ML20207E524

Advises That Written Testimony for 860716 Hearing Should Address Significance of Poor Mgt & Provide Subcommittee W/Description of NRC Problems to Cope W/Licensee Mgt Problems.Testimony & Response Requested by 860712

ML20207E524
Person / Time
Site:	Pilgrim
Issue date:	06/24/1986
From:	Markey E HOUSE OF REP., ENERGY & COMMERCE
To:	Palladino N NRC COMMISSION (OCM)
Shared Package
ML20207E430	List: ML20207E427 ML20207E524
References
NUDOCS 8607220362
Download: ML20207E524 (210)

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""u'.M o, 7gg i uw es t s COMMITTEE ON ENERGY AND COMMERCE WASHINGTON, DC 20515 4 June 24, 1986 The Honorable Nunzio J. Palladino Chairman U.S. Nuclear Regulatory Commission 1 1717 H Street, N.W.

Washington, D.C. 20555 J

Dear Mr. Chairman:

At the Subcommittee's May 22, 1986 hearing, the Commission discussed the significance of management problems at a number of the nation's commercial nuclear facilities. As has been previously communicated with your staff, the Subcommittee will further investigate this issue at a July 16, 1986 hearing at which the Commission's testimony is requested. The hearing will begin at 9:30 a.m. in a room to be announced.

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Your written testimony should address the significance of poor management for safety and provide the Subcommittee with a i description of NRC programs to cope with licensee management problems. Specifically requested is a description of the

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management and regulatory problems that NRC has identified in recent years at each of the 17 plants that were named by the Commission at the Subcommittee's hearing as having poor management In each case, a history of enforcement action, significant

! mishaps, and SALP ratings should be included in the requested

overview of troubled plants. Obviously, if there are other plants with similar problems that the Subcommittee should be aware of but were not mentioned at the last hearing, please incorporate them l into your testimony as well.

In addition to the above, the hearing will focus in significant part on problems at Boston Edison's Pilgrim nuclear reactor in Plymouth, Massachusetts. The NRC staff has already-provided the Subcommittee with a useful history of problems at l this facility. It would be helpful if your testimony could

! include an analysis of (1) what are the causes of Boston Edision's j management problems; (2) why management weaknesses have been a recurring problem for Pilgrim; and (3) whether NRC believes in retrospect that it has done all that it could and should have in regulating Pilgrim. The Subcommittee further requests any 1 internal NRC memoranda or documents produced by industry I

organizations such as the Institute for Nuclear Power Operations

] detailing management weaknesses at Pilgrim since January 1982, i when NRC issued a $550,000 civil penalty to Boston Edison.

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The Henorablo Nunzio J. Palladino June 24, 1986 l Page 2 .

l The Subcommittee also requests the Commission's response to the followings r

1. Previde five examples of significant mishaps at operating nuclear reactors since the 1979 accident at Three Mile Island that the Commission believes can be largely if not entirely attributed to management weaknesses within the licensee. In each I

case explain what actions the NRC and the licensee took to correct management problems and state how long it took for weaknesses to be corrected.

2. The NRC has promulgated regulations and guidances j concerning required training, experience and qualifications for reactor operators. Does the NRC have any similar requirements for the training, experience and qualifications for important -

management positions such as plant manager and vice president for nuclear power operations? If not, does the Commission believe it would be advisable to ,

consider adopting regulations or guidances in this j area?

5. What regulatory actions has the Commission taken to assure management improvements at each of the 17 f acilities identified as having management problems?

6. What are the lessons learned from NRC's Systematic Assessment of Licensee Performance program?

7. Members of the Subcommittee have criticized the .

NRC's failure to correct known management weaknesses 4 and design defects prior to their contributing to i the June 9, 1986 loss of feedwater accident at the Davis-Besse' nuclear reactor. The Subcommittee i requested that NRC conduct an internal investigation of-NRC's responsibility for the accident. Now that this investigation is complete, please inform the Subcommittee of what conclusions can be made and what changes have or will be made in NRC's management.

8. Although the Commission has variously concluded that the risk of a core melt accident could be as high as 12 or 45 percent in the next 20 years at a U.S. i plant, the NRC has informed the Subcommittee that l

this risk is deemed acceptable because of the ability of containment buildings to prevent a major I

The Honorablo Nunzio J. Pelltdino June"24, 1986 Page 3 ,

radioactive release. 731ven a core melt accident,

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what does the Commission believe is the maximum acceptable probability of a subsequent failure of the containment building in order to reach a finding that public health and cafety can and will be protected?

9. NRC's chief safety officer has reportedly told the industry that he is concerned about Mark 1 containment buildings because given a core melt accident they have a 90 percent chance of f ailure.

Please answer the'following: (a) is a 90 percent chance of failure in the event of a core meltdown an acceptable failure rate; (b) does the NRC believe that Pilgrim's containment building is more vulnerable to f ailure given a core melt accident than other types of containment buildings in use at other plants; (c) rank the 17 plants with management problems in descending order of the estimated containment failure rate; and (d) is NRC considering ~

any new requirements or backfits relating to l containment issues?

Please provide th Subcommittee with 25 copies of your testimony and respodse to questions by Friday, July 12, 1986. The requested documents concerning Pilgrim should also be provided by this deadline. Please bring an additional 75 copies of your testimony and response to questions to the hearing room the morning of the hearing.

In advance, thank you for your cooperation in keeping the Subcommittee fully and currently informed about these important issues.

Sincerely,

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Edward J. Marke Chairman I

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ATTACHMENTS TO TESTIMONY OF UNITED STATES NUCLEAR REGULATORY COMMISSION July 16, 1986 U.S. House of Representatives Subcommittee on Energy Conservation and Power of the Committee on Energy and Commerce The following attachments provide responses to subcommittee questions.

Information concerning management and regulatory problems, enforcement and operational history, and SALP ratings for problem plants are provided as part of the responses to Question 45. In this regard, information for the problem plants identified by the Commission at the May 22, 1986 hearing is provided with a few exceptions. After careful review and discussion by senior staff management, it was determined that Peach Bottom should have been on the list of problem plants mentioned by the Commission on May 22.

In addition, Oyster Creek and the D.C. Cook units should be removed from the list. As a result of these changes, the attachments in the response to Question 5 discuss the status for 16 plants at 10 sites rather than the 17 facilities mentioned in the Subcommittee Question 5.

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QUESTION 1.~~

Provide five examples of significant mishaps at operating nuclear reactors since the 1979 accident

! at Three Mile Island that the Commission believes can be largely if not entirely. attributed to manage-I ment weaknesses within the licensee. In each case explain what actions the NRC and the licensee took to correct management problems and state how long it took for weaknesses to be corrected.

ANSWER.

Five examples of significant events attributed to management weaknesses include events that occurred at Browns Ferry (Alabama),

Salem (New Jersey), Davis Besse (Ohio), Ft. St. Vrain (Colorado),

and Rancho Seco (California). The first four have been reported to Congress in NUREG-0090 as Abnormal Occurrences. The Rancho Seco event is under consideration for inclusion in a forthcoming

. report. These events illustrate the importance of utility management to the maintenance and operation of their plants. The events and NRC and Utility response are described below.

1 Since the TMI accident there has been a heightened awareness at the NRC of the importance of utility management, and progressively greater NRC resources and attention have been expended in this area. Efforts to appraise and improve utility management will i

continue.

QUESTION 1. (Continued) _~

SIGNIFICANT MISHAPS l

BROWNS FERRY REACTOR VESSEL LEVEL INDICATION DISCREPANCIES (1984/1985)

During a Browns Ferry Unit'3 reactor startup on November 20, 1984, one of three narrow range reactor vessel water level instruments was reading about 11 inches lower than the redundant channels.

Reactor startup was delayed for several hours, and the water level discrepancy corrected itself and the startup was resumed. During a Unit 3 reactor startup on February 13, 1985, the same vessel water level instruments were similarly providing inconsistent readings. Relying on the erroneous instruments, reactor operators allowed the vessel level to drop until a reactor protection system half scram was signalled in the control room. The vessel level was raised to clear the half scram and the startup continued without determining the cause of the level instrument problem. It was only after NRC management involvement following the February 13 event that meaningful corrective action was initiated to determine the root cause of vessel level instrument problems.

The vessel level instrument problems were determined to be caused by a malfunctioning instrument reference leg.

The event resulted from a failure to take corrective action when a similar reactor vessel water level instrument problem occurred on November 20, 1984. If effective corrective actions had been taken

QUESTION 1. (Continued) , at that tiie the event in February could have been prevented.

Contributing causes were a lack of knowledge by the operators due to a deficient training program and communicatiors and coordination problems between operators, mai.ntenance, and management.

CORRECTIVE ACTIONS The above are the most significant operating events over a several'

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year period at Browns Ferry. As a result of the failure to obtain sufficient improvement in operating plant and general performance 1

under an escalated enforcement action, in early 1984 TVA was required to submit written plans to upgrade performance at Browns Ferry. The Regulatory Performance Improvement Program (RPIP) was confirmed by an order dated July 13, 1984. TVA assigned additional specialists to assist the site in specific areas, hired consultants, and completed organizational changes to strengthen management controls as part of the RPIP; however, performance failed to improve as noted above. The Regional Administrator had i

additional discussions with the members of the TVA Board in early 1985. Following the reactor water level event, on March 8, 1985, the Regional Administrator requested the licensee to justify continued operation of the Browns Ferry units. After reviewing l l

the details of the event, TVA ordered Unit 3 shutdown on March 9, i 1985. Unit I was shutdown March 19 (Unit 2 was shutdown for refueling) due to inoperability of the high pressure coolant injection system. The licensee agreed to not restart any unit I

QUESTION 1. (Continued)  :

without NRC concurrence. On July 3, 1985, the Executive Director for Operation sent a letter to the Chairman of the TVA Board of Directors about the sustained and consistent history of poor I

performance.

