should be
/ Nucleardeleted. There are enough companies qualified to do the work q
here in the U.S.A. and foreigners like Korea and Brazil, Slovenia Holders and to the United States for Nuclear Certificate kgthey come find them. Until I see you again, stay well. Cordially,
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A. E. Amer, President 60: 9T IMd P6-9I-d3 Ie a
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/ Ncumber 10, 1994 l
The Honorable William V. Roth, Jr. l United States Senate l Washington, DC 20510 l
Dear Senator Roth:
I am responding to your memorandum of October 13, 1994, which forwarded a I letter fro (Trederick Harpster,*one of your constituents, regarding government oversight of Salem Nuclear Generating Station. I I can assure you and Mr. Harpste that the U.S. Nuclear Regulatory Commission (NRC) is closely monitoring plant operations at the Salem station. The NRC , has three resident inspectors located at Salem whose sole responsibility is to assess plant safety. This resident staff is supplemented, as required, by inspectors from the NRC's Region I office in King of Prussia, Pennsylvania, 1 and NRC Headquarters in Rockville, Maryland. Because of recent performance issues, the NRC has increased regulatory attention to Public Service Electric and Gas Company's (PSE&G) operation and maintenance of the Salem Station. The NRC has also taken enforcement action on several occasions to emphasize l the inportance that the NRC places on effective and safe operating practices, ' and proper adherence to regulatory requirements. Most recently, on October 5, 1994, the NRC issued a proposed civil penalty of $500,000 following an l April 7, 1994, event at Salem Unit 1. This event occurred when marsh grass caused clogging of the circulating water system resulting in an automatic reactor shutdown and two automatic actuations of the safety injection system. The proposed civil penalty was issued to emphasize the importance of aggressive management of the Salem station to ensure that (1) management ) expectations are established, effectively communicated, and followed by the I station staff, (2) problems are promptly identified and corrected, and (3) operations supervisors maintain appropriate command and control. This event was the fourth significant event at the Salem station since 1991. In response to the recent occurrences, one of which was cited by $ Harpster,< PSE&G has been acting to replace or repair equipment that contributed to, or was a factor in, station performance problems and to correct operating practices that need improvement. PSE&G has also reassigned or replaced supervisory and technical personnel in an effort to improve overall station performance. The NRC, with its increased regulatory attention to Salem, will continue to monitor the results of these efforts. l l 1 Mf+70984. :af
The Honorable William V. Roth, Jr. I assure you that the NRC staff will continue to closely monitor plant operations and will not hesitate to take any necessary regulatory actions. I trust this letter will satisfy your constituent's concerns. Sincerely,
/
FA mes M. lor xecutive Director for Operations 1 1 l l I d a (
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. Noven er 10, 1994 4 .
The Honorable William V. Roth, Jr. I assure you that the NRC staff will continue to closely monitor plant operations and will not hesitate to take any necessary regulatory actions. i }! I trust this letter will satisfy your constituent's concerns. Sincerely, Original signed by James M. Taylor 1 3-James M. Taylor Executive Director I for Operations a L s, ! ,L: .[l T DISTRIBUTION See attached list *Previously Concurred . OFFICE PDI 2/LA PDI-2/PM PDI-2/D TECH ED* DRPE/0* NAME M0'Brien* LOLshan* JStolz* MMejac* SVarga* DATE 11/02/94 11/02/94 11/02/94 10/25/94 10/24/94
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[ QNe 2 2 2 4-244 eANitiNo nousi c AN unsA,a ass Ains ilm.ttd States $cnatt ~~""~o*"-"" WASHINGTON. DC 20510 MEMORANDUM Date: October 13, 1994 To: Office of Congressional Affairs Nuclear Regulatory Commission Washington, D.C. 20555 From: William V. Roth, Jr. l United States Senate l 104 Hart Senate Office Building l Washington, DC 20510 1 Because of the desire of this office to be responsive to all inquiries and communications, your consideration of the attached is requested. Your findings and views will be appreciated. Sincerely, l William V. Roth, Jr. United States Senate A4##45% ano
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y k UNITED STATES , j j 2 NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. snana nani
% / July 7, 1995 The Honorable Frank R. Lautenberg United States Senate Washington, DC 20510-3002
Dear Senator Lautenberg:
I as responding to your letter dated May 5,1995, written on behalf of your constituent, Mr. William Pettit. As we understand Mr. Pettit's letter, dated April 12, 1995, he is concerned about: (1) the recent release of radioactive material from Public Service Electric and Gas Company's (PSE&G) Hope Creek station; (2) the potential public health and safety impact of a contaminated tractor-trailer that left the Hope Creek site following the radioactive release; (3) the timeliness of communication of the Hope Creek event to ) Cumberland County officials; and (4) the history of problems experienced by PSE&G relative to the Sales Nuclear Generating Station, Unit 1, for which he recommends that this facility be monitored. The NRC dispatched a special inspection team on April 6, 1995, to review the circumstances surrounding the release of radioactive material and determine the significance to public health and safety and impact on the environment. Our inspection report, NRC Inspection Report No. 50-354/95-05, is enclosed for your information and is available to the public. The inspection revealed several performance problems that contributed to the event, including (1) deficiencies in the design and modification of a radioactive waste processing component that was the source of the release, (2) the inability of the radiological gaseous effluent monitoring aquipment to detect the release due to the liquid form of the material, (3) the startup and operation of the equipment without sufficient safety evaluation sr procedures, and (4) insufficient management oversight and control of associated activities. Notwithstanding these performance deficiencies, we confirmed that this release was of very short duration and did not exceed NRC affluent release limits. The event did not adversely affect the public health and safety, including workers on-site, nor was the environment adversely impacted. However, the performance issues were significant enough to be the subject of an URC ( Enforcement Conference wit.h PSE&G (the licensee) on June 16, 1995. The meeting was open to public observation, and Mr. Pettit attended. Currr"tly, the NRC is considering enforcement action on several of these matters. The licensee's corrective actions associated with the above deficiencies were reviewed by the NRC and found to be appropriate. ! One vehicle, a tractor-trailer, was driven off-site on the morning of April 5, 1995, before PSE&G personnel realized that a release occurred. The vehicle l , was subsequently located on April 6, 1995, at the Air Products Corporation l terminal in Delaware City, Delaware. PSE&G radiation protection personnel f 4(63W36 3pp
l ' l The Honorable Frank R. Lautenberg responded and determined that low levels of contamination were deposited on portions of the trailer. The vehicle was subsequently decontaminated. The drivers and other personnel who handled the vehicle were not contaminated. Several pertinent facts should be noted concerning the type and level of contamination and the decontamination. The contamination adhered to the external surfaces of the truck and was removed with cloths wiped over the vehicle. No precipitation occurred during the time between radioactive release at the Hope Creek Generating Station and the time of truck decontamination. No release limits were exceeded. The level of contamination resulting from the release did not present a public health and safety hazard. Cumberland County officials, including other State and local officials, were not immediately notified of the release since the circumstances and level of contamination did not require emergency declaration or notification in accordance with PSE&G's emergency response plan, which is approved by the NRC. On April 6, 1995, PSE&G informed the appropriate State agencias in New Jersey and Delaware of the circumstances of this event, issued '. a press release, and filed a report of the event with the NRC in accordance with regulatory requirements. With regard to Mr. Pettit's statement that Salem Station performance must be monitored, the NRC maintains a resident inspection staff at all operating cosmarcial power facilities, including the Tales and Hope Creek Generating
' Stations. NRC resident inspection activities at Salem and Hope Creek are managed by the NRC Region I Office, located in King of Prussia, Pennsylvania, -
and are supported by region-based specialist inspectors as necessary. The purpose of the resident program is to provide an on-site hRC presence to monitor performance of NRC licensed activities by the conduct of formal inspections and assessments in order to verify that public health and safety is maintained and that the licensee operates the facility in accordance with regulatory requirements. The NRC has intensified the monitoring of the Sales Nuclear Generating Station due to performance problems, both NRC and licensee identified. On March 21, 1995, KRC senior managers met with the licensee's Board of Directors to communicate NRC's safety concerns regarding the performance of the Salem Station. The board members and company officers confinned their commitment to improve performance of the Salem Station. On May 16, 1995, the licensee voluntarily shut down Unit I to resolve concerns with switchgear room supply fans, initiated a comprehensive multi-discipline evaluation of outstanding maintenance issues, revised and refocused the engineering support organization, and initiated a high-level review of the problems which led to the Unit I shutdown. On June 7, 1995, the licensee commenced a shut-down of Sales Unit 2 after declaring two valves inoperable in the Residual Heat Removal system. During the shutdown process, Unit 2 tripped due to apparent problems experienced with electrical breakers associated with the 500 kV switchyard resulting in loss of power to some vital and non-vital buses. The unit was stabilized and shut down. Subsequently, the licensee ! committed to keep both units shut down until it completes comprehensive corrective actions to address the specific causes leading to the shutdown of
- both Sales units and initiates broader actions to address underlying weaknesses involving long-standing equipment reliability and operability issues.
l l - - - - _ _ . _ _ _ _ _ _ __ _ _ _ _ . _ _ _ _ _ _ ._ ._
< The Honorable Frank R. Lautenberg ' On June 9, 1995 the NRC issued the licensee a Confirmatory Action letter l acknowledging the licensee's commitment to maintain the Salem units in a shutdown condition pending completion of specific actions to be accomplished by the licensee. These commitments include a review of the circumstances leading to the Salem Unit 2 reactor trip, a special review of long-standing 4 equipment operability issues, a meeting with the NRC to gain agreement on scope and detail of the licensee's plan for an operational readiness review in support of startup of each Salem unit, and the execution of the operational ; readiness review. i NRC staff has been in contact with Mr. Pettit and provided him with a copy of I the Hope Creek Inspection Report referenced above. During the Hope Creek l Enforcement Conference on June 16, 1995, the staff met with him, explained the NRC enforcement process and provided assurance that the NRC would continue to actively monitor the Hope Creek and Salem facilities. We trust that this letter is responsive to your request. Please contact me if ' you have further questions or require additional information. Sincerely,
/
MV a s M. Ta r ecutive Director for Operations
Enclosure:
Letter to L. Eliason, PSE&G, from R. Cooper, NRC, Region I, dated May 30, 1995, transmitting Inspection Report F- o-354/95-05 5 i
i i k May 30, 1995 ) i l
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I j EA 95-087 I Mr. Leon R. Eliason a Chief Nuclear Officer and President d Nuclear Business Unit i Public Service Electric and Gas Company ; i P. O. Box 236 l ! Hancocks Bridge, NJ 08038 i
SUBJECT:
NRC INSPECTION NO. 50-354/95-05 i
Dear Mr. Eliason:
! } ! A special reactive safety inspection was conducted by Mr. R. L. Nimitz and . other NRC Region I personnel during the period April 6 - 21, D95, at the Hope j Creek Nuclear Generating Station, Hancocks Bridge, New Jersey. The inspection
; was conducted to review the circumstances surrounding, and licensee actions i and evaluations associated with an unplanned release of radioactive material l from the Hope Creek station's south plant vent (SPV). The release occurred i during the early morning hours of April 5,1995, and was not_ discovered by j your staff until the afternoon of April 5, 1995. The release contaminated
- portions of the site and was later determined to have originated from the 4
Decontamination Solution Evaporator (DSE). i i The findings of the inspection were discussed with you and members of your \ organization at the exit meeting held on April 21, 1995. Inspection findings were also periodically discussed during the inspection with Messrs. Trum and Hovey of your organization. The exit meeting was open to the public and
- members of the public, including representatives of the news media, were in i attendance.
i 4 Overall, the findings of the inspection indicate no release limits were exceeded and reasonable worst case analyses indicate the release of radioactive contamination from the DSE via the SPV had little radiclogical impact on the public and environment. Although about 25 gallons of steam and water, that contained about 85 millicuries of mixed radioactive corrosion products, was discharged from the SPV to the environment, the safe operation of the reactor was not affected and the release did not significantly impact on-site personnel. Your staff performed an excellent evaluation of the impact of the release on the environment. Based en the results of this inspection, four apparent violations were identified and are being considered for escalated enforcement action in accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy),10 CFR Part 2, Appendix C. The ' violations are summarized in the Executive Sunr:ary included in the enclosed inspection report. The number and characterization of apparent violations WE~E ,,y-- 4 f. I e .A. - K .. . ,.