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SUMMARY

U TVA continues to receive a high level of NRC attention. A senior

, management team is coordinating the NRC inspection efforts and the staff review of the acceptability of TVA corrective actions related to their nuclear facilities. ,

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l DAVIS BESSF-LOSS OF FEEDWATER

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4 j On June 9, 1985, the Davis-Besse Nuclear Power Station experienced  ;

a loss-of-main feedwater transient. A number of equipment I malfunctions and an operator error occurred during the course of 1

I this transient, c'esulting in a temporary loss of all feedwater. l i

1 j An NRC Incident Investigation Team investigated the circumstances of this event and concluded that the underlying causes of the 1

! June 9, 1985 event were the licensee's lack of attention to detail

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2 in the case of plant equipment; the licensee's poor history of

performing troubleshooting; inadequate maintenance and testing of l

l equipment, and evaluating operating experience related to equip-ment in a superficial manner. This resulted in a failure to i

identify and correct root causes of problems. Engineering design i

i and analysis effort to address equipment problems had not been '

i effectively utilized. Equipment problems were addressed and j

resolved only to a level of minimum compliance with NRC regulatory j requirements.

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l The NRC believes that the lack of a strong licensee management team was the cause of the equipment malfunctions which occurred l j  !

! during the June 9 event. As outlined in the answers to earlier

! subcommittee questions, the NRC believes the root causes of

! licensee management problems were that the corporate and plant 1

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QUESTION 1. (Continued) ,

management were not an effective team in identifying problems or in solving problems once they had been identified; that the Chief Executive Officer was not sufficiently involved in Davis-Besse i

operational activities; that management was' ineffective in implementing programs for resolving performance deficiencies; and that there was a lack of corporate support to the nuclear mission particularly in procurement and personnel matters.

CORRECTIVE ACTION

In addition to dispatching an Incident Investigation Team to .

investigate the June 9 incident on August 14, 1985 Region III issued a 10 CFR 50.54(f) letter. In response to this letter the licensee developed a Course of Action program to address the NRC's concerns. The Course of Action report describes (1) the programmatic actions Toledo Edison Company has taken to improve its management structure, particularly with respect to plant ,

maintenance; (2) the results of investigations into the causes of malfunctions of equipment and the corrective actions to be taken; (3) other procedural and system modifications and improvements made to minimize the possibility of a recurrence of a similar loss of feedwater; and (4) the program for review of systems important to safe operation of the facility to uncover problems that could potentially interfere with the ability of the systems to perform their intended functions and to identify the corrective actions necessary to remedy any problems.

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QUESTION _1. (Continued)  ;

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SUMMARY

Implementation of this program is still in progress; however, the initial results have been encouraging. Extensive NRC oversight of this activity is ongoing and will continue through plant restart.

The NRC has also taken a number of steps to improve upon its inspection process. These steps include the development of Master Inspection Plans to focus resources on poor performance identified through the SALP process or other means, more detailed supervisory involvement in detailed inspection planning, and a reemphasis of evaluation of licensee performance rather than licensee programs in the inspection process.

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QUESTION 1. (Continued) FORT ST. VRdIN FAILURE OF SIX CONTROL R00 PAIRS TO AUTOMATICALLY INSERT ON A REACTOR TRIP -

In June, 1984, there was an event at Fort St. Vrain in which six of 37 control rod pairs failed to insert automatically into the reactor upon a reactor trip signal. As a result of this occurrence, a special assessment of Fort St. Vrain operation was ordered by the Director, NRR. Because Fort St. Vrain management deficiencies had become evident in the 1982-1984 time frame as a .

result of NRC systematic assessment of licensee performance (SALP), which indicated a progressive decline in the level of performance in operations, management control, licensing, and other areas, the scope of the assessment included a review of management oversight of nuclear activities. The assessment I confirmed the findings of the June 1984 SALP report concerning management deficiencies.

CORRECTIVE ACTIONS As a result of the findings of the NRC assessment, the licensee arranged for a third party (independent) audit of management structure and practices relative to the operation of FSV. The 4

licensee contracted with the NUS corporaton to perform this audit.

A meeting was held between the NRC, the licensee, and NUS representatives in November, 1984 to discuss general assessment of

QUESTION 1. (Continued) management ~ problems and insure that the audit would address the broad issue of management structure and competence as well as the control rod event.

The NUS report concluded that the unique design of Fort St. Vrain (a gas cooled reactor) had led to a management mindset of isolation from the rest of.the industry, because of the industry's light water reactor orientation, and a belief that some NRC regulations are not applicable to their plant. As a result of this third party review the licensee developed a Performance Enhancement Program (called " PEP".) The PEP Program was implemented in March, 1985. The PEP consists of a number of specific tasks for i mproving plant performance and responsiveness to NRC initiatives. It is a long-range program which will continue over several years. PEP includes a " Total Responsibility Management" program including individual manager assessment. The licensee has made significant progress on its originally defined

PEP tasks and has defined new tasks as the need for them has i become apparent.

SUMMARY

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The most recent SALP (for the period ending May 6, 1986),

ir,dicated continued weak performance and the need for continued NRC and licensee management oversicht. However, uptrends were apparent in several areas. NRC staff is following the progress of the PEP Program through quarterly briefings. NRC inspection 4

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QUESTION 1. (Continued) efforts have been redirected and intensified to address the problem areas identified by the SALP Program.

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QUESTION 10 (Continued) -

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RANCHO SECO (1985)

LOSS OF INTEGRATED CONTROL SYSTEM POWER AT RANCHO SECO On December 26, 1985, Rancho Seco Nuclear Generating Station, a Babcock & Wilcox (BW) designed pressurized water reactor, operated by the Sacramento Municipal Utility District (SMUD), experienced a loss of dc power within the integrated control system (ICS) while the plant was operating at 76 percent power. Following the loss of ICS dc power, the reactor tripped on high reactor coolant system (RCS) pressure followed by a rapid overcooling transient ,

and automatic initiation of the safety features actuation system on low RCS pressure. The overcooling transient continued until ICS de power was restored 26 minutes af ter its loss.

The fundamental causes for this transient were. design weaknesses and vulnerabilities in the ICS and in the equipment controlled by that system. These weaknesses and vulnerabilities were not adequately compensated by other design features, plant procedures or operator training. These weaknesses ard vulnerabilities were largely known by the licensee by virtue of a number of precursor events and through related analyses and studies. Yet, adequate plant modifications were not made so that this event would be improbable, or so that its course or consequences would be signi-ficantly altered. This failure is attributed to management weakness at-SMUD.

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QUESTION 1. (Continued) 12 -

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CORRECTIVE-#CTIONS On December 26, 1985, the Regional Administrator of the NRC Regiori V Office forwarded two Confirmatory Action L,etters to the licensee confirming that the licensee would perform a root cause analysis prior to return to power and would not perform,any additional work on equipment that malfunct.ioned during the event until the NRC could evaluate the event.

On December 27, 1985, an NRC Augmented Inspection-Team (AIT) was sent to the site by the Reg 1,onal. Administrator and started trans-cribed personnel interviews on December 28. On D'cember e 31, 198'5, the responsibility for the incident investigation was expanded to a special NRC Incident Investigation Team by the NRC Executive Director for Operations (ED0). The results of the Team's investi-gation are contained in NUREG-1195. Problems identified included issues specific to Rancho Seco and several possible generic issues. The NRC ED0 has directed program managers to conduct further generic and plant specific follow-up actions. Development of NRC plant specific action plans commencid while the IIT was on-site in January 1986, and have been exp'anded subsequently.

The NRC ED0 has also considered this event in a January 24, 1986 request to the B&W Owners; Group (B&WOG) to.obtain an industry effort to assess the genericyaspects of plant responses to,tcansi-ents, and methods of redu'ction of the number of plant' trips. In a meeting with the Staff on April 8, 1986, the B&WOG presented their 5

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QUESTION 1. (Continued) programp[anforreducingthereactortripfrequencyandimproving the transient response of B&W-designed plants. The NRR Staff is currently reviewing this plan.

In addition to addressing those issues which have arisen directly as a result of the December 26, 1985 cooldown transient, the NRC Region V Office has reeval'uated the status of prior Rancho Seco open inspection findings to identify matters which should be resolved prior to restart of the plant. 1he licensee and NRR have included these in restart plans. Also, the NRC Staff has encouraged the licensee to reexamine the status of all critical, plant systems to assure readiness for operation and maximum relia-bility, so that operation of the plant may be continued with a low probability.of disruption from internal causes. These efforts will be reviewed by NRC' inspectors.

SUMMARY

The consistent NRC regulatory approach to the SMUD management problems has been heavy regional inspection and manacement

, involvement to insist on rising standards for SMUD. Management meetings, enforcement meetings, civil penalties, outside management audits, 50.54(f) letters, and direct ED0/ Commission involvement have occurred in a steady escalation throughout this period. The result has been a perception that SMUD has improved organizationally in most areas. However, Rancho Seco has been shut down to such an extent that the effectiveness of the changes

QUESTION 1. (Continued) 14 -

, cannot be definitely known. Mcreover, most senior managers in the SMUD nuclear organization are new to their jobs, and are untested in them. Currently, SMUD is heavily reliant on interim contractor managers (from the Management Assistance Corporation). These people appear competent, but are not expected to remain at SMUD more than a year or two. On July 1, 1986 the General Manager for SMUD resigned in conflict with the elected Board of Directors of SMUD. He had been installed only ten months previously as part of a SMUD program to improve their performance.

Future NRC actions will hinge upon the thoroughness of the restart program SMUD intends to submit to the NRC in July, 1986 and the successful permanent restaffing at SMUD.