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1 L. R. Eliason 2 described in the enclosed inspection report may change as a result of further NRC review. Accordingly, no Notice of Violation is presently being issued for these inspection findings. Of particular concern'was the delay in identifying that a release had occurred, thereby delaying actions to secure potential sources of the ~ contamination and mitigate potential onsite and offsite exposures. We note that the delay in identifying the release appeared to be due, in part, to
- weaknesses in $nter- and intra-departmental communications and integrated assessment of hvailable information. In addition, we are concerned about the adequacy of your engineering assessment of the modifications made to the DSE, and of your design change process which allowed an inadequately evaluated release pathwny (DSE effluent vant pipe) to be placed in service. Further, we are concerned about your equipment start-up and operations program which : : '
permitted equipment to be placed in service with an incomplete understanding of its operating design basis and with inadequate opeFating procedures. *le7.i our view, the aature of these deficiencies represents an apparent breakdown in control of licensed activities that indicate a need for improved attention toward licensed responsibilities. , An enforcement conference to discuss the apparent violations and NRC observations has been scheduled for 10:00 a.m. on June 16, 1995, in the NRC Region I office, King o'/ Prussia, Pennsylvania. The decision to hold an enforcement conference does not mean that the NRC has detemined that a violation has occurred or that enforcement action will be taken. The purposes of this conference are to discuss the apparent violations, their causes ana - i safety significance; to - vide you the opport"aity to point out any errors in 1 our inspection report; :. :o provide an oppc- ity for you to ~esent your proposed corrective act- , in adH tion, tr i an opportunit. 'or you
- provide any informati- :erninc sur pers les on 1) the se city of e viol'ations, 2) the aprl w .1on of
- factor the NRC consic 5 when determines the amount M a civil alty tha . be assessed in :ordan with Section VI.B.2 of the Enforce.. ment Policy, and 3) any other splicatt - .f the Enforcement Policy to this case, including the exercise of discretion in accordance with Section VII. You will be advised by separate correspondence ,
of the results of our deliberations on this matter. No response regarding these apparent violations is required at this time. In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of 4 this letter and its enclosure will be placed in the NRC Public Document Room. Your cooperation with us is appreciated. S rely, Or ial Signed By: i Ri =ard W. Cooper, II, Director . 2 Division of Reactor Projects Docket No. 50-354 C77: i..t.3 :.b CarY
I L. R. Eliason 3 i l
Enclosure:
NRC Inspection Report No. 50-354/95-05 l cc w/ encl: J. J. Hagan, Vice President-Operations S. LaBruna, Vice President - Engineering and Plant Betterment 1 C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co. l P. MacFarland Goelz, Manager, Joint Generation Department,
- Atlantic Electric Company R. Burricelli, General Manager - Information Systems & External Affairs j
l
- M. Reddemann, General Manager - Hope Creek Operations J. Benjamin, Director of Quality Assurance and Safety Review i
F. Thomson, Manager - Licensing and Regulation R. Kankus, Joint Owner Affairs A. C. Tapert, Program Administrator R. Fryling, Jr., Esquire M. J. Wetterhahn, Esquire Consumer Advocate, Office of Consumer Advocate l William Conklin, Public Safety Consultant, Lower Alloway'; Creek Township
- State of New Jersey State of Delaware
- State of Maryland i
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L. R. Eliason 4 Distribution w/ encl-Region I Decket Room (with concurrences) K. Gallagher, DRP D. Holody, RI i J. Lieberman, OE , D. Screnci, PA0 (2) Nuclear Safety Information Center (NSIC) { NRC Resident Inspector Distribution w/ encl: (Via E Mail) , (Non-E-mailable attachments to Enclosure are to be mailed or faxed) l M. Callahan, Office of Congressional Affairs ' W. Dean, OEDO D. Meran, Project Manager, NRR J. Stolz, PDI-2, NRR l Inspection Program Branch, NRR (IPAS) ' l DOCUMENT NAME: S:\HC9505.rin
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RI:DRSS/ , E RI:DRSS 6 RI:DRS l s 0FFICE , RI:DRP 'RI:DRSS _NAME J. Jar,g ~ \ Am 'A J. Kotta W T. Walker TZ W S. Morris c w R. Nimitz 6. s i DATE 05/12/95 / '/ 05/2 2 /95 05/ n /05 05/n /95 M^ 05/n '/95
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-U. S. NUCLEAR REGULATORY COMMISSION REGION I Report No. 50-354/95-05 License No. NPF-57
, ticensee: Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Facility: Hope Creek Nuclear Generating Station Dates: April 6-21, 1995 Inspcc+ars: R. L. Nimitz, CHP, Senior Radiation Specialist (Team Leader)
- S. A. Morris, Resident Inspector T. Walker, Senior Operations Engineer
, J. Jang, PhD., Senior Radi'ation Specialist
- J. Kottan, Senior Laboratory Specialist M h e-Approved
- [ rt 'J. Bores, Ch)ftf \/ l acilities_RadiatidnProjectionSection i44 u6n of Radiat 3n J fety and Safeguards 1
Insoection Summary: This inspection was a special reactive ssfety inspection I conducted to review the circumstances surrounding, and licensee actions and l evaluations asstciated with an unplanned release of radioactive material from i the Hope Creek Station south plant vent which occurred on the ettly morning l hours of April 5,1995. I Areas Reviewedi The following Executive Sumary delineates the inspection findings and conclusions. m 705t&9W59 Dff 7 PDR
i } i TABLE OF CONTENTS 1 EXECUTIVE .9tARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
- 1.0 INDIVIDUALS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . 8 i 2.0 PURPOSE AND SCOPE OF INSPECTION . . . . . . . . . . . . . . . . . . 8 1
! 3.0 EVENT DESCRIPTION. EVENT RESPONSE. ROOT CAUSE ANALYSIS. AND NRC l EVALUATION OF EVENT RESPONSE ................... 8
- 3.1 Event Description . . . . . . . . . . . . . . . . . . . . . . 8
! 3.2 Licensee Event Response and Sequence of Events ....... 9
- 3.3 Licensee Root Cause Analysis ................ 14 j 3.4 EC Assessment of Event Response .............. 15 i 40 LIQL ' RADWASTE CHEMICAL W/dTE SYST 4 "ESIGN A E OPE ATION .... 17
- 4.1 3eneral . . . . . . . . . . . ....... ...... 17 4.2 Background ......... ....... ...... 17 1 4.3 Licensee Understanding of Chem :al Waste System Design Basis i Before Event ........................ 18 1
4.4 NRC Evaluation of Licensee Engineering Design Reviews and , Safety Evaluations ..................... 18 i 4.4.1 Licensee Review of System Design ........... 18 i 4.4.2 Licensee Review of Planned DSE Operations . . . . . . . 20 i 4.5 DSE Operations During Start up Testing and Training of j Personnel on DSE Operation ................. 21 , 4.6 Operating Procedures for the DSE .............. 23 I 4.7 Overall Conclusions Regarding Cause of Event ........ 24 5.0 ADDITIONAL ISSUES (SYSTEM CONFIGURATION CONTROL) ......... 25 l i f. 0 EXTENT OF CONTAMINATION AE LICENSEE EVALUATION AE CONTROL OF i CONTAMINt4 TION . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 6.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 l 6.2 Licensee Response to Identification of Contamination .... 26
- 6.3 Description and Composition of Onsite Contamination . . . . . 27 l 6.4 Offsite Contamination (Outside Frotected Area) d. . . . . . . 28 i 6.3 Worker Notification of Contamination on Site ........ 29
! 6.6 Worker Contaminations and Radiation Monitoring and l Evaluation of Intakes of Radioactive Material . . . . . . . . 32 1 7.0 ESTIMATE OF RADIQACTIVITY RELEASED A E EFFLUENT CONTROLS ..... 34 j 7.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . '34 7.2 Operability of the SPV Effluent Monitoring System . . . . . . 34 , 7.3 Total Amount of Radioactive Materials Released ....... 36 l 7.4 Projected Dose to the Public and Conformance with Technical Specification Limits .................... 37 i 7.4.1 General . . . . . . . . . . . . . . . . . . . . . . . . 37 i 7.4.2 Liquid Release Pathway Analysis . . . . . . . . . . . . 37 I 7.4.3 Airburne Release Pathway Analysis . . . . . . . . . . . 38 7.5 Assessments and Conclusions . . . . . . . . . . . . . . . . . 39 8.0 EXIT E ETING ........................... 39 l
l l
- Attachments
Attachment 1, Individuals Contacted Attachment 2, Documents Reviewed Attachment 3, Event Time Line 1 Attachment 4, Schematic of Decontamination Solution Evaporator 1 4 Attachment 5, General Arrangement of Duct Work Affected by Release i , Attachment 6, Extent of Onsite Contamination within the Protected Area l Attachment 7, Radionuclide Analysis and Intercomparison of Ratios Attachment 8, Shoreline Sediment Sample Analysis Results Map Attachment 9, Shoreline Grass Sample Analysis Results Map ; Attachment 10, Technical Specification Compliance Matrix and Offsite Calculated Radiation Doses , Attachment 11, Public Exit Meeting Notes ! I l l
EXECUTIVE SL 4ARY Hope Creek Inspection Report 50 354/95 05 April 6 21, 1995 A. Description of Event 6 unplanned release of radioactive material, from the Hope Creek' station's south plant vent (SPV), occurred on the early morning hours of April 5, 1995. The radioactive material released originated from the decontamination solution evaporator (DSE) and travelled through the , unmonitored DSE effluent vent pipe to the SPV. The SPV effluent monitoring system did not detect the release due to its liquid mist / droplet form. The release contaminated portions of the site 4 protected area downwind of the release point. The release was not discovered unt- the afternoon of April 5, 1995. A contaminated vehicle left the site before the contamination was identified. B. General Findings and Conclusions
- 1. Licensee Response to Event The licensee's response to the initial alarm was appropriate.
However, incorrect diagnoses were made to explain conflicting i indications. Operations and radiation protection personnel relied j on the readings of the SPV monitor and samples of the DSE effluent ' and SPV effluent and incorrectly concluded that a release had not occurred. - The licensee was slow to identify the occurrence of a release due to weaknesses in communications and integrated assessment of incoming information. As a result, the licensee was slow to take actions to secure potential sources of additional releases and to take appropriate actions to prevent potential further spread of , contamination, and mitigate exposure pathways. 1 The licensee's procedures provided limited guidance for response to an onsite contamihation event.
- 2. Engineering The licensee did not have an adequate understanding of the design basis of the DSE and did not perform an adequate design review of the DSE and the SPV effluent monitoring system to support operation of the DSE.
The radiation effluent monitoring system was not capable of detecting effluent releases (in the form released) from the DSE. ' 0
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l i 5 i j 3. Operations and Operations Procedures The DSE was not operated in accordance with design basis or Final j Safety Analysis Report commitments. The inspection identified i that, among other findings, the DSE's operating level set i points / limits / alarms were set non-conservatively, the DSE was ' operated in " semi-continuous" mode versus " batch" mode, the processing of floor drain water was not evaluated, and automatic j control functions were o'v erridden to establish flow paths. i In addition, operating procedures for the DSE were inadequate, 4 there was a lack of clear understanding of system operation by i system operating personnel, and operating personnel did not have a
- clear understanding of system interlocks and automatic functions.
. Lastly, there was a belief that the DSE could not cause a i radioactive release and there was minimal monitoring of system
- operations.
1 ! C. Safety Significance i . j Although about 25 gallons of steam and water, that contained about 85 ! millicuries of mixed radioactive corrosion products were released from 1- the SPV, the release of radioactive contamination from the DSE had j little radiological impact on the public and environment. No release ! limits were exceeded and a reasonable worst case analysis did not i identify any significant potential impacts. The safe operation of the reactor was not affected and the release did not significantly impact on shift licensee personnel. In addition, although workers worked in areas later determined to have low levels of contamination, no intake of radioactive materials occurred and no significant personnel contaminations occurred. After it was identified that a release had occurred, there was excellent evaluation o' the impact of the release on the environment and on continued reactor operations by the licensea. D. Summary of Areas for EC Followup and Apparent Violations The inspectors identified a number of areas for followup and four apparent violations as follows.
- 1. The design review of the DSE was inadequate. As discussed in Section 4.0 of the inspection report, the licensee's design reviews did not identify DSE design weaknesses.
- 2. There were no adequate approved operating procedures for the DSE.
As discussed in Section 4.6 of the inspection report, as of April 5,1995, the operating procedures for the DSE, a liquid radwaste system component, were inadequate to limit uncontrolled releases to the environment and provide for proper operation of the DSE.
6 This is an apparent violation.of Technical Specification 6.8.1 requires, in part, that applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, be established, implemented and maintained. Appendix A of Regulatory Guide 1.33 recommends procedures for limiting release of radioactive materials to the environment including operation of liquid radioactive waste systems.
- 3. The surveying and monitoring of DSE effluents was not adequate to detect the release. As discussed in Section 7.2 of the inspection report, as of April 5, 1995, the licensee's surveys and i evaluations of the effluent released from the DSE exhaust to the south plant vent were inadequate to ensure compliance with the '
requirements of 10 CFR 20.1302. This is an apparent violation of l 10 CFR 20.1501(a).
- 4. Alarm set point changes were not made in accordance with approved procedures. As discussed in Section 5 of the inspection report, on April 12, 1995, alarm setpoints were increased on both the reactor building ventilation exhaust system and radwaste exhaust system ventilation duct radiation monitors without appropriate operating shift approval, indeper. der.t review, or technical document room notification. This is an apparent violation of Technical Specification 6.8.1 which requires, in part, that applicable procuivres recommended in Appandix A of Regulatory Guide 1.33, Revision 2, be established, implarented and maintained. Appendix A of Regulatory Guide 1.33 recommends procedures for control of temporary modifications.
- 5. Workers were not infomed of the release and onsite contamination once it was identified. As discussed in Section 6.5 of the inspection report, onsite workers and drivers of vehicles that traversed and worked in contaminated areas on April 5, 1995, were not informed until April 6, 1995, that they had potentially entered contaminated areas and should perfom enhanced personnel monitoring to detect contamination. This is an apparent violation of 10 CFR 19.12.
- 6. A contaminated vehicle left the site. (See Section 6.5 of the inspection report.)
- 7. The development by the licensee of a plan for disposal of contaminated soil and maintenance of records relative to 10 CFR 50.75(g). (See Section 6.3 of the inspection report.)
- 8. The verification by the licensee that apparent previous Hope Creek turbine building roof contamination and other site contamins. tion
. (as appropriate) has been properly evaluated from an offsite impact perspective. (See Section 3.2 of the inspection report.)
1
l 4 7 The NRC will review the above matters for follow-up and potential enforcement, as appropriate, and will review the event to determine if generic communications regarding the unmonitored release (e.g., an NRC Information Notice) are needed. l l l I I \ l l l i t i I i
DETAILS 1.0 INDIVIDUALS CONTACTED t j Attachment I this report identifies the individuals contacted. 2.0 PURPOSE AND - 2E OF INSPECTION The inspection was a special reactive NRC inspection conducted to review 4 the circumstances surrounding, licensee evaluations made, and corrective l actions taken following an unplanned release of radioactive material from the Hope Creek station's south plant vent (SPV) on the early morning hours of April 5,1995. a The inspectors reviewed the circumstances surrounding the event and the licensee's actions and evaluations associated with it. The inspect m interviewed individuals directly involved in the event aM responst ! it. The personnel involved in tt.= design review of the Jid radb. 3 i system were also interviewed. In addition, the licensee s root cause
- analysis of the event was reviewed. l 1 '
! The following matters were reviewed during the inspection. l 1 Sequence of Events Station Response to Event ) - Radiological Release Decontamination Solution Evaporator Design and Testing Decontamination Solution Evaporator Operation and Operating i Procedures - Radiological Controls and Contamination Controls The documents reviewed during the inspection are identified in 1 Attachment 2 to this report. A event time line is included as Attachment 3 of this report.
- 3.0 EVENT DESCRIPTIW EVENT RESPONSE. ROOT CAUSE ANALYSIS APO PRC 2
EVALUATION OF EVENT RESPONSE j 3.1 Event Description ? On the evening of April 4, 1995, a radwaste (RW) operator was processing wasta liquid from the chemical waste tank (CWT) via evaporation by use of the decontamination solution evaporator (DSE). Feed to the DSE was secured about 11:07 p.m. on April 4, 1995. Shortly before midnight on April 4,1995, the RW operator restarted feed flow to the DSE from the CWT. Feed to the DSE had been secured in order to refill the CWT from a floor drain collection tank (FDCT). 2
..___._____ _ _ _ _. _ ~._ _ _ _ _ _ _ _ - _ _
t 9 Between midnight and 1:00 a.m. on April 5, 1995, the RW operator l ' responded to several alarms, due to high differential pressure (dp) across the demister in the vapor body of the DSE, by spraying the demister with water from t.ie condensate system. In two instances the operator left the spray valve open for an extended period of time (6 minutes and 13 minutes, respectively) while attending to other l operations in the RW control room. The DSE is discussed in Section 4.0 of this report and is depicted in Attachment 4. Theprolongedsprayingofthedemister,combinedwithacontinuous ! supply of heating steam to the evaporator, caused a buildup of steam in the vapor body of the DSE. This resulted in an increased evaporator pressure that was suddenly relieved when the spray flow was secureJ. Unknown to the operator, the depressurization caused a momentary high steam flow condition in the six-inch diaeter DSE evaporator effluent exhaust pipe that ejected approximately 43 and 15 ga'lons on two occasions of a water and steam mixture to the south plant vent (SPV). Portions of the steam and water sixture (an estimated 25 gallons) was released to the environment from the SPV, while the remainder was deposited in the SPV duct work on the 155' elevation of the services radwaste (SRW) building. The radioactive liquid in the SPV duct work caused a limited increase in general area radiation levels, which were detected by three radiation monitors in the area. Two of the radiation monitors, on the reactor building ventilation system exhaust (RBVSE) and the radwaste area exhaust (RWE), alarmed at about 12:30 a.m. Both monitors indicated two - 1 distinct increases in radiation levels occurring approximately 7 minutes i after each of the two prolonged sprays of the DSE desister. Increased , radiation levels were also indicated on the filtered ventilation I recirculation system (FRYS) area radiation monitor (ARM), but no alarm I was received on this monitor due to the low radiation levels detected by 1 this ARM. There were no increases in radiation levels detected by the l SPV effluent monitor. Attachment 5 depicts the general arrangement of ' the duct work and radiation detectors affected by the release. l 3.2 Licensee Event Response and Sequence of Events In response to the radiation monitor alarms, control room (CR) operr. tors entered abnormal procedure HC.0P-A8.ZZ-0126 (AB-126), " Abnormal Releases of Gaseous Activity". Concurrently, a radiation protection (RP) technician initiated a review of the alarms in accordance with HC.RP- 1 AR.SP.0001, " Radiation Monitoring System Alam Response". These procedures direct personnel to review other radiation monitors for indications of radiation. The procedures also infom personnel to review SPV monitor readings for indications of radioactive releases. The operators and RP technician (technician A) independently checked multiple indications and detemined that the RBVSE and RWE monitors were the only alams that were received. L
i i i } 10 Both the CR and radiation protection personnel contacted the RW control i room and were told that the DSE was operating, but that no activities were in progress that could have caused the radiation alarms. No ! indications of a previous or in progress release was noted by review of the SPV monitor. ! The senior nuclear shift supervisor (SNSS), the work control supervisor, i an instrumentation and controls (I&C) technician, and two RP technicians 1 (technicians A and B) went to the area of the alarms to investigate the i cause of the alarms. They identified a hot spot in the SPV duct work i that measured approximately 120 mR/hr on contact and.15 mR/hr at i approximately one foot. (See Attachment 5 for location of hot spot.) After surveying the area and duct work, the radiation protection technicians and senior reactor operators (SR0s) believed that the hot
, spot was caused by a piece of solid material (possibly a piece of a l filter) that had been deposited ins the duct. The operations personnel i inspected the o ;ilation filter 4 rains, but could not detect any 1 damage. Liqu, sas observed dripping from the duct work into a i previously installed drip bag. The liquid was reddish brown in color and was assumed to be a pre-existing condition. Personnel believed i that, because no increase had been seen on the SPV effluent monitor, no i release had occurred or was in progress.
I An RP technician (technician B) and the I&C technician attempted to go l onto the SRW building roof in proximity to the SPV discharge point, to l check the SPV duct work, but the attempt was aborted when they
- identified that their clean booties (worn in the radiologically
- controlled area for housekeeping purposes) were contaminated.
- Consequently, the technicians could not exit onto the normally non-i contaminated roof area.
At approximately 2:00 a.m., as a result of the contaminations, the drip hag and the area under the drip bag were surveyed. The survey identified up 2 to 80,000 dpm/100 caf on the floor, and up to 220,000 dpm/100 cm in the drip bag. The RP technicians initiated action to enhance the drip bags to collect the leaking fluid and post and control the area as a contamination area. (Inspectors' Note: The above contaminatian survey resolts were detemined by the licensee using a 10% detection efficiency for the thin window GM contamination survey detector used to analyze the smear surveys. Subsequent licensee evaluations detemined that the efficiency of the GM contamination survey detector was approximately 2%. Consequentl 400,000 dps/100 cm'y contamination to 1,100,000 dpe/100 values p'otentially cm removable ranged:from The contamination. licensee was not aware initially of the reduced detector efficiency for the radionuclide mix encountered.) {cu' T
_. _ _ . _ _ _ ._ _ __. _ _ _. __ , ____ . . _ . ~ . . . _ - _ _ _ _ . _ 11 Several hours after the high radiation alarms were received, the CR operators exited (9 3:00 a.m.) procedure AB-126 because it was believed that no release had occurred and the procedure did not provide any applicable instructions for addressing the hot spot and contamination in the plant. The SNSS requested that the DSE be secured, but the RW operator suggested that the evaporator be left in service so that an effluent sample could be taken. The SNSS agreed to the suggestion and the DSE was left in operation. The RW operator also informed the CR that he had sprayed the DSE demister and caused a high level in the evaporator around the time that the radiation alarms were received. A sample of the process stream from the DSE effluent pipe was collected at approximately 4:00 a.m. that morning. The sample analysis results (provided about 5:00 a.m.) indicated that no unusual radiological releases were occurring from the DSE. A nuclear incident report (IR) and a radiological occurrence report (ROR) were initiated to address the radiation alarms and the hot spot found on the duct work. RORs were also written to address the personnel contaminations. At the morning managers' meeting, the RP manager was 1 assigned to investigate the incident report and Operations was assigned I to assist in determining if the DSE was the cause. After the meeting, the senior shift support (radwaste) supervisor reviewed the DSE recorder traces and concluded that, in spite of the preblems with evaporator level control on the previous shift, the DSE kas operating normally and Could not have caused the hot spot in the SPV duct work. At the time of the meeting, the day shift SNSS incorrectly believed that the DSE was secured and relayed the incorrect information to plant management. CR operators and shift supervision focused their efforts on preparing for a future release due to the fluid in the duct work drying out. They reviewed abnormal response proceoures and closely monitored radiation monitor indications. Throughout the morning of April 5, RP personnel continued to try to determine the cause and e.xtent of contamination associated with the hot spot and liquid found in the duct work. As part of the weekly routine sampling program, the continuous samples (particulate and iodine) from the SPV were pulled for analysis at about 3:00 a.m. A smear sample from the SPV enclosure was collected at approximately 9:15 a.m. This sample, analyzed at approximately 11:00 a.m. indicated the presence of short-lived radionuclides.
1 ) i a . i 12 l
~
i At approximately 10:00 a.m. iin April 5,1995, an RP supervisor (RP j supervisor A) and an RP technician (technician C) together exited from j the turbine building roof top area near the south plant vent and j identified contamination levels of up to about 8,000 dpm on their clean booties coming into the building from the roof top. j Although they informed their supervisor, no further evaluation was ! performed of the cause of their bootie contamination. The RP personnel j had collected some roof top rock (gravel) samples which were counted in
- a high sensitivity tool monitor. The rocks alarmed the tool monitor.
! (The turbine building roof was not posted as a contaminated area. The j turbine building roof access hatch is normally locked due to the
- preserice of radiation on the roof from steam passing through the turbine.) -
! The rocks were analyzed and deterhIi"ned around noon to contain longer-
- lived radionuclides (e.g., Mn-54 ~aWd Zn-65). These results were also i provided to the individual's supervisor; however, the contamination was i believed to be from a pre-existing condition on the roof and no further i evaluation was made of the rocks. The licensee's RP personnal indicated j a previous release of low level contamination of portions of the turbine building roof had occur-
- d. Chemistry personnel, who counted the rock l samples, noted unusual radionuclide contents indicative of reactor coolant and informed RP personnel of these observations. However, this
- information was not effectively communicated in that RP management was 2
not made aware of the information. The Senior RP supervisor did have a technician on standby to perform surveys of the outdoor areas because of the indicatica of contamination on the roof, however, this was canceled at around noon because the results from the 8:00 a.m. samples from the SPV weekly samples were received about noon and the sample results indicated no release had occurred or was in progress. Neither the identification of short-lived radionuclides at 9:15 a.m., the occurrence of personnel contaminations at 10:00 a.m., or the concerns raised by radiochemistry personnel were effectively integrated into the assessment of whethsr a release to the environment had occurred. The RP personnel conservatively posted the SPV event enclosures as a contaminated area at 12:10 p.m. A survty of the enclosure at 1:40 p.m. identified high levels of contamination (up to 25 millirad /hr as measured on wipe sample using an open window ion chamber) and water on the floor near the SPV duct work. The SPV was posted as high contamination area at that time. At about 2:20 p.m. on April 5,1995, RP technicians, informed of the potential contamination on the roof of the turbine building, questioned during shift turnover whether the roof-top area of the turbine building should be posted as a contaminated area.
I i j 13 I l At the 3:00 p.m. planning meeting, RP reported that they had not i identified any new concerns related to the incident report. (Note: As ! he was leaving the site at the end of day shift, the senior radwaste i supervisor was concerned that the source of the hot spot had not been
- identified. He called the RW control room and directed the operator to secure the DSE. The DSE was secured at 4:30 p.m.)
l ! RP technicians were dispatched to the turbine building roof to survey
- the roof to determine the need for posting of the roof as a contaminated
- area. At 3:30 p.m., a survey of the roof indicated elevated levels of
! contamination of about 10,000 dpm for a large area smear sample. Also, l short-lived radionuclides were identified during analysis of large area , wipe samples at about 4:00 p.m. indicating a release to the roof had i occurred. The technicians posted the roof area and informed their i supervisors, who directed that surveys of the yard area be performed. The inspectors noted however, that based on previously known information ! as discussed above, the licensee should have been aware of the potential j for a release to the environment i A survey of the yard area at about 4:30 p.m., identified removable l contamination of the yard area and on vehicles parked in the area in proximity to the south side of the turbine building. Levels ranging from less than 1000 dpm/100 cm' to 20,000 dpm/100 cm' removable
- contamination were identified. About 5,000 dps/100 cm' was identified i at the fence area near the hydrogen tankers. The RP technicians
! informed their supervisor. The inspector noted that the yard i contamination could have been identified earlier if the reasons for shoe { contaminations resulting from walking on the turbine building roof been j pursued. Hope Creek RP personnel contacted the Salem station RP
- organization and informed them of the identified contamination and j requested personnel to stand by to provide assistance.
! (Inspectors' Note: The above contamination survey results were i determined by the licensee using a 10% detection efficiency for the thin i window GM contamination survey detector used to analyze the smear j surveys. Subsequent licensee evaluations determined that the efficiency of the GM contamination survey detector was approximately 2%. Consequently contamination values actually ranged from less than 1000 dpe/100 cs' to 100,000 dps/100 cm' removable contamination. In addition, I the fence area exhibited about 25,000 dps/100 cm. The licensee was not aware initially of the reduced detector efficiency for the radionuclide mix encountered.) At approximately 5:15 p.m., the Hope Creek Senior Nuclear Shift Supervisor (SNSS) was notified of the yard contamination. The control room (CR) operators reentered the gaseous release abnormal procedure , (AB-126). The filter recirculation ventilation system (FRVS) was placed 1 in service and the major discharges through the south plant vent (reactor building ventilation, turbine building ventilation, and radwaste and services building ventilation) were secured at 5:50 p.m. in l l l I 1 I
I 14 accordance with AB-126. The iicensee deciered the SPV effluent monitor inoperable at 6:42 p.m. and initiated alternate samplbg (9 7:35 p.m.) of the SPV effluent. Hope Creek RP personnel again contacted Salem RP personnel at about 6:45 p.m., to inform them that contamination was identified at higher elevations of the station and to have radiation protection personnel stand by. Hope Creek RP personnel later (9 7:20 p.m.) notify Salem personnel to survey at higher elevations. , At approximately 8:00 p.m., the licensee informed the NRC senior i resident inspector (SRI) of the presence of contamination in the protected area. At about 11:30 p.m., Operations personnel informed RP personnel that a vehicle (an Air Products hydrogen tanker) had left the site at about 9:40 a.m. that morning. RP personnel were dispatched to survey the vehicle at its Delaware City terminal. At 11:30 p.m., RP personnel informed security personnel at the security building to prohibit exit of vehicles without RP permission. Because the vehicle had to be located and RP technicians sent to the location, the vehicle was not surveyed until 4:30 a.m. The survey of the hydrogen tanker at 4:30 a.m. on April 6 1995, identified removable contamination up to about 3,000 dps/100 cm',(Actually 15,000 dpm/100 cm 2 when corrected for the reduced efficiency discussed above.). Decontamination was performed of the vehicle at the teminal with cleaning cloths returned to the licensee's HC station. Personnel involved with the tanker were surveyed and found to be free of contamination. At 6:30 a.m., a four-hour report in accordance with 10 CFR 50.72(b)(2)(vi) was made to the NRC for the in6ivertent release of radioactively contaminated material. At 6:30 a.m., NRC inspection personnel entering the station were directed by security personnel to avoid grassy areas and remain on walkways. At ab)ut 8:00 a.m., radiation protection personnel were stationed at the security building to survey personnel leaving the protected area. Signs were also posted at the security area notifying personnel entering and i exiting the protected area of the onsite contamination. Enhanced ~ l personnel monitoring, using hand and foot monitors, for personnel l egressing the protected area, was initiated at approximately 10:30 a.m. I that day. i ! 3.3 Licensee Root Cause Analysis a ! The licensee established, appropriately staffed, and provided a specific i charter to the root cause analysis (RCA) team directed to analyze the
; event. NRC review indicated the RCA team focused on the significant i issues, including the mechanism by which the event occurred, and j demonstrated good use of analytical tools to establish root causes. The i .
f, 1 15 4 i team used procedure NC.NA-8P.ZZ-0002, " Root Cause," to guide the j analytical process. The inspectors concluded that the team's final j report was detailed and comprehensive; further, recommended corrective actions specifically addressed the identified root causes. l 1
- Ultimately the RCA team attributed the cause of the event to a design
- problem. Specifically, steam vapor leaving the DSE discharged directly j into the SPV without any condensing or filtering unit. This allowed two short duration releases of a steam / water mixture (approximately 58
. gallons total) to exit undetected from the DSE effluent vent pipe to the ,
i SPV after a high differential pressure condition inside the DSE was l j relievsd by prolonged spraying of an internal desister element. l 1 l About 25 gallons of radioactive liquid, in a mist / droplet fom, late:- was determined to have exited the SPV to the environment. The remainder was believed to have collected in the duct work, spilled to the floor, , i and returned to the DSE. 1
- 1 l Contributing causes were also determined by the RCA team to be primarily l design related (i.e., inadequate effluent radiation monitoring, no I
, automatic effluent isolation function, excessive DSE vent. piping length I with "no-slope" sections). However, inadequate procedures, operator i training and knowledge, and other operational concerns were concluded to have had direct impact on the event. l The release mechanism established by the RCA team was judged by the l inspectors to be credible and consistent with NRC findings and observations. The inspectors concluded that the licensee's RCA team j performed an excellent post-event analysis and review. l l 3.4 BC Assessment of Event Response i The inspectors determined that the licensee's initial response to the ! high radiation alarms was appropriate. The inspectors concluded, l however, that licensee personnel involved in the event and reviewing the i event during the -y on April 5, 1995, were slow to identify that a l release had occurred. Multiple indications were evaluated and i appropriate procedures were entered, however, an incorrect diagnosis was
- made to conflicting radiation monitor indications. Data and results
- being collected throughout the morning, which indicated that a release may have occurred, were not evaluated in an integrated fashion.
! Operations and radiation protection personnel believed that a release had not occurred due to: 1) the lack of eny indication of a release on i thc SPV effluent monitor, 2) sampi > results for the DSE effluent
- indicated that no release was in p ogress, 3) sample results from the SPV veekly sample indicated a release had not occurred, and 4)
, information provided by RW operations personnel indicated that operation j of the DSE could not result in a release of radioactive material. ; Subsequent investigation and follow-up activities were hindered by j misdiagnoses and communications problems. In addition, procedural
! weaknesses, involving limited guidance for control of radioactive 4
16 material outside the radiologically controlled area, contributed to the slow response to the event. The following examples are provided to support these conclusions. J - The SR0s on the night shift incorrectly believed that the hot spot was caused by solid material lodged in duct work. The SR0s and radwaste personnel did not believe that there was a mechanism that could have resulted in a release from the DSE into the SPV. As a result, the DSE was not secured until 16 hours after the event. Key information was identified throughout the investigation, but the information was not communicated and interpreted effectively, which delayed identification that t release had occurred. This inc':ded inf:rmation, obtained be- e noon on Apre 5, that per nnel hac become contaminated ile traversin; :he turbine bu: :ing roof, indicating the pre- ce of contamination in an unexpected location, and informatu.n provided by the chemistry group that they had identified unusual radioactivity on the turbine building roof. The procedure for abnormal gaseous releases (AB-126) and the radiation monitor alarm response procedure (ARP) focused the licensee staff's attention on use of the SPV monitor readings to ascertain whether a release had occurred or was in progress. Since i the SPV effluent monitor could not detect the release, this delayed actions to secure the SPV. Shift management and radiation protection personnel relied on radwaste personnel information that operation of the DSE could not have resulted in a release of radioactive material. The licensee was not initially aware of the reduced detection
- efficiency for radionuclide mix.
l ,t As a result of these problems, the licensee was slow to take actions to secure potential sources and to take appropriate actions to prevent potential further spread of contamination. Management attention and l direction was focused on preventing a future release from liquid drying i out in the duct, rather than on determining the cause and extent of the event, includine; whether a release had occurred. 1 The inspectors detemined that the event was properly reported and that the required notification was made, when it was identified that a contaminated vehicle had left the site. No emergency action levels (EALs) were exceeded during this event. i l
17 4.0 LIQUID RADWASTE CHEMICAL WASTE SYSTEM DESIGN AM) OPERATION : 4.1 General i The inspectors reviewed the design basis, start-up testing, and applir 41e desion change packages associated with start-up and operation , of the M. lhe inspectors also evaluated the general and specific ! knowledge of the licensee's personnel involved with design review, > start-up, and operation of the DSE. i 4.2 Background ! Hope Creek was originally constructed with an extensive solid and liquid radioactive waste handling system, however, the majority of the system was not placed in service when commercial operation of the plant began : in 1987. The solid waste processing system was not placed into service until 1989, and the evaporation (volume reduction) portion of the Liquid including the chemical waste subsystem : Waste of which Management System the DSE is part, was (LMS),'t no placed in operation until 1994. ) The DSE, located on the 54' elevation of the services radwaste (SRW) building, is a small capacity evaporator used to process chemical waste from the chemical waste tank. The evaporator was designed to process chemical wastes from laboratory drains, decontamination solutions, and i sample rack drainage on a batch basis. The Final Safety Analysis Report (FSAR) indicates that the DSE is operated on a batch basis. However, at the time of the event, the DSE was being used to process liquid I radioactive waste from the floor drain collection system in a semi-continuous mode. In an effort to minimize the total volume of radioactive waste shipped offsite, the licensee developed a LWS evaporator start-up plan. The plan was described in a project scope proposal drafted in 1992. This proposal included a plan to verify that the original LWS installation was intact, and to conduct a phased approach to starting up the various components in the system. In planning for the start-up and operation for the DSE, the licensee developed a " global" design change package (DCP 4EC-3348) to address minor deficiencies that may arise during the start-up of the system, and to control the necessary functional and operational testing. The DSE was in the final phase of this start-up testing at the time the release event occurred. The inspectors noted that the licensee's DCP did not evaluate the adequacy of the original design of the DSE, rather it served to provide a means to correct minor system operational issues which ray be encountered during system start-up and operation. The licensee's personnel assumed that the design had been reviewed and was acceptable. l l
. - . _ , _ _ . . _ _ y _ _ . _ _ . _ _ _ ,~,y -3 _
18 4.3 Licensee Understanding of Chemical Waste System Design Basis Before Event The inspectors concluded that the licensee's personnel involved in the DCP discussed above, and the operations personnel starting ep and operating the DSE, did not have an adequate understanding of the design basis of the DSE prior to the event, both in terms of its interconnection with the remainder of the LWMS and the SPV, and its functional operation. This was evidenced by the following observations. In several instances, actual LWMS configuration and operation conflicted with Final Safety Analysis Report (FSAR) section 11.2, I design bases and system descriptions. For example, LWMS effluents l were described in the FSAR to be " processed, monitored, and I diluted" prior to discharge to the environment. More I specifically, DSE operations were intended to occur on a " batch i processing" basis, with the effluent vapors then " sampled and l discharged" through the DSE effluent vent to the SPV. These activities did not occur in practice. Responsible engineering personnel were not completely familiar with the commitments made in the FSAR. After the event, a team of licensee engineering personnel was assembled to research and understand the original design basis of the DSE and its effluent path. Insufficient design documentation existed at Hope Creek to establish the true basis for the system's design and operation, indicating that familiarity with the design of the system, including the design bases for the SPV radiation monitoring system (RMS), was weak. Only after several days of effort, which included consultations with the system's vendor (General Electric) and the plant architect (Bechtel), was the licensee able to completely understand the features of the system and the reasons for its installed configuration. 4.4 PRC Evaluation of Licensee Engineering Design Reviews and Safety Evaluations 4.4.1 Licensee Review of System Design The inspectors concluded that the licensee did not identify significant DSE and SPV radiation monitoring system design concerns which, had they been noted and adequately addressed, likely would have prevented the April 5, 1995, inadvertent radioactive release. The inspectors determined that the licensee had several opportunities prior to the event to identify the noted problems with the design of the DSE. Missed opportunities included: the original design and independent review of the DSE and the SPV radiation monitoring systems; the 10 CFR
j 19 l 50.59 safety evaluations performed to justify the LWMS start-up program ! under DCP 4EC-3348; and the Hope Creek Station Operations Review j Committee (SORC) reviews of these same DCP safety evaluations. } As a result of weaknesses in the licensee's evaluation of the DSE, i several key issues were not addressed which impacted the likelihood and significance of this event. The following examples are provided. ) l - FSAR section 11.2.3, "Radioact!ve Releases," did not address the potential for a release via the DSE effluent vent path, despite { the fact that engineering drawings (Process and Instrument Drawings (P& ids)), as well as General Electric and Bechtel design ! documents, indicated that the DSE was directly vented to the j environment via the SPV. 4 4 - The DSE effluent path was not equipped with a radiation monitor l (or an associated high radiation isolation function), contrary to
- FSAR section 11.2.1 and 10.CFR 50 Appendix A General Design
! Criteria (GDC) 60 and 64 requirements regarding control, 1 monitoring, and sampling of radioactive releases. i Although the FSAR states that the DSE effluent is vapor (without i reference to a known " rainout" or " entrained liquid droplet" ! transport phenomenon), no assessment was made of the SPV effluent
- monitor's capability to detect such effluent in the FSAR RMS design bases (section 11.5). (Post-event analysis by the licensee i determined that the SPV monitor was incapable of detecting -
contaminants in vapor fom). l The inspectors noted that the licensee performed several 10 CFR 50.59 ! safety evaluations to assess the various phases of the DCP test plan, ' ! including the initial functional testing and the subsequent operational
- testing of the DSE. None of these evaluations addressed the potential
- for a radioactive release via the DSE process vent. Specifically, the j evaluations did not consider the potential for unexpected DSE
- operational transients that could be encountered or the capability of
! the SPV RMS to detect any rc ultant releases. Opportunities to identify 1 DSE and SPV RMS design problems during these safety evaluations may have
- been missed because of the nature of the DCP itself; that is, the DCP
- was drafted primarily to enable minor system deficiencies to be
! corrected during start-up testing, with the assumption that the safety l of the DSE had been evaluated previously in the FSAR. The inspectors
- did note that the licenses had evaluated the DSE relative to NRC j Information Nati o No. 91-40 and had concluded that the concerns raised
- in the notice were adequately addressed.