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QUESTION 1. (Continued) -

SALEM (198I1 TRIP BREAKER (ATWS) EVENT On February 22, and February 25, 1983 both reactor trip breakers at Salem Unit 1 failed to open automatically on receipt of valid trip signals from the Reactor Protection System. The causes of the breaker failures include lack of lubrication, dust and dirt, frequent operation, and wear. Additional contributors included issues such as safety classification, vendor recommendations, maintenance practices, quality assurance, and post-maintenance testing.

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CORRECTIVE ACTIONS As revealed by intensive on-site review of the events, several meetings with the licensee, and licensee appearance before the Commission itself, the problems associated with the reactor trip breakers appeared to be rooted in basic management capability and attendant performance deficiencies. In addition to escalated enforcement in the torm of a Civil Penalty in the amount of

$850,000, an Order was issued on May 6, 1983. The Order listed a l 1

number of specific items to be completed which related to the reliability of reactor trip breakers and other safety related equipment. In addition, the licensee was required to undergo a I

QUESTION 1. (Continued) third party ~ evaluation to determine organizational weaknesses and to develop corrective actions.

The result of the third party evaluation was.a comprehensive Action Plan addressing a number of organizational features which needed strengthening or modification. Work on these items encompassed about one and one half years. During this time, senior NRC Region I and NRR managers and staff met with the licensee about every other month to discuss progress and lessons learned from the on-going changes and evaluation of those changes.

In the course of +.hese discussions the NRC expressed dissatisfaction with the slow progress of the Action Plan and its focus on meeting administrative milestones and developing procedures rather than developing changes with more visible results. Subseouently, the Executive Director for Operations and senior NRC Regional and Headquarters Managers met with the President and a member of the Board of Directors to discuss the specific issue of leadership. In response, the licensee made major senior management changes in addition to the action plan to address basic changes in attitudes toward activities at the Salem site. One of these was the on-site Vice President. The change in the Vice-President in early 1985, a nuclear-experienced individual from outside the utility's organization, resulted in new and more effective approaches. Rather than dealing in a reactive manner to identified problems, new philosophies and management style

QUESTION 1. (Continued) .

provided a ~91sible change in attitudes. The focus was shifted

away from tracking of the Action Plan's milestones.

SUMMARY

The visible results include; a number of personnel changes, an improved safety attitude at all levels, more consistency in operations, reduction in the number of Licensee Event Reports, a more conservative approach in solving problems, an improving trend in the annual Systematic Assessment of Licensee Performance (SALP), and a reduced number of violation.

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The NRC has promulgated regulations and guidances

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QUESTI0S~2.

concerning required training, experience and qualifications for reactor operators. Does the NRC have any similar requirements for the training, experience and qualifications for important management positions such as plant manager and vice president for nuclear power operations? If not, does the Commission believe it would be advisable to consider adopting regulations or guidances in this area?

ANSWER.

The NRC does not have specific requirements for the training, experience and qualifications for important management positions such as plant manager and vice president responsible l

i for the operation of nuclear power facilities. The NRC does j provide guidance on personnel qualifications through a variety of documents described in detail below. This guidance, however, is generally focused on the personnel required to operate the plant through the plant manager. It does not

normally address corporate management.

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QUESTION 2.-(Continued) ~~

The NRC is not currently considering adopting regulations or guidance which would specify standards for upper level management training, experience, or qualifications. Instead, the NRC is developing methods to assess the management performance and effectiveness. A summary of these proposals is also reviewed below.

The Code of Federal Regulations, Part 50, requires applicants i

for licenses to provide, i n part:

- Plans for organization, training of personnel, and conduct of operations--10 CFR 50.34(a)(6);

- Organizational structure, responsibilities and authorities, and personnel qualifications requirements--10 CFR 50.34(b)(6)(i);

1 - Technical qualifications of the applicant--10 CFR 50.34(b)(7).

I The Standard Review Plan (SRP), Section 13.1'.1, " Management and

! Technical Support Organization," and Sections 13.1.2-13.1.3,

" Operating Organization," specify that the NRC will review the licensee's organization and technical capabilities of those personnel. Regulatory Guide 1.8, " Personnel Selection and Training," describes a method acceptable to the NRC staff for complying with Commission regulations regarding training and i

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qualifications of personnel. Regulatory Guide 1.8 also endorses ANSI /ANS 3.1-1981, "American National Standard for Selection, Qualification, and Training of Personnel for Nuclear Power Plants."

ANSI /ANS 3.1 specifies the following minimum education and experience for the plant manager:

- Bachelor degree in engineering or related science;

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- Six years total power plant experience; and .

- A Senior Operator License (or equivalent training).

t These documents provide the guidance for the NRC to review the technical qualifications of utility management and the plant manager. -

As directed by the Commission's " Policy and Planning Guidance, i 1986," NUREG-0885, Issue 5, the staff is moving toward

. performance-based rather than prescriptive regulation. As a result, new regulations involving management and organization have been deferred. In place of staff activity to develop ,

regulations, the staff is focusing on actual management performance and effectiveness through its program for the l

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OUESTION 2 (Continued)  !

" Systematic Assessment of Licensee Performance," (SALP). The SALP process assesses plant-specific performance for management issues and results in appropriate action being taken when i t is indicated. While the staff can assess the technical capabilities of management personnel, management competence is a complex issue which is not amenable to generic solutions.

The SALP process togeth'er with periodic senior NRC management reviews will provide the means to identify poor management performance. In addition, INP0 is developing training guidelines for the plant manager position (similar to other guides). INP0 is also starting a training course for ,

prospective plant managers, expected to begin in the Fall of 1986.

Commissioner Asselstine adds:

Although the SALP process and the type of plant operation performance indicators being developed by the industry and the ,

NRC can identify the symptoms of poor management performance, they often do not i dentify the nature and root causes of management deficiencies. They also do not provide necessary early identification of management problems before the problems result i n a serious deterioration in plant performance. Given the critical importance of good management to safe and reliable plant operations, NRC should be developing indicators to

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identify deficient management practices in nuclear power plant ,

operations. The Commission should also reconsider the need for l l

, 4 specific qualifications for senior nuclear managers in such key posts as nuclear vice president and plant manager,

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QUESTION 5.' What regulatory actions has the Commission taken to assure management improvements at each of the 17 facilities identified as having management problems?

ANSWER, I

j The following material addresses management and regulatory problems, significant events, enforcement and other regulatory

.i actions, and SALP ratings for the following facilities:

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Pilgrim l

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• Peach Bottom

Browns Ferry Sequoyah

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't PILGRIM As noted in the Subcccmittee Chairman's letter of June 24, 1986, the NRC staff has already provided the Subcommittee with a history of problems at this facility. This attachment provides an analysis of management performance and addresses the questions raised in the Subcommittee Chairman's letter.

QUESTION. What are the causes of Boston Edison's management problems and why have management weaknesses been a recurring problem for Pilgrim?

ANSWER.

NRC has identified symptoms of Boston Edison's management weaknesses through inspections, evaluations, and assessments. The SALP process attempts to integrate both positive and negative indicators of performance to better understand the reasons for it. As such, SALP is not an enforcement tool but is one of the ways we attempt to predict the nature of future performance. Based on the SALP review of BECo's performance during 1985, a recurrent theme was

! noted in the evaluation of the individual areas: improvements were noted in '

plant hardware but inadequacies existed in the performance of individuals (i.e., supervisors, managers and workers) relative to staffing, planning, 1

coordination and control over work activities. A subsequent in-depth on-site team evaluation reaffirmed this concern by the existence of the following:

(1) incomplete staffirg, in particular operations and key mid-level supervisory personnel; (2) a prevailing view in the organization that the improvements made to-date have corrected the problems; (3) reluctance, by management, to acknowledge some problems identified by the NRC; and (4) dependence on third parties to identify problems rather than implementing an effective program for self-identification of weaknesses, l In reflecting on these observations, we believe that BECo's management problems include a weakness in corporate policies. Frcm a historical perspective some general comments can be made:

(1) It was apparent to BEco management that successful operation at Pilgrim meant compliance with NRC regulations. The standards and goals were established in light nf the problems experienced in 1981. The physical condition of the facility has been dramatically improved over the years.

However, there was no clear comitment to surpass minimum requirements.

(2) Individual managers and supervisors were not held accountable for timely resolution of problems.

(3) There has been a reluctance to critically conduct self-evaluations or to address potential problems until the consequences were made self-evident.

~

In light of-their performance over the years, it was clear that BEco could react to serious problems and deal with them once they were identified and defined. However, it was the dependence on NRC oversight and the inability to be proactive that culminated in the critical reports issued earlier this year. These indicators reflected a lack of understanding of what " excellence" in performance means and this resulted in erroneous beliefs throughout the organization that success had been achieved. The industry and NRC were expecting more.

Consequently, it was through the SALP process that the NRC staff identified a deteriorating situation. If left uncorrected it is clear that a more serious situation could have evolved and stronger NRC enforcement actions would have been required.

The reactive process ~that Boston Edison has evidenced in the past has been highlighted to them by the NRC. Boston Edison has submitted a plan which suggests that they understand the problem and are taking action to address it.

CUESTION. Does the NRC believe that it has done all that it could have, or should have in regulating Pilgrim?

ANSWER.

It can always be argued that more could be done, however, the NRC has been aggressive in its regulation of the Pilgrim facility. The NRC has not allowed Pilgrim's performance to degrade to the point where there are clear violations of NRC requirements, as was the case in 1981. The SALP process has provided a strong, precautionary warning that is being heeded. The performance trend must and will be reversed. In 1982, following issuance of a $550,000 civil penalty for violations of NRC requirements, the NRC issued an order that required BECo to submit to the NRC a comprehensive plan to address problems that had been identified at the plant. The order required that the plan include (1) an independent appraisal of site and corporate management, (2) recommendation for improvements in management controls and oversight, and (3) a review of previous safety related activities to evaluate compliance with NRC requirements. BECo took several actions in response to the NRC order. These included a reorgani-zation of corporate management, initiation of performance improvement program, and implementation of physical equipment upgrades. The NRC held management meetings with BEco approximately every six weeks until September 1984 to monitor progress of this improvement program.