i i Following the event, the licensee learned that a decision was made in
- the mid-1970's to remove a process vent effluent condenser incorporated
,in the original vendor DSE design.
i ) 1
20 This decision was based on concerns regarding the potential for organic chemical contamination of the distillate that would be returned to the demineralized water system. Justification for this pre-installation design modification was based on a radiological impact assessment performed by Bechtel and subsequently approved by the licensee, which
- concluded that any radioactive contaminants released via this pathway l would be insignificant.
The licensee was not aware of this original design modification and its justification during the planning, evaluation, and conduct of the LWMS l start-up testing. As a result, certain assumptions made in the Bechtel I analysis were invalidated during the testing. For example, the analysis i assumed that the DSE would be proce: ng " batch" quantities of chemical i waste. In contrast, the licensee we processing, in a semi-continuous manner, low purity floor drain coll tion tank waste. Further, Bechtel assumed that routine batch samplir if the DSE process influent and effluent would occur to continual validate radiological effluent conditions; however, the licenset did not perfom such routine sampling in practice. The inspectors noted that, after the event, the licensee was not able to locate the original engineering change notice that authorized removal of the effluent condenser. , i The inspectors concluded that the licensee did not perfom an effective review of the LWMS design bases before initiating the operational testing phase of DCP 4EC-3348. This resulted in an inadequate justification for the conduct of the testing as it was ultimately performed and a failure to consider the impact of the DSE operation on i effluent releases and the adequacy of installed radiation monitors. ; 4.4.2 Licensee Review of Planned DSE Operations The inspectors detemined that the licensee did not adequately evaluate several DSE operational issues. The following examples are provided.
- No evaluation was conducted to justify operation of the DSE in a semi-continuous mode. The system was designed to be operated in a batch mode as described in the FSAR. There was no evaluation to i ensure that changing the mode of system operation did not have an effect on design assumptions for radwaste holdup times and sample j
requirements.
- There was no evaluation to justify processire of floor drain water in the DSE. (It was necessary to transfer or drain water to the CWT ^o provide a semi-continuous suppl: process fluid.) No
- onsider ion was c4ven to evaluation of d- eences in the nature of the r ;or drain ad chemical waste tank uts to 2temine if I
there was any impact on the DSE. Automatn .antrol functions
i .- 1 i !
- I f .
- l l 21 ,
1 had to be bypassed to establish a flowpath from the FDCT to the i i CWT, but no evaluation was performed to justify the acceptability ! l of bypassing the automatic control functions. i The chemical waste system and DSE operating parameters were not !' well defined or evaluated during the design change process. No specifications were defined for evaporator pressure, temperature,
- operating level, or for steam or desister spray flow rates. The operational testing was intended to demonstrate acceptable operation of the system; however, the only testing acceptance i criteria specified in the DCP was that the nominal evaporation rate of the DSE be at least 3 gallons per minute (gpm).
During the design change process, DSE operating level setpoints, limits, and alarms were set non-conservatively due to an error in interpreting design documents. The evaporator vendor manual specified that a control system was required to prevent steam from being admitted to the evaporator shell unless tubes were flooded with liquid. As a result of the misinterpretation of design information, the automatic steam shutoff function was set at a level 24 inches below the top of the tubes. Actual operating level for the DSE was selected based on experience gained during the start-up testing. The normal operating level for the DSE was 6 inches below the top of the tubes; therefore, the DSE was operated routinely with the tubes not flooded. The normal operating level also was not within the operating level band specified in the system operating procedure (50P). The level band in the 50P and the alarm setpoints'in the system ARPs were appropriate with respect to the level of the tubes in the evaporator. However, the discrepancies between the i setpoints in the existing procedures and the setpoints established ! in the design change process were not identified. l Overall, there was no indication that the operating characteristics of the evaporator were evaluated or that abnormal conditions were considered. As a result, it was not recognized that prolonged spraying of the desister or spraying while steaming could cause a pressure transient in the evaporator. 4.5 DSE Operations During Start up Testing and Training of Personnel on DSE Operation The inspectors' evaluations of actual DSE operations and training of personnel during start-up testing identified the following. No formal monitoring of system operation was performed during the operational testing phase of the start-up testing.
l 22 The DCP for the per" nance run stated that data would be gathered , in accordance with tae radwaste log procedure. This procedure ! contained a log sheet for the chemical waste system, but did not specify a frequency for completing the data sheet. Normally, the ! S0P specifies system logging requirements. In this case, the 50P had not been revised for current operation of the system and did not specify any logging requirements. The log sheet was completed at system start-up, but no routine logs were taken during system operation. There was no indication that any concerted effort was made to ensure that the system was operating properly. In at least one instance, system mis-operation was not reported and investigated. On March 25, 1995, a high level occurredn % the evaporator, apparently due to inadvertr-t closure of the steam inlet valve and failure of the evaporator sed inlet valve to fully close as designed. This abnormal cpndition was not identified until the DSE level recorder traces were reviewed in conjunction t:iti, investigation of the April 5 event. Radwaste personnel did not have a clear understanding of system interlocks and automatic functions. For example, both RW operators and supervisors had misconceptions about the automatic system response on high and low level evaporator level. This lack of understanding appeared to be due to failure to consolidate information from the design change process for incorporation into procedures and training material. Training had been conducted on the chemical waste system shortly before the event, but the system lesson plan had not been revised to reflect current information on system operation and contained many inaccuracies. l Operators and radwast.e su u rvision did not believe that the DSE could cause a radioac,tive nir.elease. They were not familier with the design basis of the DSE and did not recognize its potential to ! release radioactive contaminants through an unfiltered, l unmonitored effluent pathway. As a result, operation of the DSE was considered a lower prjority when conflicting demands that required operator attention existed. The RW operator involved in l the event indicated that he had clearly defined priorities and i would only have been concerned about DSE operation if a radiation alars was received on the steam supply for the DSE. On the night of the event, there were numerous evolutions in progress in the radwaste control room. When another operation, that was i considered higher priority than the DSE high differential pressure i (dp) alarm, required his attention, the operator was distracted ' and inadvertently left the desister spray valve open for ani extended period of time.. " re i
i i i 23 4.6 Operating Procedures for the DSE , 1 The inspectors' review of the operating procedures for the DSE l identified the following. The chemical waste system operating procedure was not revised to
- support the operational testing of the DSE. A conscious decision
- was made to rely on operator experience gained during start-up testing rather than a formal procedure for system operation.
j However, accurate, reliable information concerning system 4 operation was not readily available to the operators. The intent ' was to revise the procedure after start-up testing was complete so that experience gained during the operational testing could be
. incorporated. One of the activities that the RW operator was involved in on the night of the event was working on the revision
] to the procedure. The DSE operating procedure contained inaccurate information concerning system operation. For example, the procedure contained
- a note with incorrect information concerning automatic system
, response to high and low evaporator level. 4 The existing system operating procedure did not address semi- ! continuous operation of the DSE. No procedural direction was provided for refill of the CWT or DSE operation during the refill. A draft procedure was provided by engineering during the start-up j testing, but it also did not address operation of the DSE while . ! refilling the CWT. Operators were given the option of securing
- steam to the evaporator when refilling the CWT, therefore, the
> evolution was not perfomed consistently from shift to shift. Failure to secure steam while refilling the CWT caused an i unnecessary level transient in the DSE and unnecessarily challenged the automatic closure function of the steam valve on low level, i
- The safety evaluation in the DCP stated that water transfers would be controlled by approved procedures. However, no procedural direction was provided for transfer of water from the FDCT to the '
l CWT, even though automatic control functions and interlocks had to be overridden to establish the flowpath. i
- There was inadequate procedural guidance for process sampling as
. required in the design specifications and the FSAR. The operating l procedure required sampling of the CWT, but the procedural i direction could not be implemented because the system was not i operated in batch mode, as the 50P intended. Periodic CWT and FDCT samples were taken, but they were not analyzed for solids as specified in design specifications, and the sampling frequencies did not ensure that all DSE influent was sampled. I
1 l 24 The procedure addressed, but did not require, sampling of the
" vapors." It was not clear if " vapors" referred to the DSE effluent, because the sample point specified in the S0P was not on I the DSE discharge line. No routine samples of DSE effluent were j l taken. l The alarm response procedure for high differential pressure across the demister did not provide direction for spraying the demister, i Operators were trained to spray for 30 seconds to 1 minute, but no cautions were provided in procedures or in training on the I
consequences of prolonged spraying of or spraying while heating steam was being supplied to the DSE. Prolonged spraying while heating steam was being supplied to the DSE resulted in the pressure transients that caused the release of radioactive material. The inspectors noted that Technical Specification 6.8.1 requires, in part, that applicable procedures recomended in Appendix A of Regulatory Guide 1.33, Revision 2, be established, implemented and maintained. Appendix A of Regulatory Guide 1.33 reconnends procedures for limiting release of radioactive materials to the environment, including operation i of liquid radioactive waste systems. Based on the above review, the inspectors concluded that as of April 5, 1995, the operating procedures for the Decontamination Solution Evaporator, a liquid radwaste system component, were inadequate to limit i uncontrolled releases to the environment and provide for proper - operation of the DSE. Specifically, on April 5,1995, the DSE ; discharged about 85 millicuries of mixed radioactive corrosion products, ! in an uncontrolled manner to the environment, and the procedures and
' controls for operation of the DSE were inadequate to either preclude or detect the occurrence. This is an apparent violation of Technica! l Specifications. (VIO 50-354/95-05-01) -
4.7 Overall Conclusions Regarding Cause of Event The inspectors concluded that the primary root cause of the April 5, 1995, event was an inadequate system design. However, secondary causal factors were also identified. The inspectors also concluded that the licensee did not have an adequate understanding of the design basis of the DSE and did not perform adequate design reviews of the LWMS chemic~al waste subsystem and SPV radiation monitoring system prior to placing the DSE into operation. Several opportunities were missed in the original design and design change processes to identify a failure to meet General Design Criteria requirementse regarding monitoring and control of radioactive effluents. a ar The inspectors further concluded that overall control of system operation was weak. Operating parameters were not clearly defined or evaluated prior to system start-up. There was minimal monitoring of system operation even though the system was in a testing mode.
25 Radwaste personnel did not have a clear understanding of system operation and system operating and alarm response procedures did not provide adequate direction for operation of the DSE. Existing procedures were not adhered to and the DSE was not operated in accordance with the design bases or FSAR commitments. Some of these weaknesses contributed directly to the event. For example, inadequate procedural direction and understcnding of system operation resulted in prolonged spraying of the demister, which ultimately caused the release. 5.0 ADDITIONAL ISSUES (SYSTEM CONFIGlRATION CONTROL) Subsequent to the event, on April 12, 1995, temporary modifications (T-Mod's) were made to two non-Class IE ventilation duct radiation monitors. Specifically, the RWE and RBVSE duct radiation monitor alarm setpoints were increased in order to clear locked-in high radiation alarms caused by elevated background radiation levels which resulted from the April 5, 1995 release. Although it was known that this change would reduce the sensitivity of the stated detectors, it was deemed necessary in order to provide control room operators some indication of a transient condition in the event of a subsequent release via the affected pathways.
- Although the inspectors noted that the affected radiation monitors were not Technical Specification-required monitors, the inspectors were informed and noted that T-Mod's were not implemented in accordance with i the established licensee procedure (NC.NA-AP.ZZ-0013(Q), " Control of l Temporary Modifications"). Specifically, the alarm setpoint changes '
were made without appropriate operations shift acknowledgement, l independent review, and technical document room notification. Further, I the radiation protection database control procedure, HC.RP-GP.SP-0001, 1 was not implemented because the appropriate radiation protection ' department personnel notifications were not made. This deficiency, attributed by the licensee to personnel error, was identified by the responsible licensee technical department supervisor and documented in an internal station incident report. Technical Specification 6.8.1 requires in part that applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Rev 2 be established, implemented and maintained. Appendix A of Regulatory Guide 1.33 recommends procedures for control of temporary modifications. The above failure to follow procedures is an apparent violation of Technical Specifications. (VIO 50-354/95-05-02)
26 6.0 EXTENT OF CONTAMINATION AND LICENSEE EVALUATION AND CONTROL OF CONTAMINATION 6.1 General The inspectors reviewed the extent of onsite and offsite contamination resulting from the unplanned release of radioactive material from the SPV. . The inspector also evaluated the adequacy of the licensee's efforts to 3 control the contamination once it was identified. In addition, the inspectors evaluated the licensee's measurements of offsite (outside protected area) contamination, and its potential impact on the public. 6.2 Licensee Rer.1se to Identification of Contami. 3 tion The licensee discovered removable contamination on the roof of the turbine building at approximately 3:30 p.m. on April 5, 1995. As a result, Hope Creek RP personnel were directed to perform surveys of the yard area south of the turbine building. The surveys of the yard area, performed at approximately 4:30 p.m. on April 5, 1995, indicated removable contamination. Once the contamination was identified, Hope Creek RP personnel informed , Salem station RP personnel of the onsite contamination. This ' notification prompted Salem RP personnel to survey and monitor normally accessible walkways and entrances to the Salem station. No contamination was detected at the Salem station. Hope Creek RP personnel later informed Sales station RP personnel that the contamination may have been deposited at higher ehevations. This notification, at about 8:00 p.m. on April 5,1995, prompted Salem station personnel to survey elevated areas in the wind direction provided by Hope Creek personnel. Salem RP personnel identified, using large area smear surveys, low levels of contamination on the Salem Unit 2 turbine building deck. The Salem turbine deck was posted to inform personnel of the contamination. Once the onsite contamination was identified, the licensee did send personnel to survey areas outside the protected area. The results of surveys perfomed outside the protected area are discussed in Section 6.4 of this report. The licensee's corporate radiation protection services organization was informed of the contamination on the morning of April 6, 1995. The services group initiated offsite surveys and developed an enhanced environmental monitoring program. In addition, the licensee initiated action to retrieve and analyze airborne samples from fixed monitoring stations at offsite locations.
i l 27 4 6.3 Description and Composition of Onsite Contamination Attachment 6 to this report depicts the magnitude and extent of contamination of the Hope Creek and Salem stations. Note that the values for contamination levels given in Attachment 6 tre in counts per 2 minute per 100 cm . These values may be corrected to disintegrations per minute per 100 cm' (dpm/100cm ) by dividing the value by .02 (the nominal 2 detection efficiency for the handheld frisker for the radionuclide mixture). The inspectors' review indicated that the majority of contamination was located on the roof area of the Hope Creek turbine building and the area immediately south of the Hope Creek turbine building. The contamination appeared to have exited the SPV in a droplet-like form as evidenced by reddish-brown spots observed by an inspector on the. turbine building roof. Contamination levels ranged from about 150,000 dpm/100ca' (corrected for radionuclide mix) at the SPV, to less than detectable at th extreme point of deposition within the protected area. Contamination surveys on the Salem Unit 2 station's turbine deck did not identify contamination with area surveys of 100 cm . Large area surveys, using cloth wipes, 2 however, identified low levels of contamination. The identified areas of contamination were immediately posted and controlled. The licensee did not detect radioactive materials via surveys of areas outside of the area depicted in Attachment 6. Based on the Grvey results, the majority of contamination fell directly south of and in close proximity to the Hope Creek turbine building, an area located within the protected area that was not accessible to the public. A number of licensee vehicles, located in the area south of the turbine building, were contaminated to levels averaging 100,000 dpm/100 cm' (corrected for radionuclide mix). These vehicles were decontaminated. No significant contamination was identified at the immediate area of the south exit point from the Hope Creek station, an area frequented by individuals taking breaks while smoking. In addition, no contamination was detected within the Salem or Hope Creek station building air intake systems or cafeterias. In order to confim the source of the radioactive material deposited on site, and evaluate the release to determine if a chronic low-level release may have occurred, the licensee performed gamma spectroscopic analysis of representative surveys of various contamination samples collected throughout the site. The results of those analyses are depicted in Attachment 7. Attachment 7 provides percentage ratios of the radionuclides identified in the sample results, which confim that the mix and ratios of radionuclides identified were similar to those identified in the DSE.
1 1 28 At the conclusion of the inspection, the licensee's root e analysis team and corporate r 'ological s / ices group concludec i gallons of liquid, it about 25 aining abe 85 millicuries of m- radioactive { corrosion product: been rei d from the SPV to t i ivironment. l The 25 gallons w+ imated to been r- ised fre otal of 58
- gallons which wa. 1 eased to t. i efflt vent 4
! Based on the data provided, the inspectors concluded :nat the
- radioactive materials deposited on portions of the station originated from the DSE. This was evidenced by the consistency of ratios for
! short-lived products and the lack of identification (in any compass ;
.irection) of any radioactive materials immediately outside the plume l
'ntamination foot-print area) depicted in Attachment 6.
Tr inspectors' discussions we b licensee personr- indic,ted a pr- s event apparently had resulted very Ic levels adic :tive contamination being depositea the tur ne builu g roof. This ma - was not included wit.41n the scupe of this inspection. .However, the licensee indicated the information on the previous event will be obtained and provided to the NRC during a subsequent inspection. The inspector indicated the matter will be evaluated relative to the need to include such a release in the licensee's deconumissioning database file, as required by 10 CFR 50.75(g), and whether such a release required NRC approval to leave the previous contamination found on the turbine building roof in place. Overall, the inspectors concluded that the licensee performed a comprehensive evaluation of the extent and composition of onsite contamination associated with the April 5,1995, unplanned release, once the contamination was identified. 6.4 Offsite Contamination (Outside Protected Area) As discussed abova, the licensee performed surveys outside of the protected area. No contamination was detected using either smear surveys or monitoring with handheld survey meters. The licensee retrieved offsite airborne radioactivity monitoring samples from various locations around the site out to about 10 miles. The licensee collected five air samples from stations that continuously l collected airborne samples, four surface water samples, and nine grass samples. These included samples from sampling stations in Delaware and i New Jersey. The licensee's sample analysis results did not identify any detectable activity attributable to the release. i
4 l l l 9 i : The licensee also collected soil and grass samples from the shoreline l
- directly downwind from the Hope Creek SPV. The samples were collected ;
l within the owner controlled area and were analyzed by high sensitivity l gamma spectroscopy analysis to lower limits of detection recommended by , the NRC. The samples were collected to evaluate the potential for i contamination outside the protected area. l The licensee detected contamination in samples of soil. The samples i collected were two-foot diameter circular areas 1.25 inches deep. The maximum sample result was about 577 picoeuries per kilogram (pCi/kg) 4 (corrected for hard-to-detect Fe-55) in location B-10, which is located on the shoreline within the owner controlled area south of the Salem l
! station.
- j 1
3 The levels detected in soil samples, as well as their location, are l l shown in Attachment 8. This maximum result indicated twice the I concentration of normal activity seen in river sediment samples near the 1 plant liquid effluent discharge point. The inspectors noted that the
- radioactive contamination detected would not result in any significant i i exposure of members of the public. The maximum offsite doses projected
! for the radioactive contamination released is discussed in Section 7.4 l of this report. ! The licensee also collected shoreline grass samples. The grass samples were grass clippings collected from a two-foot diameter area. The licensee detected a m rimum of about 43,500 picoeuries per kilogram (at j location B-9) (correro j for hard-to-detect Fe-55) of grass. The levels i detected, as well as leir location, are shown in Attachment 9. The ! maximum projected of ite doses for the radioactive contamination
- released is discusses in Section 7.4 of this rr. port.
3 The inspectors noted that the contamination was within the owner controlled area and did not represent a hazard to members of the public. The licensee estimated that about 2,000 linear feet of shoreline exhibited trace contamination not detectable by hand held monitoring instruments. The licensee will include the radioactivity released , during the event in subsequent effluent release reports. ! The dose assessments for members of the public potentially exposed to , the contamination is discussed in Section 7.4 of this report. 6.5 Worker Notification of Contamination on Site i
- The licensee became aware of the onsite contamination in the area south
! of the Hope Creek turbine building at about 4:30 p.m. on April 5, 1995. Prior to the discovery, numerous contractor employees had worked during the day of April 5, 1995, on a new site services building located between the Salem and Hope Creek stations. At least two of the conti ar. tor workers also worked in grassy areas located in proximity j l
l 30 to the south side of the Hope Creek turbine building. The individuals worked in manholes 10 and 10A near the walkway from the Hope Creek station to the security processing area. The inspectors' review indicated that essentially all of the workers left the site at the end of the work day at about 3:00 p.m. on April 5, 1995, prior to the discovery by the licensee that a release had occurred. A licensee contamination survey, documented at 5:00 p.m. on 4 April 5,1995, indicated removable contamination south ofr the Hope Creek turbine building ranging from less than 1000 dpm/100 ca to 100,000 dpm/100cm' (corrected for radionuclide mix). The average removable contamination in the area south of the turbine . building indicated about 50,000 dpm/100cm' (corrected for radionuclide mix). The inspector also noted that the licensee identified about 25,000 dpm/100cm' (corrected for radionuclide mix) of contamination on the site services building on April 5, 1995. The licensee posted these areas as contamination areas. The inspector questioned licensee personnel as to what information was provided to workers once the contamination was discovered. Licensee l personnel indicated that once the contamination was discovered, the ) affected areas were posted imediately. In addition, security personnel ! later were informed to go to the Sales radiological control point and perform whole body frisking. Security vehicles were surveyed. No l readily identifiable contamination was noted. The licensee also l initiated, on April 6, 1995, periodic updates of personnel via separate information notes and via the licensee's onsite employee newspaper. The licensee's RP personnel directed security personnel that workers should be informed that they were not to go to the new site services i i building, but to report to their muster areas. Security personnel informed workers coming into the station as early as 6:30 a.m. on April ; 6,1995, that personnel were only to walk in designated areas and remain l off of the grassy areas. The inspector noted that no posting or infomation was placed at the entrance or exit of the security building until about 8:00 a.m. on April 6,1995, to indicate to personnel that an unplanned contamination release event had occurred. The licensee's RP personnel indicated to the inspectors that they believed that it was not necessary to inform workers who had left the station of the contamination event because: 1) personnel were monitored
' by a portal monitor as they left the station; 2) personnel who had traversed the contaminated areas were not alaming portal monitors inside the security building or at the RP control points; and 3) surveys perfomed inside the security building and parking lot areas did not identify any contamination.
31 The . inspectors evaluated the RP personnel's decision not to inform workers of the contamination event. The inspector reviewed the sensitivity of the portal monitor and noted that the portal monitor at the security building had a sensitivity of about 450,000 dpm. However, the monitor had previously identified personnel attempting to exit the station with lower levels of contamination, but the licensee was not ' able to qualify the minimum amount of contamination detectable. The inspector noted that 10 CFR 19.12 requires that all individuals working in or frequenting a restricted area be kept informed of the
! storage, transfer, or use of radioactive materials or of radiation in such portions of the restricted area and be instructed in the health protection problems associated with exposure to such radioactive material or radiation, and be instructed in prceautions or procedures to minimize exposure.
The inspectors' noted that the extent of such instructions is required to be commensurate with the potential radiological health problems in the restricted area. The licensee's RP personnel met with the construction workers on the morning of April 6, 1995, and briefed them on the extent of contamination, the potential radiological hazards, and the actions on-going to evaluate the release. The workers were informed to return to : their home and bring back the clothes they had worn the previous day so that the clothing could be monitored for contamination. The workers-returned clothing throughout the afternoon of April 6, 1995, but did not return to work on the site services building that day. Notwithstanding the information that was provided to workers on the morning of April 6, 1995, the inspectors' believed that it was reasonable to have informed, on April 5,1995, all construction workers who had worked in close proximity to the Hope Creek turbine building of the discovery of removable radioactive contamination in their work area, and to have requested at that time that they return to the station so that their person and clothes could be monitored. This was reasonable considering that: 1) the licensee did not know who had worked in the contaminated areas and what the nature of their tasks was; and 2) it was not apparent that the portal monitor could readily identify contamination that was less than high levels. In addition, the licensee did not post a notice at the security building once the site contamination was identified infoming personnel of the event. Such notification would have allowed workers exiting the station after the discovery of the contamination the option of requesting high sensitivity personnel monitoring before leaving the site. In addition, licensee RP personnel did not take any action to loctte any vehicles that may have left the site until approximately 11:30 p.n. on
' April 5, 1995, when it was brought to their attention that a vehicle (hydrogen tanker) had left the site at approximately 9:40 a.m. that day.
The vehicle, when located at approximately 4:30 a.m. on April 6, N95,
32 was determined to be contaminated. The contaminated vehicle was , unknowingly removed from the site. The licensee's radiation protection program procedure (NC.NA-AP.ZZ-0029(Q) - Revision 2) prohibits release of materials with radioactive contamination as specified in Section 5.0 of the procedure. The inspector noted'that once it was brought to the RP group's attention that a vehicle had left the site, the licensee initiated a review to identify any other vehicles that may have left the site after the contamination event occurred. The licensee subsequently identified that 18 vehicles (including the above discussed hydrogen tanker) had left the site after the time of the release. These 18 vehicles were located and surveyed by radiation protection personnel. Vehicle handling personnel were also surveyed. Of the 18 vehicles, only cr>. the above discussed hydrogen tanker truck, was identified as contam sted. The tanker was decontaminated and returned to the station for t 'ther monitoring.on April 6, 1995. Decontamination cloths were also returned to the site. No personnel who drove or worked with the vehicles was contaminated. The inspector noted that the contamiriation on the hydrogen truck was '~ generally tenacious and was not easily dispersed. In addition, there was no precipitation in the area on April 5 and 6, 1995, thW. would have dispersed the contamination. The inspectors noted that the failure to infom personnel of the contamination event was an apparent' violation of 10 CFR 19.12. (VIO 50-354/95-05-03) 6.6 Worker Contaminations and Radiation Monitoring and Evaluation of Intakes of Radioactive Material The inspector noted that, once the onsite contamination was identified on the afternoon of April 5,1995, Salem station RP personnel initiated actions to monitor individuals who may have traversed the area during the time of release or thereaft c. These individuals were primarily security personnel. Also, vehicles used by the security force were surveyed. No readily detectable contamination was identified. The i licensee also initiated whole body counting of on-shift personnel who were present on the day of release and who could have been exposed to airborne radioactive material. These individuals, as indicated above, were primarily roving security personnel. No intakes of radioactive material were identified. At the end of the inspection, the licensee. was reviewing the potential for any of the approximately 97 personnel who were on shift during the period of release to have traversed the contaminated area. The licensee directed all construction workers to report to the Salem station radiological control point on the morning of April 6, 1995. at about 10:00 a.m. for frisking with high sensitivity whc t body frukers. As noted previously, the licensee monitored about 32 incividuals wno worked for the contractor performing work on the new site services building. Of the 32 individuals monitored, the licensee determined that
i - [ 33 I 11 individuals may have worked in contaminated areas. These 11 ! individuals were whole body counted on April 7, 1995. No intakes of ! radioactive material was identified by whole body counting. i The inspectors noted that trace amounts of contamination was identified :
- on shoes of 13 of the 32 individuals. These individuals' vehicles were !
surveyed and no contamination was identified. Trace clothing contamina'.icn was identified on the outer layers of clothing worn on l April 6,1995, of five of the 13 individuals. The clothing was i determined by the licensee to have been the same outer garments worn by 1 ! these individuals on April 5. According to the licensee, none of the l contamination was detectable by handheld monitoring with a frisker (thin l window Geiger-Mueller (GM) pancake probe). The licensee decontaminated j the clothing. Two of the five individuals, who were considered to have been the individuals who worked in closest proximity to the areas of j maximum contamination, were interviewed by the inspectors. The d inspectors noted that the two contractor workers had received radiation worker training. The two individuals had not been provided personnel radiation monitoring devices because of the expectation that the . i workers' tasks would not result in any measurable radiation exposure. l The inspectors' review indicated all individuals who exited the site on
- April 5, 1995, followed directions of security force personnel and re-
- monitored themselves if a portal monitor alarmed. The inspectors' i interviews of workers and security force personnel indicated security
- personnel were familiar with requirements for monitoring personnel
- leaving the site. I l The inspectors also noted that the licensee performed an exposure )
! evaluation to determine the potential external radiation exposure for j- individuals who may have been standing or working near the ground contamination. The licensee assumed a maximum exposure time of 48 hours and concluded that the maximum calculated radiation exposure was less than 1 millires. The inspector noted that the individuals worked in the area for no more than 8 hours following the contamination event. The inspectors noted that the licensee performed skin dose assessments assuming workers were unknowingly contaminated to levels equal to the highest levels of ground contamination seen. Th licensee's calculations, perforised for skin density thicknesses of both 3 milligram per centimeter squared (ag/ca') and 7 mg/cs', indicated no significant ' skin exposure was sustained assuming an 8 hour exposure period. The inspector noted that no regulatory limit would be exceeded for a 24-hour exposure period. Further, no monitoring of personnel skin dose would be i required. The licensee also estimated exposure of workers to i radioactive material via inhalation, submersion in the plume, and exposure due to resuspended radioactive material. No significant exposure was estimated for these pathways. Exposure results were well ! within regulatory requirements. l
34 , Based on the above review, the inspectors concluded that no significant personnel contamination, external radiation exposure, or intake of ; radioactive material by personnel occurred. At the end of the inspection, the licensee was finalizing its dose assessments. These final assessments will be reviewed during a subsequent inspection. , 7.0 ESTIMATE OF RADI0 ACTIVITY RELEASED AlO EFFLUENT CONTROLS 7.1 General The inspectors reviewed the licensee's estimates of radioactivity released from the SPV, its potential impact on members of the public, and the licensee's conformance with applicable regulatory requirements controlling the allowable quantities and release rates of radioactive material. The following areas were reviewed during the inspection. (1) Operability of SPV effluent monitoring system (2) Quantification of the radioactive materials released to the environment (3). Calculation of projected dose to the public, and (4) Implementation of the radiological environmental monitoring program (REMP). I 7.2 Operability of the SPV Effluent Monitoring System 't The SPV effluent monitor provides continuous particulate, iodine, and noble gas monitoring of effluents discharged through the SPV. The monitor consists of isokinetic sampling probes installed in the duct work, a continuous particulate monitor, a continuous gaseous iodine monitor, and a continuous gaseous effluent monitor. The particulate channel and iodine channel of the monitor are equipped, respectively, with filters to collect sawples of particulate and gaseous iodine effluent releases. Noble gas releases are monitored continuously and periodically verified by grab sampling and analysis. The general arrangement of the sampling station, as well as the locations for the reactor and radwaste building exhaust monitors, is shown in Attachment 5. As shown in Attachment 5, isokinetic sampling probes are connected to the SPV sampling station. The isokinetic sampling probes installed in the SPV duct work are not designed to collect liquid mist or vapor. During the event on April 5,1995, radioactive liquid in a mist / droplet form was released through the SPV. Accordingly, the SPV effluent monitoring system did not detect any unusual radioactivity in the effluents.