In addition to those activities related tio the January 1982 Order, NRC has given high inspection priority to Pilgrim and taken other regulatory actions when it was deemed appropriate. Since January 1982, over 192 inspections representing over 16,000 inspections hours have been expended at Pilgrim.

This is approximately 50", more inspection hours than expended at other similar plants in the Northeast. For the majority of the time since 1980 the NRC has had two Resident Inspectors at Pilgrim even though most single unit sites are normally manned with one Resident. Since January 1982 the NRC has had eight management meetings with Pilgrim, excluding those related to the performance improvement program; seven enforcement conferences have been held; three confirmatory action letters have been issued; and three SALP 2-

1 evaluations performed. Most recently, the NRC has conducted a special diagnostic team inspection, performed an Augmented Team Inspection, and has temporarily assigned a third Resident Inspector to the site. The kinds of problems noted in the recent NRC reports, however, are not readily identified solely through the inspection process. :t requires a comprehersive evaluation on the part of managers, supervisors and staff collectively to reach such far reaching conclusions. We have obtained sufficient information through our inspection program to allow NRC managers to do what has been done at Pilgrim.

A review of the above record clearly indicates that the NRC has given high priority to Pilgrim and has conducted an extensive inspection program given the available rescurces. Further, the NRC program, including a proactive SALP process, is identifying problems for which regulator.v and enforcement actions are being taken in a timely fashion to ensure the plant will not be operated in an unsafe condition.

Furthermore, the recently more active role of senior company officials such as the President, Mr. Sweeney, in personally becoming involved with plant management and in initiating strong actions to strengthen management staffing with new and experienced people gives confidence that the corporate philosophy has been redefined and a new attitude towards excellence is evolving. .

I i

3-

PEACH BOTTOM

Background

Peach Bottom Atomic Power Station, Units 2 and 3 are 3,293 megawatts (MW) thermal,1055 MW electrical, General Electric-Boiling, Water Reactor Mark I units operated by Philadelphia Electric Company (PECo) and located on the Susquehanna River, 19 miles south of Lancaster, in York County, Pennsylvania.

Unit 2 operating license (0L) was issued October 25, 1973 and was declared commercial July 5, 1974, Unit 3 OL was issued July 2, 1974 and was declared commercial December 23, 1974. The units are jointly owned by PECo (42.49%),

Public Service Electric & Gas Company (42.49%), Atlantic Electric Company (7.51%) and Delmarva Power and Light Company (7.51%).

Sumary of Management Problems and Recent Operating History As noted in the recent SALP and considering historical SALP results, the Peach

] Bottom facility has not shown performance improvements, and in a few areas

]

performance has deteriorated. In contrast, the recently licensed Limerick facility received favorable SALP reports for essentially the same time period.

j The Peach Bottom facility has been undergoing extensive modifications and

< improvements. During the SALP period, Unit 2 conducted a 15 month outage to

! replace recirculation system piping and Unit 3 started a eight month outage i to conduct repairs to recirculation system piping. Refueling was conducted during both outages.

A recent problem which occurred after the SALP assessment period resulted in a $200,000 proposed civil penalty. The incident involved inadequacies on the part of operators in the startup of Unit 3 on March 18, 1986. These inadequacies involved personnel errors by four licensed individuals. Based on prior

+ enforcement actions in 1984 and 1985, and considering the SALP results, the NRC staff viewed these problems as being indicative of a lack of management involvement in and attention to station activities to assure that station personnel respect, understand the need for, and adhere to company policies

, and procedures. In the March 18, 1986 incident this was exhibited by

! inattention to detail, failure to adhere to procedural requirements, and a generally complacent attitude toward proper performance of duties.

The licensee's response to the Notice of Violation has not yet been received.

! Although the physical conditien of the plant continues to be improved, it is the occurrence of such sporadic mishaps that led the staff to express dissatisfaction, through the SALP, with the management of Peach Bottom.

A forthcoming management meeting with the licensee to discuss the staff's views and perceptions was scheduled for Friday, July 11, 1986. A subsequent meeting between senior corporate executives and the NRC's Executive Director for Operations will also be held to further review the situation. In this regard we view the SALP process as proactive in identifying potentially adverse situations or trends before they result in more serious events or incidents.

I As such, there has not been a history of major hardware deficiencies attributable

! to management problems. There are favorable coments and findings also noted in the SALP. However, it is the staff's perception that corporate management's attention has in the past few years been diverted to the construction and

~

startup of Limerick; this has allowed some poor practices and attitudes to develop at Peach Bottom. Consequently, the management problems at Peach Bottom will be addressed through NRC meetings with senior licensee executives and their effectiveness will be monitored through our on-site efforts.

Significant Event Chronology .

June 1980 Management meeting to discuss the results of the SALP for the period May 1979 to May.1980.

March 1981 Management meeting held at licensee's request to discuss licensee plans for improving operational safety and performance.

l April 1981 Immediate Action Letter (81-19) corrective actions regarding isolation of three drywell pressure transmitters (Inspection 50-277/81-07 and 50-278/81-09). A severity level IV Notice of Violation was issued.

May 1981 Escalated enforcement (severity level III, no civil penalty) resulting from violations of radwaste transportation in November 1980. (EA 81-31 and NRC Inspection 50-277/80-36; .

, 50-278/80-29).

September 1981 Management meeting to discuss the results of the SALP for the period July 1980 to June 1981.

December 1981 Confirmatory action letter dated December 24, 1981, regarding planned corrective actions on significant findings identified in the NRC Emergency Preparedness Team inspection on December 7 through 17, 1981.

March 1982 Enforcement Conference on March 18, 1982, regarding radioactive material transportation. (NRC Inspection 50-277,278/82-05).

A severity level IV Notice of Violation was issued.

July 1982 Enforcement Conference at NRC Region I Office July 22, 1982, regarding numerous radiation protection violations and a violation of primary containrrent (NRC Inspections 50-277/82-10, 11 and 50-278/82-10, 11).

J,uly 1982 Management meeting to discuss the results of the SALP for the period July 1981 to June 1982.

January 1983 Enforcement Conference at NRC Region I Office, January 18, 1983, regarding plant operations in the area of valve positioning errors that resulted in safety systems out of service and violations of containment integrity. (NRC Inspection 50-277,278/83-03).

March 1983 Notice of proposed civil penalty was issued based on radiation protection and plant operations inspection findings during October 1981 and May to September 1982 (EA 83-7, $140,000, level III).

May 1983 ~~ Enforcement Conference at NRC Region I Office, May 6,1983, regarding procedural and Technical Specification adherence, and plant operations (NRC Inspection 50-277/83-13 and 50-278/83-13).

June 1983 Management meeting to discuss the results of the SALP for the period March 1982 to February 1983.

June 1983 A Notice of Proposed Civil Penalty was issued on June 14, 1983 for a containment integrity violation (EA 83-46, $40,000 level III).

July 1983 Confirmatory Act. ion Letter dated July 13, 1983, regarding conduct of emergency preparedness drill associated with deficiencies in health physics practices identified in the Annual Exercise on June 28, 1983.

August 1983 Confirmatory Action Letter dated August 9, 1983, regarding planned corrective action on deficiencies identified during the in-plant health physics drill conducted on August 3, 1983.

l August 1983 Enforcement Conference at NRC Region I Office, August 11, .

1 1983, regarding the Peach Bottom fire protection program.

(NRC Inspection 50-277,278/83-23). A severity level IV violation was issued.  ;

March 1984 Management meeting to discuss the results of the SALP for the period March 1983 to December 1983.

April 1984 An Enforcement Conference was held April 12, 1984, to discuss the findings of Inspections 50-278/83-32, 50-277/84-01,

50-278/84-01, 50-277/84-03 and 50-278/84-03 relative to individual rod scramming and LC0 violations (NRC Inspection 50-277,278/84-11).

June 1984 Notice of Violation and Civil Penalty was issued June 18, 1984, associated with violations regarding excessive heatup rates, an unplanned reactor pressurization, and excessive rod scram times (Enforcement Action 84-39,

$30,000, level III).

June 1984 Order modifying license dated June 18, 1984, regarding violations associated with Enforcement Action 84-39 requiring the licensee to submit and implement a plan for an appraisal of: (1) the process for performing safety evaluations and reviews of procedures pursuant to 10 CFR 50.59 to determine if the process is currently effective. or if improvements are needed; (2) plant and system operating procedures to verify that existing procedures are consistent with Technical Specification bases, and those sections of the FSAR concerning systems necessary to mitigate Design Basis Accidents, and do not involve unreviewed safety questions; ano (3) the program for ensuring that employees involved in the review and approval of operating procedures remain cognizant of the licensing bases, t

(

)

July 1984 - kn Enforcement Conference was held July 31, 1984, to discuss the findings of Inspection 50-277/84-19 and 50-278/84-10 relative to security plan violations (Enforcement Action 84-44, no civil penalty, level III).

February 1985 An Enforcement Conference was held February 8, 1985, to discuss the findings of Inspection 50-278/85-07, a Unit 3 event regarding simultaneous diesel generator inoperability and containment cooling. (No enforcement action was taken).

March 1985 An Enforcement Conference was held March 4, 1985, to discuss findings of a radiological event during the Unit 2 outage from Inspection 50-277/85-11.

May 1985 Enforcement Conference was held to discuss security plan violations. (NRC Inspection 50-277/85-16,50-277/85-13).

The violations were categorized as a severity level IV.

I June 1985 Civil Penalty was issued June 7, 1985, associated with NRC i Inspection 277/85-11 conducted during period February 13-15, 1985.