- ._ -. . - --.-- - - - . . - _ . - . - . - - - . . - - - - .~
i . l . l 35 l The inspector reviewed analytical results for SPV iodine and particulate i samples and monitoring results-for radwaste, turbine, and reactor
- building effluent RMS. Analytical data for the SPV iodine and particulate samples indicated normal activities.
j During the event, however, reactor and radwaste building exhaust
- radiation monitoring systems (RMS) in the vicinity of the SPV alarmed.
i The locations of the reactor and radwaste building exhaust RMS are 6 . feet and 10 feet away, respectively, from the SPV. Radioactive liquid 4 found on the SPV floor and contained within duct work was believed to . have caused these two exhaust RMS channels to alarm. The turbine } building exhaust RMS did not alarm because this RMS is farther away from the SPV. l Based on the reviews of analytical rr ' s and RMS monitoring results, the inspector determined that the SPV sampling station and RMS were operable at the time of the event and were also operable during the investigation. However, because of the nature of the release (i.e., liquid mist / droplet form) the release was not detected by the SPV. The inspectors believe that the monitor was unlikely to detect the release because: 1) the release was not in a form easily sampled by the SPV isokinetic probes; and 2) the DSE effluent (9 700 cubic feet per minute (CFM)) discharged from a vent pipe into the SPV, which had a discharge flow of about 400,000 CFM. Consequently, the DSE effluent released would be highly diluted before it reached the isokinetic probe. l The inspector noted that 10 CFR 20.1501(a) requires that each licensee make or cause to be made surveys that may be necessary and reasonable to comply with the regulations in this part and are reasonable under the circumstances. Also, 10 CFR 20.1103 defines a survey as an evaluation of the radiological conditions incident to, among other matters, the release, disposal or presence of radioactive material or other sources of radiation. When appropriate, such an evaluation includes a physical ! survey of the location of radioactive materials and measurement or calculations of levels of radiation or concentrations or quantities of radioactive material present. 10 CFR 20.1302(a) requires that the licensee make or cause to be made, as appropriate, surveys of radiation levels in unrestricted areas and controlled areas and radioactive materials in effluents released to unrestricted and controlled areas to demonstrate compliance with the dose limits for individual members of the public in 20.1301. The licensee must show compliance with the dose limits of 10 CFR 20.1301 by the methods outlined in 10 CFR 20.1302(b). The inspector noted that, as of April 5,1995, and since initial start-up of the system (at least since October 1994), the licensee's surveys and evaluations of the effluent released from the decontamination solution evaporator exhaust to the south plant vent were inadequate to ensure compliance with the requirements of 10 CFR 20.1302. Specifically, the inspector noted that the licensee had not evaluated
1 I 36 the physical characteristics of the effluent released from the DSE when i t the DSE was operating in 1) the continuous or semi-continuous mode of I i operation, or 2) during periods when DSE demister spraying was performed to reduce high differential pressure conditions. As a result, the ; licensee was unable to detect the release of an estimated 85 millicuries ! of radioactive material that was released from the DSE to the environment via the SPV on April 5, 1995. This is an apparent violation of 10 CFR 20.1501(a). (VIO 50-354/95-05-04) 7.3- Total Amount of Radioactive Materials Released 1 The inspectors reviewed the licensee's methods used to estimate the 4 total amount of radioactive material released from the SPV. The inspectors also performed independent calculations to estimate the quantities of radioactive materials released. t The licensee estimated the amount of radioactive material released by three different methods. The first method involved use of a computer I code (MIDAS) and concentrations of radioactive material found in soil samples outside the protected area. The licensee back-calculated the release assuming deposition velocities ! contained in NRC regulatory guides. The licensee calculated about- 1 l curie of mixed corrosion products was released. This was considered a very conservative calculation (i.e., likely to overestimate the release) in that the licensee assumed the release was a particulate release when in fact the release was liquid. - The licensee performed a second estimate of radioactive material released by using comprehensive measurements of radioactivity levels in the protected area with a thin window GM probe. The licensee concluded ' that about 10 millicuries of mixed corrosion products had been released fromthesouthplintventusingthissecondmethod. The licensee subsequently performed a release calculation using the volume of liquid that was estimated, by the licensee's root case analysis group, to have been released from the SPV and the liquid radioactivity concentrations in the DSE. The licensee concluded that 25 gallons of liquid may have been released from the SPV which contained a total of 85 millicuries of mixed corrosion products. This calculation appeared to be reasonable. The licensee also performed a reasonable worst case estimate of radioactive contamination that could have been released. The calculation is discussed in Section 7.5 of this report. The inspectors estimated the amount of radioactive material released by using radioactive material concentrations obtained from the licensee's analysis of liquid samples obtained from the SPV floor (likely released ; liquids). The inspector assumed 100 gallons (3.8E+5 milliliters) of liquid was released and concluded the total amount of radioactive j ' materials released to the licensee's property was 268 mil 11 curies of mixed corrosion products. Correcting the amount of radioactivity released for hard-to-detect iron-55 (Fe-55) results in a total estimated
- x v -- - -- w
.e f
4 37 amount of radioactivity released of about 346 millicuries. If 25 gallons was released (using the licensee's estimate of liquid volume released), it is expected that about 86 millicuries wuld be released. 1 This estimate compares favorably with the licensee's estimate. The l inspectors noted that, based on reviews of surveys and tours of the
- areas, the majority of the released radioactive materials landed on the
- grass of the protected area close to the south side of the Hope Creek turbine building and on the turbine building roof.
! The inspectors noted that the licensee included into the dose i calculations, the total amount of tritium (H-3) potentially released to [ the environment. The licensee used H-3 activity measured in the i evaporator water and/or evaporator feed water rather than tritium
- sampling.at the SPV stack. The average H-3 activity in the evaporator
! water was 1.32E-3 yCi/ml. Therefore, the total amount of H-3 released during this event was 5.02E+2 yCi (0.502 millicuries). ! The projected dose to the public and licensee confomance with j applicable release limits are discussed in Section 7.4 of this report. i
- 7.4 Projected Dose to the Public and Conformance with Technical l.
Specification Limits E f 7.4.1 General The inspectors evaluated the potential doses that could be received by members of the public attributable to the radioactivity released from the SPV on April 5, 1995. The inspectors reviewed liquid and airborne release pathways. The inspectors interviewed and discussed dose results with cognizant licensee personnel. The inspectors evaluated the licensee's calculations and methods to determine projected potential offsite doses to members of the public. The inspectors noted that the licensee conservatively assumed (for the purpose of deze calculations) that the total estimated volume of liquid released (25 gallons) from the SPV was discharged offsite. Such a calculation would significantly overestimate the offsite dose, since the majority of the liquid released would have settled on the onsite building roofs and grounds. 7.4.2 Liquid Release Pathway Analysis
]
Due to rain on April 8 and 9,1995, the licensee analyzed storm drain samples. The stors draias catch runoff from roofs and the ground before release to the environment. The licensee, in anticipation of rain, applied a commercial sealer to the site walkways and driveways that indicated contamination. Landscape rock was also sealed with a commercial sealer. The licensee also applied a sealer to roof tops. Consequently runoff of radioactive contamination was expected to be 1 minimal. Also, the licensee cut and bagged contaminated grass before any rain occurred. These methods were considered very good licensee contingencies to minimize releases to offsite environs. The inspector noted that the majority of radionuclides in the SPV release were short-lived, and would decay away quickly.
38 T inspe ars' revie, dicated tb analytical results of the st m
. .in sar as were v- ow and nea the environmental lower limi . of stection ,LLDs). i 'spectors actermined that there was no dose consequence to the ; a ic relative to storm drain runoff. In addition, the inspector noted that the licensee's calculations, using NRC-approved methods, indicated the licensee did not exceed either the Technical Specification 3.11.1.1' liquid effluent concentration limit or the Technical Specification 3.11.1.2 liquid effluent offsite dose limits.
Maximum concentrations of radioactivity in liquids contained in outfalls were below 1% of maximum permissible limits. In addition, maximum projected organ doses and total body doses were well below limits, assuming the entire estima* 25 gall ms of liquid was r. ' eased to t.S river. Based on the above review, the inspectors concluded that the liquid release had no significant offsite dose impact on personnel. 7.4.3 Airborne Release Pathway Analysis The inspectors reviewed the licensee's airborne release pathway analyses and compliance with Technical Specification release limits. The inspector reviewed and discussed the Technical Specification 3.11.2.1.b gaseous effluent dose values, Technical Specification 3.11.2.3 iodine, tritium and radionuclides in particulate form dose limits and values, and also discussed Technical Specification 3.12.1.b environmental monitoring program results. The inspectors' review of the licensee's data and methods indicated the licensee used offsite dose calculation manual methodologies and actual meteorological conditions. The review indicated all dose values were well within Technical Specification limits using, as a source term, the radioactivity contained in the 25 gallons estimated to have been released from the SPV. As noted above, the licensee, in performing the calculations, assumed that all radioactivity contained within the 25 gallons was released offsite. The inspectors noted that the licensee calculated the potential exposure (due to inhalation and direct exposure to deposited activity) to a hypothetical member of the public who may have been at the Delaware River shoreline during and following the event. Based on review of assumptions used in the calculation, the inspectors agreed that no significant exposure would have occurred. l
i i 39 i Based on the above review, the inspectors concluded that the airborne release had no significant offsite dose impact on personnel. i 4 7.5 Assessments and Conclusions , l . Based on the above reviews, the inspectors concluded that there were no I
- radiological impacts on either the public or the offsite environment. I f
- Attachment 10 to this report provides a Technical Specification j compliance matrix developed by the licensee to show applicable limits,
- maximum calculated doses for the event, and comparison of doses (or
- quantities) from releases during calendar year 1994 and the April 5, ;
j 1995, event. j The inspectors further noted that the licensee perfomed a reasonable ! l j worst case analysis for offsite dose consequences. The analysis assumed l i that a quantity of radioactive material, equal to five times that ! i released on April 5,1995, was released in the direction of the closest I ! site boundary (901 meters north). The licensee's calculations indicated 2 the potential doses would be well within the dose liefts for individual l members of the public outlined in 10 CFR 20.1301. i I i 8.0 EXIT E ETING ! The inspectors held a public exit meeting on April 21, 1995, at the licensee's combined Salem / Hope Creek station processing center. Members
- of the public including w mbers of the media, attended the meeting. The j inspectors summarized the purpose, scope, and findings of the j inspection. Attachment 11 to this report provides the information
! discussed at the exit meeting. The licensee acknowledged the inspection
- findings.
l l i
Attachment 1 INDIVIDUALS CONTACTED I. Public Service Electric and Gas Comoany. Inc.
*J. Benjamin, General Manager, Quality Assurance and Nuclear Safety Review D. Branham, Chemistry Support M. Champ, Manager, Nuclear Communication V. Cirlante, Sen,or Radiation Protection Supervisor, ALARA
*J. Clancy, Technical Manager, Hope Creek Operations T. DiGuiseppi, Manager, Emergency Preparedness and Radiological Support R. Dolan, Principal Engineer, Chemistry Services
*L. Eliason, Chief Nuclear Officer and President, Nuclear Business Unit R. 3ary, Senior RP Supervisor, Operations J. dagan, Vice-President Nuclear Operations F. Higgins, Planning Manager R. Hovey, General Manager, Hope Creek Operations M. Ivanick, Senior Security Regulatory Coordinator P. Kordziel, Senior Planner
*S. LaBruna, V. P. Nuclear Engineering
*C. Lambert, Manager, Nuclear Engineering Design J. Molner, Senior RP Supervisor
*W. O'Malley, Operations Manager
*P. Opsal, Chemistry Manager J. Priest, Engineer, Licensing and Regulation
*M. Prystupa, RP Manager D. Smith, Principal Engineer, Nuclear Licensing
*F. Thomsor, Manager Nuclear Licensing G. Trotter, Supervisor, Testing
*M. Trum, Maintenance Manager J. Nichols, Manager, Assessment J. Wray, Principal Engineer, Radiological Support
- 2. Others C. Mumert, Site Superintendent, Ratheon M. Sesok, Hope Creek site representative, Atlantic Electric K. Tosch, Nuclear Engineer, New Jersey Bureau of Nuclear Engineering D. Vann, Nuclear Engineer, New Jersey Bureau of Nuclear Engineering
2
- 3. U. S. Nuclear Reoulatory Commission
- S. Shankman, Deputy Director, Division of Radiation Safety and Safeguards (DRSS)
- J. White, Chief, Reactor Projects Section 2A, Division of Reactor Projects
- R. Bores, Chief, Facilities Radiation Protection Section, DRSS
- R. Summers, Senior Resident Inspector, Hope Creek Station
- Indicates attendance at exit meeting on April 21, 1995.
l i 1 l 1 1
l Attachment 2
)
DOCUMENTS REVIEWED
- Memorandum from M. Prystupa to M. Trum dated 4/18/95, " Root Cause investigation of IR # 95-083 South Plant Vent Radioactive Material Release of April 5, 1995" - Nuclear Incident Report 95-083, RX BLDG EXHAUST HI RAD - Hope Creek Significant Event Review Team (SERT) Report 95-02, Inadvertent Release, dated April 5, 1995 - HC.0P-50.H8-0003(R) - Rev. 2, " Liquid Radwaste - Chemical Waste System Operation" (and draft Rev. 3) - HC.0P-AR.HB-0007(R), Rev. 4, "Radwaste Annunciator Panel 00C300 CN-3"
- .HC.0P-SO.HB-0002(R), Rev. 6, " Liquid Radwaste - Floor Drain System Operation" - HC.0P-AB.ZZ-0126(Q), Rev. 4, " Abnormal Release of Gaseous Radioactivity" - HC.0P-DL.ZZ-0030(R), Rev. 6, "Radwaste Management Log" - Student Handout No. 300H-000.00H-00H805-02, Chemical Drains System - Instruction Manual Detergent Evaporator Waste Evaporator System - General Employee Lesson Plans - HP.RP-GP.SP-0001(Q), Rev. 7, " Control of Radiation Monitoring System Setpoints" - HC.RP-AR.SP-0001(Q),, Rev.10. " Radiation Monitoring System Alarm Response" - HP.RP-TI.ZZ-1001(Q), Rev. 5 " Radiological Occurrence Investigations" 3 - HP.RP-TI.ZZ-0804(Q), Rev. 5, " Labelling and Control of Radioactive Material" - HC.RP-TI.ZZ-0201(Q), Rev. 5, " Access Control Point Management" - HC.SA-AP.ZZ-0046(Q), Rev. 6, " Radiological Access Control Program"
- HC.RP-TI.ZZ-024 (Q), Rev. 6, " Posting of Radiological Signs and Barriers" - HC.RP-TI.ZZ-062(Q), Rev. 7, Radiation and Contamination Surveys - HC.RP-TI.ZZ-0205(Q), Rev. 6, " Decontamination of Personnel and Skin Dose Assessment"
k 2 1 HC.RP-TI.ZZ-0602(Q), Rev. 7, " Radiation and Contamination Surveys"
- NC.NA-AP.ZZ-0013(Q), Rev. 2, " Control of Temporary Modifications" l
- NC. IIA-AP.ZZ-0024(Q), Rev. 4, " Radiation Protection Program"
} NC.NA AP.ZZ-0059 (Q), Rev.3, "10 CFR 50.59 Reviews and Cafety Evaluati9ns" NC.DE-WB.ZZ-0001(Q), " Standard Design Charge Workbook One" l NC.NA-AP.ZZ-0008(Q), " Control of Design and Configuration Changes" 4 Process and Instrumentation Drawings (P& ids) M-26-1, Radiation Monitoring System M-62-0 Equipment Drain M-63-0 Floor Drain M-64-0 Chemical Waste
- M-65-0 Waste Evaporator j -
0-P-HB-11 Isometric for DSE Vent to SPV Hope Creek Design Change Package 4EC-3348 (LWMS Startup Program) Hope Creek Profect Scope Proposal H92-007 (LWMS Startup Program) (
- - Hope Creek Final Safety Analysis Report (FSAR) Sections 11.2, 11.5, ,
14.2, 15.7 i
- PNO-G14-4010 GE Design Specification for Radioactive Waste Disposal i System l
l
- GEK-90351 GE Design Document for LWMS 10855-D3.43 Design, Installation l
and Test Specification for Hope Creek LWMS l j - May 17, 1995 Memorandum (Bechtel Corp. to PSE&G) regarding j Decontamination Solution Evaporator
- May 17, 1995 memorandum (GE to PSE&G) answering PSE&G questions
' regarding Decentamination Solution Evaporator
- NRC Information Notice 91-40, " Contamination of a Nonradioactive Sys' tem and Resulting Possibility for Unmonitored, Uncontrolled Rele&se to the 1
invironment,", dated June 19, 1991 \
- - NRC Circular No. 79-21, " Prevention of Unplanned Releases of 3 Radioactivity," dated October 19, 1979 3
- NRC Circular No. 80-18, , "10 CFR 50.59 Safety Evaluations for Changes
- to Radioactive Waste Treatment Systems," dated August 22, 1980 i
~ - _
3
- NRC Bulletin 80-10, " Contamination of Nonradioactive System and Resulting Potential for Unmonitored, Uncontrolled Release to Environment," dated May 6, 1980
- NRC NUREG 1048 and Supplements, " Hope Creek Safety Evaluation Report,"
dated October 1984 ' Various NRC Regulatory Guides including Regulatory Guides 1.21, 1.26. l 1.143 i i - s,-
l Attachment 3 EVENT TIME LINE Times are approximate: April 4, 1995 11:07 p.m. A radwaste (RW) operator secures feed to the decontamination solution evaporator (DSE) and initiates refill of chemical waste ' tank (CWT) from a floor drain collection tank. 11:45 p.m. RW operator completes fill of CWT and restarts feed to DSE. April 5, 1995 j 12:07 a.m. High differential pressure alarm on DSE demister. RW operator . sprays demister and leaves spray valve open for 6 minutes. l 12:19 a.m. Radiation levels on reactor building ventilation system exhaust I (RBVSE) and radwaste exhaust (RWE) radiation monitors start to ! increase. ~ 12:23 a.m. Radiation alarms received in control room and radiation protection alarm monitoring station. 12:24 a.m. High differential pressure alarm on DSE demister. RW operator i sprays demister and closes spray valve in < 1 minute. 12:28 a.m. High differential pressure alarm on DSE demister. RW operator : sprays demister and leaves spray valve open for 13 minutes. 12:30 a.m. Control room operators and radiation protection technician (technician A) investigate radiation alarms. Radiation protection technician A goes to the area of the detectors in alarm condition (services radwaste (SRW) building elevation 155') and performs a radiation survey with a hand held ion chamber. The technician does not identify an apparent cause of the alarm. 12:35 a.m. A second radiation protection technician (technician B) and an I&C technician go to the location of the detectors in alarm condition. Technician B takes additional radiation survey instruments to perform comprehensive surveys in the overhead areas near the detectors. The senior nuclear shift supervisor (SNSS) and work control supervisor go to area to investigate.