The violations were associated with radiation protection practices during the Unit 2 pipe replacement outage. The Notice of Violation and Civil Penalty were combined with escalated enforcement from Limerick (Enforcement Action #85-42, $25,000).

June 1985 Enforcement Conference was held to discuss an apparent inattentive Unit 3 reactor operator. No Enforcement Action was taken (NRC Inspection 278/85-22).

June 1985 Management meeting to discuss the results of the SALP for the period January 1984 to March 1985.

August 1985 Management meeting to discuss status of June 18, 1984 Order.

November 1985 Confirmatory Action Letter dated November 5, 1985, regarding actions to be taken by PECo in the area of Peach Bottom emergency preparedness.

November 1985 Enforcement Conference to discuss problems with radwaste transportation activities.

March 1986 Enforcement Conference was held to discuss an out of sequence control rod withdrawal and related personnel errors during a Unit 3 startup (NRC Inspection 50-278/86-09).

May 1986 Enforcement Conference held to discuss 01 Report (50-278/1-85-19) concerning the alleged termination of employment of a workman following engagement in activities protected under 10 CFR 50.7.

June 1986 SALP Board Report for period April 1985 to January 1986 issued.

June 1986 -- Civil Penalty dated June 9,1986, associated with violations during the Unit 3 startup in March 1986 and out of sequence control rod withdrawal event (EA 86-59,$200,000, level III).

June 1986 NRC Region I meets with PECo to discuss performar.ce issues.

June 1986 ED0 letter to FEco Chief Executive Officer expresses concern with operations and requests meeting to discuss declining perfonnance.

June-July 1986 A special diagnostic team inspection (50-277/86-09 and 50-278/86-12) was conducted to determine the underlying reasons for the licensee's poor performance described in the most recent SALP (June 1986), and to ascertain whether they could have an adverse impact on the safety of plant operations.

t

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SALP RATINGS ASSMT.

PERIOD OPS RADCON MAINT SURV EP FP sic REFL QP LIC TRN 5/79- 2 N 3 2 2 2 3 2 3 N N 5/80 7/80- 2 2 2 1 2 3 2 1 2 N N 6/81 7/81- 2 3 2 2 2 3 2 2 N 1 N 6/82 3/82- 2 3 2 3 1 3 1 2 N 2 N 2/83 3/83- 2 2 2 2 2 2 1 2 N 1 O 12/83 1/84- 2 3 1 2 2 2 3 1 N 1 N 3/85 4/85- 2 2 2 2 2 2 3 1 3 2 2 1/86 9

_- TVA - BROWNS FERRY AND SEQUOYAH TVA, with one of the largest nuclear power prograns in the U.S., has had a history of operating and management difficulties. The five nuclear plants with operating licenses in that system -- namely, the three units at Browns Ferry and the two units at Sequoyah -- are shut down. A number of technical and management issues have been identified that require resolution prior to the Commission allowing these units to restart.

A summary of the plant-specific problems and a tabulation of major events, i regulatory actions, and enforcement actions for Sequoyah are provided at the end of this Appendix. Also provided is a sursary of plant-specific problems and a tabulation of major events, regulatory actions and enforcement actions for Browns Ferry.

TVA, by its continued poor performance, has demonstrated ineffective management of its nuclear program. This poor performance is indicated by:

- Four successive SALP periods with Category 3 performance in Plant Operations for the Browns Ferry facility. .

- Three successive SALP periods with Category 3 performance in Quality Assurance and Administrative Controls Affecting Quality for both the Browns Ferry and Sequoyah facilities.

- Three successive SALP periods with Category 3 performance in Maintenance and Security and Safeguards for the Browns Ferry facility.

- Multiple escalated enforcement actions, including a Confirmatory Order regarding the Browns Ferry Regulatory Performance improvement Program, an Order regarding identification, evaluation and reporting of significant 7, issues, frequent enforcement conferences, and ten civil penalties totaling

> $895,000 since March 7, 1984

- Numerous significant events at TVA facilities, such as the Sequoyah Unit 1 seal table event of April 19, 1984, the Browns Ferry Unit 3 startup event of October 22, 1984, the Browns Ferry Unit 3 water level instrumentation event of February 13, 1985, and the Sequoyah equipment qualification problems identified in August 1985, i 4 A lack of Corporate attention to the control of operating activities and support to the individual sites coupled with a lack of strong centralized leadership with sufficient corporate nuclear experience

)

to effectively manage a large nuclear program.

- An apparent loss of employee confidence in TVA management, as evidenced by numerous employee concerns and allegations of intimidation and harassment.

Prior to 1986, TVA actions were insufficient to bring changes and improvements i

to the TVA nuclear program. Presently, there are major changes underway at j TVA. In hindsight, we found the increasing level of NRC attention to TVA i 1984 and 1985 did not achieve adequate results. In response to NRC enforcement actions against TVA, some at escalated levels, TVA made a number of changes including im govements in Browns Ferry operations and corporate quality assurance programs. In May 1984 at NRC's request TVA even developed a corporate Regulatory Performance Improvement Program for Browns Ferry. By March of 1985, the issues had become so numerous and significant that the Regional Administrator expressed concerns about the operation at the Browns Ferry site. Unable to address these concerns, TVA management shortly thereafter elected not to operate any of the three Browns Ferry units. At the operating Sequoyah facilities, TVA could not determine the status of the equipment qualification program and consequently, TVA voluntarily elected to shut down the Sequoyah units in August 1985.

With respect to NRC's regulatory activities, in April 1985 the Executive Director for Operations appointed a senior management team consisting of the Director of our Office of Nuclear Reactor Regulation, the Director of our Office of Inspection and Enforcement, and the Administrator of our Atlanta Office. More recently, the Director of our Office of Investigations was added to the team, a member of the Senior Executive Service was assigned to provide support for the team, and the Deputy Regional Administrator of ,

the Atlanta Office replaced the Regional Administrator on the team. The NRC has made substantial increases in our staff assigned to the regulation of TVA activities. Additionally, the NRC Office of Inspector and Auditor is looking into allegations regarding NRC employees involved in TVA activities and the NRC is laying the ground work to develop the lessons to be learned from the -

TVA situation.

In September 1985, based on NRC appraisals of TVA's performance, NRC formally requested further information regarding TVA's plans for resolving its problems.

Although some information was subsequently provided, TVA advised the NRC in January 1986 that revised submittals were being prepared and that our review of prior information should be held in abeyance. One revised submittal has been received, regarding the Corporate Nuclear Performance Plan, and a revision to the Sequoyah Nuclear Performance Plan is expected shortly.

Nuclear matters at TVA are now under the control of a single individual, and TVA has brought new personnel into the line management to fill key management 1 positions. Mr. Steven White is the new Manager of Nuclear Power at TVA and Mr. Norman Zigrossi has been appointed to the newly created position of TVA Inspector General. TVA has advised the NRC that their priority attention is directed towards Sequoyah; however detailed plans and schedules are not yet available.

The NRC has made a substantial commitment of resources to TVA regulatory activities and will maintain this comitment. The NRC will continue to work closely with TVA at the staff and management level to assure the public health and safety are protected at TVA's nuclear facilities.

l l

l 1

, , - BROWNS FERRY

Background

Browns Ferry Nuclear Generating Plant is a three unit 1100 Megawatt electrical GE BWR-4 nuclear generating station owned and operated by the Tennessee Valley Authority (TVA), Knoxville, Tennessee. The facility is located approximately 35 miles west of Huntsville, Alabama near Athens, Alabama. Unit I received an operating license on December 20, 1973. Unit 2 received it's operating license August 8, 1974, and Unit 3 received its operating license August 18, 1976. Both Units 1 and 2 were shutdown from 1975 to 1977 as a result of a cable fire in the penetrations between the cable spreading room (common) and the Unit I reactor building.

All three Brown Fer ry Units are currently shutdown. The licensee has conmitted to the NRC to keep each unit down until they and the NRC are satisfied that each unit can be operated within NRC requirements. Unit I was shutdown March 19, 1985, due to several containment isolation valves in the high pressure coolant injection system failing to pass local leak rate tests. The licensee subse-quently decided to enter a refueling outage early. Unit 1 is currently defueled.

Unit 2 was shutdown September 15, 1984, for a planned short refueling outages and the fuel was unloaded. Outage work on Unit 2 was delayed until Unit 3, which had been in a refueling outage, was returned to service.

Unit 3 was shutdown March 9, 1985, because of NRC concern regarding an unexplained mismatch in reactor water level instrumentation that occurred during a startup on February 3, 1985. Escalated enforcement action was taken against the licenesee as a result of its failure to imediately shutdown the unit.

Because of the number of problems involving equipment qualification, seismic qualification, configuration control and fire protection, the unit has remained shutdown.

Summary of Management Problems and Recent Operating History As a result of NRC inspection activities, areas of weak regulatory performance have been identified:

- Weak requalification training program as demonstrated by the failure of 80%

of licensed R0/SR0 on NRC administered requalification exams.

- Failure to control equipment status including numerous examples of improperly positioned switches / breakers, and improperly controlled jumpers / lifted leads.

- Failure to assure that required emergency equipment is operable when removing other equipment from service or changing modes.

- Failure to control access to high radiation areas and security areas.

- Failure to adequately implement the modification program including inadequ~Kfe packages, drawing update problem, hardware installation problems, post modification testing and post modification operation training deficiencies.

- Failure to adequately implement Technical Specificaticn and ASME Sect. XI testing requirements with the result that required tests were either not performed or improperly performed. .

- Excessive backlog of work request, modification, procedure changes and drawing changes.

- Failure of operation and engineering personnel to identify off normal conditions in a timely fashion.

- Inadequate interdepartmental communication.

- Low level of nuclear operating experience of TVA management at the site and in corporate headquarters.