1 l 2 12:48 a.m. Radiation levels on RBVSE and RWE radiation monitors increase again. 1:30 a.m. Radiation protection technician B discovers a spot in the duct work near the reacter building vent exhaust monitor that measures about 120 mR/hr on contact and 15 mR/hr at one foot. The RP and I&C technicians attempt to go on to the roof to check the south plant ventilation (SPV) duct work. However, upon surveying themselves to exit onto the roof, the individuals identify that they are contaminated. The technicians' booties read 6,000 dpm and 4,000 dpm respectively (uncorrected for hard-to detect-radionuclides) . The radiation protection technician initiates radiological occurrence reports to document the contamination events. 2:00 a.m As a result of becoming contaminated, the technician (Technician B) surveys the area under a drip bag that was not containing all liquid leaking from the duct work. The survey identified up to 80,000 dpm/100 cm' on the floor and up to 220,000 dpm/100 cm' in the drip bag (Values uncorrected for hard-to-detect radionuclides). The radiation protection technicians confer with the senior reactor operators (SR0s) at the area of alarming effluent monitor (155' elevation service radwaste). They believe that the hot spot is from a piece of solid material (possibly a piece of a filter) that has become lodged in the duct. l A statice incident report is initiated to document the hot spot found on .5e duct work. 3:00 a.m. Control rcom (CR) operators exit procedure AB-126. SNSS requests RW operator to secure DSE. RW operator suggests sampling DSE vapor instead. RW operator informs CR of DSE level perturbation. l 4:00 a.m. RW operator assists chemistry technician in obtaining a sample of DSE vapor. 5:00 a.m. DSE effluent sample results are received. Results indicate no. significant activity (IE-7 uti/ml). 7:30 a.m. The radiation protection manager is assigned to determine the cause of the alarms of the reactor building axhaust monitor and radwaste exhaust monitor and hot spot in the duct work. Operations is assigned to assist in determining if the DSE was the cause. Senior RW supervisor investigates and determines that DSE is operating normally. l 8:00 a.m. Weekly samples of SPV collected. ,
. l l
l I l l 3 1 l 9:15 a.m. A smear sample is taken of the SPV enclosure. The sample (enalyzed l at about 11:00 a.m.) indicates short lived radionuclides. I 9:40 a.m. An Air Products hydrogen tanker trailer, later determined to be contaminated, leaves the station. 10:00 a.m. An RP supervisor and an RP technician go to the turbine roof to perform surveys. Rocks are collected. The individuals find that their shoes are contaminated when they leave the roof. The roof area access is normally locked and controlled by RP. 11:30 a.m. Rock sample results indicate presence of long lived radionuclides. Chemistry personnel indicate results are unusual. , noon The senior RP supervisor cancels outside yard survey due to no 4 unusual radionuclides identified on the SPV weekly sample. l 12:10 p.m. Roof surveys aro initiated. The south plant. vent is posted as a Contamination Area. 1:40 p.m. While looking for the source of radioactive contamination found in the south plant vent exhaust duct work, a survey of the south plant vent enclosure identifies high levels of contamination leaking from the duct work. The SPV is posted as a High Contamination Area. i 2:20 p.m. RP technicians question how the turbine building roof is posted. The roof was then posted no access pending detailed survey. 3:00 p.m. The senior RW supervisor lerarned that the source of the hot spot had not been identified during the planning meeting. 3:30 p.m. A survey of the turbine building (TB) roof identified elevated contamination levels and short-lived radionuclides. Radiation protection personnel determine that contamination found on TB roof is not from an earlier release as was previously believed. . 4:00 p.m. The Hope Creek turbine building roof is posted as a contaminated area. 4:30 p.m. Radiation protection personnel initiate surveys of the machine shop. No contamination is found. TheDSEgsecuredif}hedirectiogoftheseniorRWsupervisor. 4:45 p.m. Radiation protection surveys of the vehicles parked south of the turbine building identify gross removable contamination of about 20,000 dpm (uncorrected for hard-to-detect-radionuclides). I
i . 4 5:15 p.m. SNSS notified of yard contamination. CR operators enter procedure AB-126. 5:50 p.m. The filter recirculation ventilation system (FRVS) is placed in service. The major discharges through the south plant vent are secured. 6:20 p.m Radiation protection surveys of the north side of the new site i services building identify about 5,000 dpm/100 cm (ur.:orrected 2 for hard-to-detect radionuclides) on vertical surfaces of the building. 6:30 p.m. The radiation protection personnel initiate surveys of the site.
. 6:42 p.m. The licensee declares the south plant vent effluent monitor inoperable.
6:45 p.m A Hope Creek radiation protection supervisor notifies the Salem radiation protection of the cont mination event. 7:20 p.m. Hope Creek RP personnel notify Salem RP personnel that contamination was found at higher elevations. Salem RP personnel initiate confirmatory surveys of upper elevations of the station. 7:35 p.m. Radiation protection personnel initiate alternate sampling of the south plant vent monitor. 8:00 p.m. The licensee infoms the NRC senior resident inspector (SRI) of the presence of contamination in the protected area. 8:10 p.m. Salem radiation protection personnel identify contamination on the Unit 2 turbine deck railing of about 5,000 dpm/large area smear (uncorrected for hard-to-detect radionuclides). 11:10 p.m. A decontamination crew finds approximately 2 gallons of red / brown liquid in SPV duct. 11:30 p.m. The licensee's senior radit Hon protection supervisor directs that no vehicles leave the prot u ed area. The directive is issued after it was determined that a vehicle left the site. . April 6, 1995 4:30 a.m. The licensee decides to issue a press release concerning the contaminated Air Products vehicle. s 6:30 a.m. A four-hour report is made to the NRC for an event of media interest. 7:30 a.m. Contractor personnel begin arriving at the station. The personnel gather at change areas. Personnel are informed of the contamination found in the protected area and are directed to go
l . 5 I to the Salem health physics control point and perform personnel . frisking. Personnel remain in the change areas until about 10:00
- a.m. Personnel are also requested to go home and return with j clothes that they wore to the site the previous day.
8:30 a.m. The licensee is informed by a contractor supervisor that several workers who had been working outside the site services building the previous day alarmed the portal monitor in the security building when attempting to exit the station. The workers were directed to re-check themselves and were found to be free of contamination. The workers are identified and directed to obtain whole body counts. 9:15 a.m. All personnel are requested to come to the Salem Station health physics control point to perform whole body frisking. 9:35 a.m. The licensee places signs at the security building to alert personnel coming into the station of the presence of contamination within the protected area. The licensee also places signs to alert personnel exiting the site that additional frisking was required to exit the station. The licensee initiates frisking using hand held friskers. 10:00 a.m. Workers report to the Salem radiation protection control point to l perform personnel monitoring. A number of individuals alarm the high sensitivity personnel contamination monitors at the RP control point. Subsequent surveys of the individuals do not indicate any contamination using a hand held frisker. 10:30 a.m. The licensee implements enhanced monitoring of personnel exiting the protected area. The licensee requires personnel to use a hand and foot monitor prior to leaving the station. Individuals that are identified as contaminated were decontaminated. 2:00 p.m. The licensee continues to perfom surveys for contamination outside the protected area. None are identified.
. . _ . _ _ _ . - _ _ _ . _ _ _ _ _ . _ . _ . _ _ . . _ _ - _ . . _ _ . _ . _ _ . . _ . _ . _ _ . _ - _ _ . .~ .. . . _ _ . _ _ _ _ _ _
l Attachment 4. Schematic of Dacor5tamination solution Evaporator I M %-
!E VAPOR f- ,
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~
96" TOP OF HEATER HEATING ;L goa OPERATED WATER LEVEL ELEMENT N 84" LAH VENT lm
; 72" ACTUAL l , LONEST ~.": VEL LEVEL g LAL- STM ~ 7N X TRANSMITER {
(N138) - l l
; 40" LALL
' _ STEAM CONDENSATE
..... q OUTLET 36"BOTTON FEED p l OF HEATER INLET l hlINSTR. ZERO
- \/ '
DENSITY l TRANSMITER (N139) o . DECON SOLUTION EVAP VAPOR BODY BATCH DISCHARGE DWG NOT TO SCALE , SOURCE: Public Service Electric and Gas Company, Inc.
9 i .
. Attachmnet 5. General Arranaemnet of Duct Work Affected by Release South Plant Vent (SPV)
I l
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Radwaste Bldg. RMS g (6 feet'from i SPV) Evaporator ' Reactor Bldg. Effluent Line (6") RMS (10 ft fra SPV)
. ) Approximate location of hot spot.
SPV RMS and Sampling Skid y Sampling Skid and RMS for the SPV
Attachment 6, Exteot of Onsite Contamination within the P'rotected Area uc' 9 l 'i,' ' i l I l i P - =l 3 l l\ le ( a>S g e a N N' , H 4 b' l h\ e--
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l Technical Umiting Condition for Operation 4/5/95 Event 1994 Valuee section 3.11.1.1 The concestration of M meterial raisesed in Equid algueres to Maximum measured > Uquid EfRuonts Concentration UNRESTRICTED AREAS sher be ilmited to the concentrations speclRed In 10 CFR 20, Appendix B. Table 2 for radionucNdes other then actMtyin outimEs less then 1% MPC AR releases less than MPC { n - w dissolved or ertrained noble gases. 8- [ o i 5 3.11.1.2 The does or does commitmert to a MEnEBER OF THE PUBUC from ODCM i Anthod ' " ;
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4 5 1 Attachment 11, Public Exit Meeting Notes l - _. i l i i 4 i NRC REVIEW FPIDINGS I OF i i HOPE CREEK NUCLEAR STATION l APRIL 5,1995 j UNPLANNED RELEASE k i i k 4 a l t PUBLIC PRESENTATION i APRIL 21,1995 ?.
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i . i l i l NRC INSPECTION NO. 50-354/95-05
- 1 April 6 - April 21,1995 l
} NRC Inspection Personnel i l { R. L. Nimitz, CHP, Senior Radiation Specialist ! (Team Leader) i T. E. Walker, Senior Operations Engineer 1 l S. A. Morris, Resident Inspector l J. C. Jang, PhD, Senior Radiation Sparialist ! J. J. Kottan, Senior Laboratory Spacialist l i i I
N i 1 4 4 j TOPICS OF DISCUSSION 1 1 I. EVENT
SUMMARY
l j II. INITIAL LICENSEE RESPONSE 1 ? l f III. SAFETY SIGNIFICANCE 1 i i ! IV. PROGRAMMATIC ISSUES l t i V.
SUMMARY
OF AREAS FOR NRC I FOLLOWUP AND POTENTIAL ENFORCEMENT i i i i i l i i i { l I i,
- l. l l
l l l l l I. EVENT
SUMMARY
l l . !
- Late on the evening of April 4,1995, an operator l
! was processing contaminated water from the l l Chemical Waste Tank via the installed station i l Decontamination Solution Evaporator (DSE) i i located on the 54' elevation Service Radwaste ! l Building. The evaporator was designed to l process chemical wastes from laboratory drains, j decontamination solutions, and sample rack i drainage on a batch basis. However, the DSE j was being used to process liquid radioactive waste j from the floor drain collection system in a semi-continuous mode. The operator experienced a high differential pressure on the evaporator's demister and initiated a spray clanning of the demister to clear material clogging the demister.
- As a result of the spraying, and resultant pressure transient within the DSE, between about 12:15 a.m. and 1:00 a.m. on April 5,1995, radioactive contamination, in the form of entrained liquid / mist was released from the DSE.
- The entrained liquid / mist travelled through the DSE's effluent discharge line to the South Plant Vent (SPV) exhaust duct located on the @ 155' elevation of the Service Radwaste Building.
_ . _ _ _ _ _ _ ._ _ ._ __ _ _ _ . . _ __ I
4 Event Summary (Contd) 1
- The radioactive contaminated entrained l liquid / mist was discharged from the SPV onto the l Hope Creek turbine building (TB) roof and downwind in a southerly direction onto portions !
of the Hope Creek station's protected area and ! vehicles and buildines located near the TB. Portions of Salem station's protected area were , also slightly contaminated.
- As a result of the release, the Reactor Building )
i Ventilation Exhaust (RBVE) and Radwaste Exhaust (RWE) Radiation Monitors alarmed.
- Subsequent licensee review and follow-up resulted in discovery of onsite radioactive contamination on the afternoon of April 5,1995.
h
I e ) ) Event Summary (Contd) i I4
- As a result of the event, a special NRC review l was conducted. Areas reviewed included the following.
The circumstances surrounding the event. 4 4 . l The licensee's initial response to the event i including reporting. J The licensee's analysis of the event. . l The evaporator and ventilation system design Operations of the evaporator. I i
- Effluent Releases and Public Impact i .
Onsite Radiological Controls s
II. LICENSEE INITIAL RESPONSE 4
-
- The licensee immediately implemented alarm response procedures and initiated an investigation to determine the cause of the RBVE and RWE alarms.
- Licensee personnel quicidy responded to the area where the detectors in alarm were located (@l55' elevation Services Radwaste Building) and through surveys identified radioactive contaminated liquid laaking from duct work and a localized hot spot measuring about 100 mR/hr.
- Licensee personnel reviewed SPV radiation monitors and subsequently collected samples from )
the DSE effluent discharge line. The results indicated no release had occurred and no release was in progress. ll
i i i l i Licensee Initial Response (Contd) I l
- The licensee believed material or filter debris had j entered the duct work, no release to the j environment had occurred, and initiated reviews
! to identify the cause of the hot spot and liquid. l Action was taken to plan securing of ventilation systems to prevent release from the duct in the ! event the material could dry out and be released j to the environment. The weekly samples of the SPV efDuent, collected early on the morning of l April 5,1995, did not indicate any unusual . releases had occurred.
- Licensee supervision and management were informed of the matter early on the morning of i April 5,1995. The licensee initiated actions to l establish a Root Cause Analysis Team at 7:30 j a.m. on April 5,1995, i
i
- Throughout the morning and afternoon of April 5, the licensee continued to perform surveys and evaluate the extent of contamination. Surveys of i the turbine building roof identified contamination i at about 2:00 p.m. The results prompted a
! survey of the yard area south of the TB which I identified contamination about 3:00 p.m. that
! day. Based on the levels detected, and the nature of the event, the licensee concluded no reporting
} was required. i i
Licensee Initial Response (Cuatd)
- Contaminated areas were roped otY and posted.
An off site survey team performed surveys outside the protected area and did not detect contamination. The licensee established an Environmental Survey Plan in response to the event. l
- As a result of the discovery of outdoor contamination, the licensee stopped major ventilation inputs to the SPV at about 6:00 p.m. l on April 5,1995. The licensee declared the SPV :
monitor inoperable at about 6:30 p.m. that day ~ and initiated alternate sampling. The DSE had been shut down earlier that afternoon as a conservative action' independent of the discovery of contamination.