- The NRC is concerned about licensee management's poor performance in the control of operational activities as evidenced by Browns Ferry's enforcement history and operating events record. As a result of numerous management meetings and enforcement conferences, TVA proposed a Regulatory Performance Improvement Program (RPIP) on February 24, 1984. The Region II Administra-tion issued a Confirmatory Order July 13, 1984, which required the licensee to implement its proposed RPIP. The RPIP failed to achieve the required level of improvement at the Browns Ferry plant.

As a result of the failure to obtain sufficient improvement in performance in response to escalated enforcement action, in early 1984 TVA was required to submit written plans to upgrade performance at Browns Ferry. The Regulatory Performance Improvement Program (RPIP) was confirmed by an order dated July 13, 1984. TVA assigned additional specialists to assist the site in specific areas, hired consultants, and completed organizational changes to strengthen management controls as part of the RP!P; however, performance failed to improve. Significant issues and events continued to occur. The Regional Administrator had additional discussions with the members of the TVA Board in early 1985. Following the reactor water level event, on March 8, 1985, the Regional Administrator requested the Manager of Nuclear Power to justify continued operation of the Browns Ferry units. After reviewing the details of the event, TVA ordered Unit 3 shutdown on March 9, 1985. Unit I was shutdown March 19 (Unit 2 had been shutdown for refueling September 15,1984) due to inoperability of the high pressure ccolant injection system. The Manager of Nuclear Power agreed to not restart any unit without NRC concurrence. on July 3,1985, the Executive Director for Operation sent a letter to the Chairman of the TVA Board of Director about sustained and consistent history of poor performance.

As discussed in the E00's July 3, 1985 letter to the TVA Board, the previous management b'o'th at corporate and at individual plants was weak in total nuclear experience and in actual operating experience in a nuclear plant. Recent addition to these staffs have not significantly increased the nuclear operating experience.

A contributing factor may have been that TVA's nuclear program appears to have not fostered the promotion of individuals with opera.tions experience. For example, all candidates for an R0/SR0 license had to complete the basic TVA two year training program, regardless of their background. This may have discouraged engineers, navy nuclear operators, and operators from other utilities from joining their licensed operator training program. This then limited TVA's ability to upgrade the organization and learn from others, and resulted in middle and upper level managers at both the plant and corporate with little reactor operating experience. With the loss of several instructors from the TVA training school in 1981, the loss of several licensed operators, and the replacement of an experienced plant superintendent with an individual with no operating experience,

! performance began a steady decline from about 1981. Two " operations" experienced assistant superintendents left TVA within the next year. They were replaced by the promotion of individuals who had little operating experience. In order to meet requirements of ANSIN 18.1-1971, these men were given a six month "SR0 Equivalent" training course.

The shortage of personnel with operating experience still hampers TVA's efforts to prepare the Browns Ferry plant for a return to operations. Additionally, the training program effectiveness had decreased as evidenced by the fact that eighty percent of the Reactor Operators (RO)/ Senior R0s reexamined by the NRC in November 1985 failed the examination. These individuals were removed from

licensed duties. Because of the high failure rate, TVA increased their requalification training program from two weeks per year to 16 weeks. The first of three groups of R0/SR0s who will be requalified has recently completed this 16 week program and has taken the NRC administered requalification exams. The results of the exams are not yet available.

Significant Event Chronology January 1980 ORDER issued to review administrative control and main-tenance activities to assure that safety features are not defeated. Meeting with TVA to discuss actions implemented j in response to ORDER.

j Civil Fenalty issued for loss of containment integrity on Browns Ferry Unit 3.

1 June 18, 1980 Civil Penalty issued for Browns Ferry radwaste shipment.

I Partial failure of control rods to scram Unit 3. Immediate June-November 1980 Action Letter (IAL) issued for TVA to investigate failure of control rod to scram. Meeting in August 1980 reviewed as-built scram discharge volume and related scram systems, Immediate Action Letter issued in October 1980 for failure to monitor water in scram discharge volume as required.

Submitted Abnormal Occurrence Report to Congress in November 1980 describing failure of control rods to j

insert fully during a scram at Browns Ferry Unit 3 (A080-6). ORDER for permanent modifications issued June 1983. -

i September 4, 1980 Meeting (All Dockets) - 1egional Administrator addresses '

all senior TVA management en Quality Assurance matters.

! September 11, 1980 Immediate Action Letter issued for unsatisfactory response to Inspection and Enforcement Bulletin 80-1.

October 2, 1980 Meeting to discuss Inspection and Enforcement Bulletin.79-018 environmental qualification requirements.

October 23, 1980 Meeting to' discuss Systematic Assessment of Licensee Performance results. '.

December 1980 Several meetings, including Regional Administrator. meeting with TVA General Manager to relate growing Quality Assurence concerns on plant performance and discussion of pla_nt -

operations and management controls. l, January 1981 Meeting to discuss site security program. Immediate Action Letter issued concerning Browns Ferry security program '

access controls.  ;

4 February-March Immediate Action Letter issued concerning fire protection '

l 1981 problems at Browns Ferry. Meeting to discuss site' fire protection program deficiencies. Civil Penalty issued,for fire ,

protection deficiencies. ,

March 6, 1981 Meeting (All Dockets) - Discussion of TVA reorganization.

February 11, 1982 Enforcement Conference - Exceeding a Limiting Conditions ,, ,'

1 for Operations involved with closing a pressure transmitter.

valve.

March-May Enforcement Conference on Security issues. Civil Penalty 1982 issued for unsecured vital area.

May 27, 1982 Enforcement Conference - Unsecured radiation aria'.-

l September- Enforcement Conference held in September 1982 on radio-December 1982 active waste shipment deficiencies. Enforcement conference on November 1982 radwaste shipments adequacy. Enforcement Conference December 1982 waste oil disposal. Civil Pen Ity issued December 1982 for defective packaging of radwaste - .

shipment. -

January 5, 1983 Enforcement Conference Security issue. Civil Penalty-issued - Failure to control access to protected area.

]

January 6,1983 - Management Conference - Recirculation pipe crack issue.

, ORDER August 1983 - Shutdown Unit 3 for Intergranular Stress Corrosion Cracking (ISCC) inspections. ORDER December 1983 - Inspection of Unit I recirculation and RCS piping. Submitted Abnormal Occurrence Report to Congress April 1984 entitled Large Diameter Pipe Cracking in BWRs (A0 83-5). Generic issue applicable to Browns Ferry. -

March 25, 1983 ORDER issued to incorporate Three Mile Island action items.

4 June-October Four Enforcement Conferences held to discuss refueling 1983 operation violations, security issues, safety system s, inoperability and radiation exposure control.

December 16, 1983 Enforcement Conference concerning Security deficiencies.

Confirmation of Action letter issued December 21, 1983.

1 December 1983- Four meetings held with TVA concerning operator training

, January 1984 deficiencies, emergency planning deficiencies, security issues, 1 - and need for management changes to address continuing site

]

problems.

February 24, 1984 Enforcement Conference - Improper rod movement. Civil Penalty issued 3/7/84 February 1984 TVA initiated Regulatory Performance Improvement Program l (RPIP) at Browns Ferry - Regional management review of

. plant performance May 14-15, 1984. ORDER - issued imposing Regulatory Performance Improvement Program (RPIP) July 13, 1984. Meeting held August 31, 1984 to review RPIP status.

April 12, 1984 Meeting held to discuss Site organizational changes.

'May 23, 1984 Four meetings October 3-4, 1984, October 17-18, 1984 and

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February 6, 1985, to discuss Integrated Schedule.

June 21, 1984 Enforcement Conference to address electrical design deficiencies and planned reviews.

I. August 1984- Core spray system overpressurized on Unit 1. Enforcement l April 1985 Conference held on September 26, 1984. Civil penalty issued January 28, 1985. Submitted Abnormal Occurrence s Report to Congress entitled Degraded Isolation Valves in Emergency Core Cooling Systems (A0 84-8). Generic issue based, in part, on an event at Browns Ferry Unit 1 on i 8/14/84.

August 30, 1984 Enforcement Conference held concerning Inoperable Residual Heat Removal (RHR) service _ water pumps.

September - Two meetings held concerning Quality Assurance reorganization

- October 1984 and status of Nuclear Safety Review Staff activities.

j I

November 1984: Unit 3 reactor startup event. Enforcement Conference held February 1985 11/17/84. Confirmation of action letter issued November 15, 1984. Civil Penalty issued 2/27/85.

December 31, 1984 Regional Administrator Meets with TVA Board to discuss matters requiring Board attention.

Enforcement Conference - Manag'ement control of maintenance February 7, 1985 activities. J February 12, 1985 First visit to Browns Ferry by new Regional Administrator.

Informed Site Director there was a significant probability of a serious event at Browns Ferry.

February 19, 1985 Regional Administrator's second visit to Browns Ferry. l First meeting with Chairman Dean and Manager Power and

- Engineering. Regional Administrator repeated his concern previously expressed to Site Director.

February 28, 1985 Enforcement Conference (All Dockets) held concerning inadequate corrective action for and management attention to problems identified by the TVA QA staff. .

March 1, 1985 Regional Administrator meets with C. Dean and R. Freeman and discusses concerns about Browns Ferry reactor vessel water level incident.

March 1985 , Regional Ad:ninistrator requested Manager Power and Engineering to justify continued operation of Browns Ferry Unit 3 in view of their handling of the water level discrepancy and other recent events. Manager '

decided to shut down unit on 3/9. Regional Administrator ,

commended TVA for this action. Plant remains shut'down

-due to numerous equipment and managerial problems.

Regional Administrator suggested to Manager Power and Engineering that they consider doing a comprehensive operational readiness review with help from EGG. TVA agreed.

March-July Enforcement conference held 3/14/85 with TVA on operation 1985 of Browns Ferry 3 with reactor vessel water level discrepancies (original reason for shutdown of Unit 3).