- The NRC was notified of the onsite contamination at 8:00 p.m. on April 5,1995.
- At about 11:30 p.m. on April 5, it was determined that a vehicle left the site earlier that day. A survey of the vehicle at 4:30 a.m. on ,
April 6, identified low les el contamination on the vehicle. The licensee initiated a fennal report to the NRC.
4 4 i i i
- Licensee Initial Response (Contd)
- The licensee established a Significant Event l Review Team on April 6,1995, and initiated special monitoring of personnel leaving the l station. Contamination monitoring of personnel
! and vehicles that were on site on April 5 was also ! initiated. l
- Licensee analysis of shoreline samples south of the station identified low levels of contamination via high sensitivity gamma spectroscopy analysis.
l l
- Licensee analysis of offsite environmental air
! samples did not identify any releases. j
- The licensee pulled onsite environmental dosimeters for analysis and is awaiting results.
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l j' . j l 3 III. SAFETY SIGNIFICANCE l i i j
- The licensee estimated that a maximum of 25 l gallons of steam and water could have been
! released from the SPV. The liquid contained about 85 millicuries of mixed corrosion products. [ i )
- Although portions of the site's protected area exhibited detectable levels of contamination, l
i whole body counting of potentially affected l workers did not identify any instances of personnel intake of radioactive material. i
- Use of high sensitivity portal monitoring did not identify any significant personnel contamination. . l l
One jacket, with low level contamination was identified. The jacket did not leave the site.
- Personnel exititg the station were monitored via l portal monitors. Surveys of personnel vehicles
- and clothing returned to the station did not
! identify detectable contamination. i
- On-site low level radioactive contamination, was
- promptly posted, secured and cleaned-up as I appropriate and contingency plans were l implemented to secure low level ground deposited j contamination to prevent its release via rain.
i i i
Safety Significance (Contd)
- After it was identified that a release had occurred, there was excellent evaluation of the impact of the release on the environment and continued operations. The licensee also performed excellent post event analysis and review.
The Root Cause Analysis and Significant Event Team compositions were appropriate. The licensee focused on appropriate safety / programmatic issues.
- There was good use of analytical tools
- ' Preliminary NRC review indicates recommended corrective actions addressed roots causes.
i
- The DSE was shut down and re-start will not occur pending NRC review of licensee
- assessments and corrective actions. The licensee is also continuing to review other evaporators and operations onsite to preclude a similar occurrence.
4 \ ! . i
- 1 l I
! l i OVERALL CONCLUSION I i i , l i l
- The safe operation of the reactor was not affected !
{ and the release did not significantly impact on j shift licensee pei aonnel. 1
- The release of radioactive contamination from the
! DSE had little radiological impact on the public ! and environment (off site). No release limits were i exceeded. A teasonable worst case analyses did ! not identify any significant potential offsite ! impacts. . I l 4 i i l i i i 1
IV. PROGRAMMATIC ISSUES A. Event Response - General Conclusions
- Initial response was appropriate in that multiple indications were evaluated and appropriate procedures were entered, but incorrect diagnoses were made to explain conflicting indications.
Operations and radiation protection personnel relied on the SPV monitor and samples and incorrectly concluded that a release had not occurred.
- Management attention and direction was focused ;
on preventing a future release (liquid drying out ; in duct).
- The licensee was slow to identify the occurrence of a release due to weaknesses in communications and integrated assessment of incoming information. As a result the licensee was slow to take actions to secure potential sources and to take appropriate actions to prevent potential further spread of' contamination.
- Procedures provided limited guidance for 3 response to an onsite contamination event.
l l B. Engineering - General Conclusions i l
- The licensee did not have an adequate i understanding of the design basis of the DSE. l l
l The licensee did not perform an adequate design review of the DSE and the South Plant Vent emuent monitoring system to support operation of the DSE.
- The Radiation Emuent Monitoring System was not capable of detecting emuent releases (in the form released) from the Decontamination Solution Evaporator.
C. Operations and Operations Procedures- General Conclusions
- The DSE was not operated in accordance with design basis or Final Safety Analysis Report commitments as follows.
Established system operating level set points / limits / alarms were set non-conservatively. The system was operated in " semi-continuous" mode versus " batch" mode. No influent or efDuent sampling performed on routine basis The processing of floor drain water was not evaluated. 3 Automatic control ihnctions were overridden to establish flow paths.
- - . l 1 .
3
! Operations and Operating Procedures (Contd) i j
- The operating procedures for DSE were j inadequate. For example, the alarm response
! procedure (ARP) for high differential pressure i across the demister provided no direction for l i spraying the demister.
- There was a lack of clear understanding of i
j system operation by system operating personnel. 1 There was a belief that the DSE could not I i cause a radioactive release and it was not j recognized that prolonged spraying, or ! j spraying while steaming, could cause a j pressure transient that could result in the ! release. 1 i l System operating personnel did not have a ! clear understanding of system interlocks and l automatic fhnctions. i i j
- There was minimal monitoring of system
! operation i i 4 i
V.
SUMMARY
OF AREAS l FOR NRC FOLLOWUP AND POTENTIAL l ENFORCEMENT 1
- 1. The design review of the evaporator was 1 inadequate. i
- 2. There were no adequate approved Operating procedures for the DSE.
- 3. The surveying and monitoring of DSE effluents was not adequate to detect the release.
- 4. Alarm set point changes were not made in accordance with approved procedures.
- 5. There is information that an individual may have alarmed the portal monitor and may have left the station without re-checking. This matter is continuing to be reviewed.
- 6. Workers were not informed of the release and on-site contamination once it was identified.
i The Honorable Frank R. Lautenberg On June 9,1995 the NRC issued the licensee a Confirmatory Action letter acknowledging the licensee's commitment to maintain the Salem units in a shutdown condition pending completion of specific actions to be accomplished by the licensee. These commitments include a review of the circumstances leading to the Salem Unit 2 reactor trip, a special review of long-standing equipment operability issues, a meeting with the NRC to gain agreement on scope and detail of the licensee's plan for an operational readiness review in support of startup of each Salem unit, and the execution of the operational readiness review. NRC staff has been in contact with Mr. Pettit and provided him with a copy of the Hope Creek Inspection Report referenced above. During the Hope Creek Enforcement Conference on June 16, 1995, the staff met with him, explained the NRC enforcement process and provided assurance that the NRC would continue to actively monitor the Hope Creek and Salem facilities. We trust that this letter is responsive to your request. Please contact me if l you have further questions or require additional information. i Sincerely, Original signedW James M.Ta# James M. Taylor i Executive Director for Operations
Enclosure:
Letter to L. Eliason, PSE&G, from R. Cooper, NRC, Region I, dated May 30, 1995, transmitting Inspection Report No. 50-354/95-05
*Previously Concurred 0FFICE PDI-2/LA PDI-2/PM PDI-2/PM RGN-I* TECH ED*
NAME M0'Brien CPoslusny:rb DMoran JWhite T BCalure DATE g g5 06/29/95 g22/95 g 0FFICE PDI-2/D DRPE/D* ADP* NRR/D EDO / OCA NAME JStolz SVarga RZimmerman WRussell JTaybr 7 , DATE 06/29/95 6/22/95 06/29/95 06/29/95 //g/95 7/ 4/95' 0FFICIAL RECORD COPY DOCUMENT NAME: GT0348.REV
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- 1 i _. May 5, 1995 i i l i Mr. James Taylor
! Director
- Nuclear Regulatory Cossaission i
11555 Rockville Pike Rockville, Mn 20852 l ) 1
- Dear Mr. Taylors _
! I as writing onIbehalf of William Pettit, Vice-Commander of i Thurston Elmer Wood Post #198 located in Cape May Court House, j New Jersey. Mr. Pettit is concerned about the recent release of radiation at the Hope Creek Nuclear Generating Station in Lower
- Alloways creek Township. ,
As you know, the Hope Creek facility recentij experienced an accidental leak that contaminated several vehicles, including j ~ one which subsequently crossed state lines and was recovered in Delaware. Mr. Pettit reports that county officials were not i directly notified of this incident, nr. Pettit requests that the plant in question be monitored and the occurrence investigated. I have enclosed a copy of his correspondence for your review. i I would appreciate any information you can provide toj> L assist with Mr. PettiL's concerns. findings. Thank you for your attention to this intter.Please notify me of y 4-
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Sincerely, C ~ Enclosure N $ 6 M EDO --- 000348
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EDO Principal Correspondence Control FROM: DUE: 05/25/95 EDO CONTROL: 0000348 DOC DT: 05/05/95 FINAL REPLY: S2n. Frank R. Lautenberg TO: James Taylor FOR SIGNATURE OF : ** GRN ** CRC NO: Executive Director . ..- -- DESC: --
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ENCLOSES LETTER FROM WILLIAM N PETTIT, THURS Q . . %g - EIMER WOOD POST #198 RE RELEASE -OF, RADIATIQBk me, r'L .T Tpylof
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THURSTON ELMER WOOD POST #198
'. 57 Hand Avenue & Dias Creek Road Post Omce Box 577 Cape May Court House, New Jersey 08210 FOR GOD AND COUNTRY April 12,1995 Senator Frank Lautenberg 506 Senate Hart Building Washington DC 20510
Dear Senator Lautenberg:
4 Once again, on behalf of the officers and members of the Thurston Elmer Wood Post #198, I am writing to you because of our serious concern pertaining to the recent accidental release of radiation at the Hope Creek Nuclear Generating Station in Lower Alloways Creek Township. Over the last two years, I have written to the office of many elected officials in an effort to bring this matter to their attention. You have noted your concern and so had former Congressman Hughes but now that he has retired from office interest has waned. It may have to be up to you and your office to personally contact the Nuclear Regulatory Commission and deterime what is the problem at this station. As you will note from the copy of the enclosed news article, liquid radioactive materials escaped, contaminating several vehicles and sprayed on a truck that was then allowed to leave and go to Delaware. It has been reported that the truck may have left behind a trail of l radioisotopes as it headed over the Delaware Memorial Bridge. I am sure you will agree with me that this is shocking. Even more shocking ; was the reported fact that Cumberland County officials did not learn about the radiation release until they heard it on th2 noontime news. l This accident is not only a threat to Cape May County but to the ; neighboring counties of Atlantic and Cumberland and to the states of J Delaware, Maryland and Pennsylvania. Salem plant il has had a history of various problems. The plant must be monitored. Please do not let them wait until a disaster happens. We, the officers and members oF Post 10, and the citizens in this area - await the results of your findings. 1 William M. Pettit Vice-Commander AN ORGANIZATION OF WARTIME VETERANS SERVICING ALL VETERANS AND THEIR DEPENDENTS
Y 7-96 h 2. TFCSS i
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Hope CreekX-plant accidentally releases. radiation ! . .. ... .. e ' O Miterial described as 'radioa'ctive wastewater'is spewed into went through i a . chimney de- ~ The t$ck, owned by Air Prod . An NRC omelal said when ; i the air, some of it coating a truck that drives into Delaware.
, lii luid dried, there was a dust signed why atostack ventmonitor radioactive failed to gases, ucts,a companyin Creeks with Delaware City 5'of particu
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' ' and that supplies Hope ,
u "tl. on ear Wednesday morning....
- i. 3.,lf . . detect the release. ,, Ia' tory Com- hind a trail of radioisotopes as it 'other materi By RICHAliD DEGENER"u.~ ~ . , The Nucipar Regu stenwreer . poses no threat.to the public but inission also wants to know why a ' . headed over. the Delaware
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LOWER ALLOWAYS ' CREEK.qplant operstions, NRC omclalsf dioactive mmtrials allowedwasthe,,_,,.,,,.n,,- re- MemorialBridg& , M me .. .o, i . . . TOWNSHIP- : An acciderttal re 'said onThursday. . . to leave and ,,o to Delaware be-Imse of radiation at the Hope.. Chief among the questions is.-fc1 anybody knew it.was con- E Cumberland County officials say they should have been notifiec Creek Nuclear Generating' .Sta.:,'whyliquid rad.!oactive materials taminated. . , the radiation release in nearby Salern County. - Page A4.
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8< E DEEGQEC,CE b C as7 3 tion f;und was liss than 1 mil- siid in a statem nt that the truck n( i lirem per hour and NRC guide driver drove sway at 9:40 a.m. di i lines allow public exposure of Wednesday before the area of tri gn P p 100 millirems annually. contamination was known.
"The alarms we::t o!T before ju Dricks said it would take 100 i y hours of exposure " standing the truck len but we didn't know
[C1CdS@$ there with your tongue hanging the source or pathway. Then we mi looked at the truck log to see pe
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A NRC press release issued what trucks left the area," said tor raClat10D late in the day said testing on the . Camp. watchdog groups _ so: (Continued from Page All - roof of the plant near the stack Nuclear , and on adjacent vehicles found spent much of Thursday seeking answers. When the truck was tested in levels of 6 millirems per hour. PSE&G also owns the two The NRC is investigating the Delaware, it had radiation on itbut it isn't known how much it incident and has a five had when it leR the plant. Hope team resident at the plant, inspectors, a have come under fire from Creek officials said it is only threespeculation to for in plant operations. say it released ra- health physicist recentincidents. diation on public roadways. "We will look at whether any Hope Creek has an excellent "The Air Products truck wasCity, federal operating ' guidelines trackrecord. traced to Delaware "It's not Chernobyl but defi-Delaware, where very low levels were violated and how this hap- nitely some serious errors were of loose surface contamination pened,"saidDricks. The accident happened at made," said Michael Mariotte of were detected on the trailer.The about 12:30 a.m. Wednesday, said the N uclear information and Re-vehicle was decontaminated atthe NRCDelaware City location until Wednesday and Dricks, He stressed buttoitre-thatitis rare was not reporte the driver of the truck and an as- the sistant were checked and were evening because the amount o off site radiationlimits. lowable limits on site. "We expect the NRC to investi-nated." read an NRC statement. However, Dricks said when Neither the NRC nor the plantService PSE&G realized there was conta gate this and quite possibly fine operator, the Public mination off-site and it exceeded the utility at some point down the Electric & Gas Co., would say allowable limits, then the utility road. This !s a major league how much radioactive materialwas released. NRC officials are reported to the NRC within stressing that the contamination PSE&G four-hourtime period required. spokeswoman year said Mario is being cleaned up and does not Michaele Camp said the stack to one fatal cancer case in every endanger the public. NRC spokesman Victor Dricks alarm may not have gone off be- 285 people. Mario said they believe the only radia- cause the liquid came out in a the half-life for radiation tion that left the plant site was on short burst. Ultimately some oth ticles ofcesium is 30 year the truck that went to Delaware. er radiation monitors at theHe describ as"a very low level of radiation." some hot spots," PSE&G, whichsaid Camp. owns the plant an unscheduled release. Early in the day, Dricks said . .. . .
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[ County not told of Hope Creek radiation leak BgEILEEN s wnte' BENNE'IT the incident didn't pose a danger Salsm I and Salem Il reactors at to the public or personnel at the the site, the second-largest com-l I plant. mercial nuclear facility in the BRIDGETON - Cumberland Lookabaugh said although the country. County officials said they news media was alerted to the in-Freeholder Douglas Fisher learned about Wednesday's ra cident, Cumberland County of said he also wanted the NRC"to diation release from the Hope ficialswere not. give us both sides of the status of Creek nuclear plant on the noon- "We would have just been an Salem 1." extra layer of carbon paper," The SalemI nuclear plant,also time news.
"This is a communications 14okabaugh said, referring to located atLowerAllowaysCreek, problem," said Freeholder Di- PSE&G notifyingthecounty. has been plagued with numerous rectorJennifer Lookabaugh,who According to 140kabaugh, problems.
4 said she heard about the in PSE&G ometals said that county Wednesday's incident is the cident on a television broadcast. omeials weren't notified be- latest mishap at the troubled Lookabaugh was speaking at cause "It was a slight release" of Salem Nuclear Generating Sta-the frteholder board's agenda radiation. tion, which has come under in-meetingThursday. Regardless, Lookabaugh said tense scrutiny by federal regula-She said county omcials were she has asked for a meeting with tors. "We need to hear both sides," not notified when radiation es PSE&G omelais and omelais of caped frem the Hope Creek nu the federal Nuclear Regulatory Fisher seid. clear plant, contaminating sev- Commission. "We need to hear what PSE&G eral vehicles and a buildmg in "We don't want this (kind of says they're doing, and we need neighboring Salem Canty. news) to get out and then get big- to hear what the NRC says they Lookabaugh said officials for ger and bigger," Lookabaugh should be doing. We have to give Public Service Electric & Gas, said. our residents some level of com-which operates the plant, said PSE&G also operates the fort" i A %.a.hi .:.e s u .:s_- i - ^-- a e Am 5.s ,
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