TVA agreed not to restart without NRC approval. Civil penalty issued July 22, 1985.

March-April Unit 1 shut down 3/19/85 due to failure of high pressure 1985 coolant injection system isolation valves to pass local leak rate test. Manager Power and Engineering agreed not "

to restart without NRC concurrence. Enforcement Conference held on 4/8/85.

March-May NRC receives initial TVA employee concerns in~ March 1985.

1985 NRC Senior Executive Board meeting with TVA to ' discuss enhanced Employee Concerns Program on 5/2/85.

g h.,fT

May 2, 1985 - Meeting (Browns Ferry and Watts Bar) - Discussion of inadequate surveillance instructions.

May 16, 1985 Civil Penalty issued on Security issues.

June 28, 1985 Staff concerns issued to Commission regaraing TVA issues (SECY-85-231).

, July 3, 1985 Letter from ED0 to TVA Board to TVA expressing concerns about TVA performance deficiencies including operating experience of managers.

July 22, 1985 New personnel appointed Acting Plant Manager and Operations Supervisor at Browns Ferry.

July 1985- Three meetings held with TVA regarding operational readiness September 1985 program, TVA plans to restart Browns Ferry, and status of TVA corrective actions.

September 1985 NRC Executive Board meets to discuss Systematic Assessment of to date of Licensee Performance (SALP) evaluation. NRC issued 10 CFR 50.54(f) letter September 17, 1985. Meeting with TVA management October 22, 1985 to discuss TVA initial responses related to Corporate and Sequoyah. TVA submits initial response November 4, 1985. Meeting December 18, 1985, to discuss Watts Bar and Browns Ferry response to 10 CFR 50.54(f) letter. Revised corporate program submitted March 10, 1986.

NRC requests additional information on May 1, 1986.

September 12, 1985 Comission meeting to discuss status of TVA Nuclear Program.

September 16, 1985 Meeting with TVA to discuss environmental qualification of electrical equipment on all TVA facilities.

October 16, 1985 Mr. C. Mason reemployed as TVA Manager of Nuclear Operations.

November 1985- Region II administered requalification examination to 15 February 1986 R0/SR0s, 12 failed. Meeting February 21, 1986 in Chattanooga to discuss requalification training program.

September 25, 1985 Mr. W. Bibb reported to Browns Ferry as Site Director (contractor).

January 13, 1986 Mr. S. A. White appointed TVA Manager of Nuclear Power (contractor).

January 27, 1986 Mr. N. A. Zigrossi appointed TVA Inspector General.

February 4, 1986 TVA notified the ED0 that a revised version of the TVA nuclear performance plan would be submitted.

February 7, 1986 The staff briefed the Commission on the status of TVA activities. l l

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February 1986 -

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Submitted Abnormal Occurrence Report to Congress describing Management Deficiencies at TVA (A-85-14). Report to be published in March 1986.

March 11, 1986 TVA management briefed the Commission on their plans to resolve TVA problems under the direction of Mr. S. A. White.

April 1986 NRC meetings with TVA to discuss the site fire protection program and environmental qualification of Browns Ferry electrical cables.

May 6- NRC, meeting at the Browns Ferry plant to discuss TVA July 1986 restart activities.

May 12, 1986 NRC senior managers meet with TVA's Manager of Nuclear Power and the TVA Inspector General regarding the TVA employee concerns program.

May 14-15, 1986 NRC meeting with TVA at the Browns Ferry plant to discuss -

seismic issues.

May 16, 1986 TVA Board notified the Commission Chairman of measures established to assess safety and other aspects of the TVA nuclear power program.

May 28, 1986 Enforcement conference with TVA management to discuss potential material false statements related to licensing submittals and breakdown in management controls identified in inspections in 1985-1986.

June 19, 1986 Enforcement conference with TVA management in the Region II office to discuss TVA's Intimidation and Harassment of TVA Employees based on 0I investigations.

June 24, 1986 Management meeting with TVA management in the Region II office to discuss Cable Pulling activities on Unit 2.

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i i l __- SALP RATINGS >

i I--

l i ASSMT.

RPT PERIOD OPS RADCON MAINT SURV EP FP SEC REFL QUP LIC TRN ,

i 01/81 04/01/79- 2 3 2 2 2 2 2 2 3 N 2 (

08/31/80 i 11/82 07/01/80- 3 3 2 2 N 3 2 2 3 N 3 .

06/30/81 06/83 07/01/81- 3 3 3 2 2 2 3 1 3 2 N

12/31/82 4

06/84 01/01/83- 3 3 3 2 2 N 3 3 3 2 N .

l 02/29/84 09/85 03/01/84- 3 2 3 3 2 3 3 N 3 3 2 05/31/85 i

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, , - SEQUOYAH

Background

Sequoyah Nuclear Plant is a two unit pressurized water nuclear reactor owned by the Tennessee Valley Authority. Each reactor is contained in a Westinghouse Ice Condenser Containment. -

The facility is located in Hamilton County, Tennessee, about 9.5 miles northeast of Chattanooga. Sequoyah Unit I was licensed on September 17, 1980; Sequoyah Unit 2 was licensed on September 15, 1981.

Summary of Management Problem and Recent Operating History As a result of NRC inspection activities, areas of weak regulatory performance have been identified including:

- Inadequate inter-departmental communications.

- Failure of operations personnel to identify off-normal conditions in a timely fashion. .

- Excessive backlogs of work requests and modifications.

- Failure to adequately implement the modification program including inadequate work packages, drawing update problems, hardware installation problems, and post modification deficiencies.

- From 1980 through 1983, the Sequoyah units demonstrated a scram rate approximately equal to the average for all PWRs. However, in 1984, both Sequoyah units showed a higher than average scram rate.

- A review of ESF actuations from January 1, 1984 through June 30, 1984 indicated that the Sequoyah units experienced a much higher number than comparable PWRs. The large number of these actuations indicate that the plant staff was not effectively diagnosing or correcting the causes.

- Management both at corporate and individual plants is weak in total nuclear experience and in actual nuclear plant operating experience.

- Three successive SALP periods with Category 3 performance in Quality Assurance and Administrative Controls Affecting Quality for the Sequoyah facility. This was due largely to poor Corporate Quality Assurance performance.

- Numerous significant events at TVA facilities, including the Sequoyah Unit I seal table event of April 1984, and the inadvertent Unit I containment spray event in February 1981.

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During Sequoyah's operating life, the regulatory performance of the Sequoyah plants has been generally mediocre with a recent declining trend. This perfor-mance combined with the historical poor performance of TVA in general, has resulted in a progression of escalating NRC regulatory actions including assessed civil penalties.

During Sequoyah's operating life, no abnormal occurrences have been reported; however, several events resulted in intense NRC scrutiny.

In February 1981, an inadvertent containment spray event occurred at Sequoyah Unit 1. This event occurred with the unit shutdown awaiting the end of the licensing pause following the Three Mile Islan'd accident. Several concerns were raised by the NRC, including the area of management interaction. Specifically, management interaction with operations personnel did not consistently ensure use of properly trained personnel, coordination of plant mode changes, or coordination of maintenance activities with plant operators.

Site performance generally remained average with enforcement actions associated with operational problems common to recently licensed plants. As the plant ,

operational experience increased, plant management control developed, and plant performance began to improve. However, in late 1983, personnel error problems began to increase significantly, and an enforcement conference was held in January 1984.

In April 1984, an incore probe seal table leak event occurred in Unit 1. The NRC concluded that the event did not have a significant effect on public health and safety; however, significant concerns arose over the breakdown in administrative controls.

These concerns specifically included:

Controls on modifications to special tools.

Inadequate procedures.

Procedural adherence.

Plant Operations Review Committee review implementation.

At a September 25, 1984 meeting between the NRC and TVA regarding this event, TVA management acknowledged a need for:

Increased management emphasis on job safety, ALARA, and hazard analysis.

Improved management control of and increased prioritization of thimble ,

cleaning activities during refueling outages.

On June 14, 1985, the NRC assessed TVA a civil penalty in the amount of $112,500.

Performance since that event generally continued in a downward trend, but with no  !

particularly noteworthy operational events.

In early 1985, the NRC expressed concerns to TVA regarding environmental qualification of electrical equipment issues. TVA hired an independent contractor to review the documentation to determine TVA compliance with l 10 CFR 50.49. The contractor determined that the documentation appeared to be inadequate at all TVA sites. As a result, TVA shut down the operating Sequoyah units on August 21, 1985.

a

In September 1985, NRC senior management reviewed the latest Systematic Assess-ment of Lice 71see Performance (SALP) for TVA. It was concluded that by TVA's continued poor performance, it had demonstrated ineffective management of its nuclear program.

As discussed in the Browns Ferry testimony, NRC took escalating enforcement action to increase the level of TVA Board and subordinate management attentior, to the problems identified.

Because of NRC concerns regarding significant uncorrected programmatic and management deficiencies, on September 17, 1985, the NRC issued a request for information pursuant to 10 CFR 50.54(f) to determine whether the license for Sequoyah should be modified or suspended.

The NRC is currently conducting a substantial review and inspection of Sequoyah activities and TVA corrective actions. The status of a number of major NRC and TVA activities appear in SECY 86-1C. Briefly, TVA has reorganized and augmented its corporate and site management structure through the use of experienced management consultants in key line positions. TVA will formally submit a revision to its Nuclear Performance Plan for Sequoyah to describe this organization and existing and planned corrective programs. This Plan will include training permanent TVA employees to ultimately replace contract managers.

Significant Event Chronology July 2, 1980 Confirmation of Action (C0A) - Letter issued on TVA's program to implement IE Bulletin 79-14 requirements.

July- NRC conducted meetings with TVA (All Dockets) to discuss September 1980 NRC concerns regarding the results of Quality Assurance team inspection of Office of Engineering Design and Construction and TVA's employee concern program.

September 17, 1980 Issued Operating License for Sequoyah Unit 1.

November- NRC conducted meetings with TVA (All Dockets) to discuss December 1980 NRC concerns regarding Quality Assurance for construction testing at all TVA plants, growing Quality Assurance concerns on plant performance, and management controls.

February 11, 1980 Inadvertent spraydown occurs in Unit 1 containment. The NRC issues TVA a Confirmation of Action Letter (2/23/81) which requires certain corrective actions prior to unit restart.

March 6, 1981 Meeting (All Dockets) - Discussion of TVA reorganization.

August 26, 1981 Unit 2 containment spray valve misalignment is discovered in Unit 2. An Enforcement Conference (9/3/81) is held with TVA to discuss this issue. Civil Penalty issued (9/24/81) for inoperability of both trains of containment spray (assessed at 540,000). l l

September 15, 1981 Issued Operating License for Sequoyah Unit 2.

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December 198J - Control rod withdrawal limits were exceeded during the March 1982 startup of Unit 2 which resulted in a Confirmation of Action Letter (12/23/81) and a Management Conference (1/6/82). Civil Penalty issued (3/29/82) to TVA and assessed at $50,000.

July 20, 1982 Confirmation of Action Letter issued on TVA corrective actions for emergency exercise deficiencies. .

March 4, 1983 Management meeting to discuss TVA actions to address repetitive valve position verification errors.

January 16, 1984 Enforcement Conference to address increasing incidents of procedural noncompliance and personnel errors.

April 1984- Incore Instrument Thimble Tube Ejection Incident on Unit 1 June 1985 (4/19/84) requires plant shutdown for cleanup and repairs.

Significant NRC followup on radiological hazards associated with irradiated thimble tube. Managaement meeting ~

(9/25/84)' addressing Nuclear Safety Review Staff initial report on seal table event and independent NRC findings.

Civil Penalty assessed (6/14/85) at $112,500.

August 1984- Management meeting (8/3/84) (Sequoyah and Watts Bar) to February 1985 discuss NRC identified fire protection program deficiencies and noncompliance with Appendix R. Confirmation of Action Letter (8/10/84) issued on Sequoyah regarding TVA correc-tive actions to ensure compliance with fire protection regulations at Sequoyah and identify necessary modifica-tions. Enforcement conference on Sequoyah (2/20/85).

Subsequent inspections in 1985 have indicated significant improvement in achieving Appendix R compliance.

September- Meetings (All Dockets) held on TVA Quality Assurance October 1984 reorganization and status of Nuclear Safety Review Staff activities.

December 31, 1984 Regional Administrator meeting with TVA Board to discuss matters requiring Board attention.

February 28, 1985 Enforcement Conference (All Dockets) - Inadequate correc-tive action and management attention for problems identi-fied by the TVA QA staff.

March-May 1985 NRC receives initial TVA employee concerns. NRC Senior Management Team meets with TVA to discuss need to enhance TVA's handling of employee concerns. Senior Executive Board meeting with TVA to discuss enhanced Employee Concerns Program.

June 14, 1985 ORDER - Related to nonconformance reports (NCRs) and handling of containment pressure transmitters environmental qualification concerns.

June 28, 1985_ - Staff concerns issued to Commission regarding TVA issues (SECY-85-231).

July 3, 1985 Letter to TVA Board from E00 expressing concerns about TVA performance deficiencies and lack of management operations experience. TVA responds 7/18/85.

July 9, 1985 TVA splits Nuclear Power organization from Power Production organization and dedicates full-time manager.

July 16, 1985 NRC management meeting with TVA Board members.

August 21-22, 1985 Sequoyah (Units 1 and 2) shut down due to inadequate equipment qualification documentation. Commission meeting to discuss environmental qualification extension - Sequoyah extension denied (10/25/85). NRR/IE/ Region II perform environmental qualification inspection and audit (11/85 -

present).

September 1985- NRC issued 10 CFR 50.54(f) letter delineating NRC March 1986 concerns (9/17/85).

Meeting to discuss TVA initial responses to 50.54(f) letter related to Corporate and Sequoyah (10/22/85).

TVA submits response to 10 CFR 50.54(f) letter regarding specific Corporate and Sequoyah concerns (11/4/85).

Meeting with TVA to discuss responses to 9/17/85 50.54(f) letter on Sequoyah (12/12/85).

The TVA Board briefed the Commission on their plans and actions to improve managernent control of TVA nuclear power plants (1/9/86).

NRC and TVA briefed the Advisory Committee on Reactor Safeguards on TVA organizational changes (1/10/86).

Mr. S. A. White appointed TVA Manager of Nuclear Power (1/13/86).

Mr. N. A. Zigrossi appointed TVA Inspector General (1/27/86).

Submitted Abnormal Occurrence Report to Congress describing l Management Deficiencies at TVA (A-85-14) (2/86).

TVA management briefed the Commissien en their plans to resolve TVA problems under the direction of Mr. S. A. White (3/11/86). j October 16, 1985 Mr. C. Mason reemployed as TVA Manager of Nuclear l Operations. 1 t

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December 1985- ~ Two meetings with TVA to discuss the Sequoyah welding January 1986 reevaluation programs.

January 14-16, NRR and Region II visited Sequoyah site to assess adequacy 1986 of the electrical design calculation progran.

January 22-23, The Region II Office of Investigations Field Office 1986 Director visited Quality Technology Company (QTC) and the TVA Office of General Counsel to assess TVA progress in resolving intimidation and harassment concerns.

January 24, 1986 TVA submitted review plan for Sequoyah modification program.

January 30, 1986 Issued immediately effective ORDER to TVA regarding preservation of Quality Technology Company (QTC) records on employee concerns. Copy of TVA letter and ORDER sent to QTC.

January 31, 1986 Chairman Palladino and the E00 visited TVA headquarters in Chattanooga and the Sequoyah site.

l February 4, 1986 TVA notified the E00 that a revised version of the TVA

• nuclear performance plan would be submitted.

February 4, 1986 A third full-time resident inspector assigned to the Sequoyah plant.

February 7, 1986 TVA submitted portions of the welding review program and the TVA welding project review plan.

February 7, 1986 The staff briefed the Commission on the status of TVA activities.

February 17-21, Region II, Region III, and NRR licensing examiners 1986 conducted simulator evaluations of Sequoyah on-shift licensed operators at the TVA Training Center.

March 3-4, 1986 Commissioner Asselstine, Congresswoman Lloyd, and Congressman Cooper visited the Sequoyah site.

April 17, 1986 NRC senior managers met with TVA management to discuss the employee concerns program.

April 22, 1986 NRC management met with TVA at the Sequoyah plant to  ;

discuss restart activities.

April 25, 1986 TVA submitted the Sequoyah Phase II welding report.

May 1, 1986 TVA submitted Revision 9 of the TVA Topical QA Program.

May 12, 1986 NRC senior managers met with the TVA Manager of Nuclear i Power and the TVA Inspector General regarding the TVA i employee concerns program. .

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May 13,1986_, - Issued SECY-86-150, Report on Review of Intimidation and Harassment Issues at TVA. ,

May 16, 1986 TVA Board notified the Commission Chairman of measures established to assess safety and other aspects of the TVA nuclear power program.

May 30, 1986 Sequoyah enforcement conference with TVA management in the Region II office regarding failure to adequately test overcurrent protection devices on containment electrical penetrations. ,

June 19, 1986 NRC conducts an enforcement conference with TVA to discuss intimidation and harassment issues.

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SALP RATINGS

REPORT ASSMT.

DATE PERIOD OPS RADCON MAINT SURV EP FP SEC REFL QP I

• 01/81 04/01/79- 2 2 2 2 2 3 2 2 2 1

08/31/80 (Unit'1)

• 11/82 07/01/80- 3 2 2 2 2 2 2 N 3 a 06/30/81

! (Unit 1) i j 06/83 07/01/81- 2 2 2 1 2 N 3 2 3 -

12/31/82 t (Units 1 and 2) 1

' 06/84 01/01/83- 2 1 1 1 3 1 2 1 3*

02/29/84 (Units 1 and 2) 09/85 03/01/84- 2 2 3 2 2 2 2 2 3 05/31/85 (Units 1 and 2)

• NOTE: Ratings for these two periods are for Unit 1 only (Unit 2 rated underConstruction).

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, .._.._v - . . . - . . . ----

-- TURKEY P0 INT

Background

FPLs Turkey Point Unit 3 was licensed on September 19, 1972; Turkey Point Unit 4 was licensed on April 10, 1973. During Turkey Point!s operating history, the regulatory performance was fairly good until approximately 1983 when a noted declining trend was noted in the operation's and maintenance functional areas.

Currently, Unit 3 is operating; Unit 4 has been shutdown since January 1986.

Enclosure 1 provides a table of Systematic Assessment of Licensee Performance categories since 1979.

Summary of Management Problems The NRC has taken action to identify and respond to conditions and events at Turkey Point and to provide feedback to FPL management of NRC concerns. This has resulted in a redirection of FPL management of site activities.

In 1983 the NRC noted that several conditions existed any one of which would not necessarily create a " management" problem at the site. These conditions included:

Lack of supervisory involvement in day-to-day in-plant work activities Management's less than conservative interpretation of specific regulatory requirements Inadequate root cause analysis of events and equipment failures Recurrent equipment failures Failure to follow procedures In short, the plant line management was not striving for outstanding performance and the company was structured such that corporate oversight and the Quality Assurance Department (QA) did not force site performance improvements.

In the post TMI era, the NRC implemented two initiatives that enabled a better focus; the Resident Inspector Program and the SALP process. These have allowed a clearer and more continuous view of the day-to-day operations rather than snapshots.

FPLs first response to QA (management) issues was to verify that all commitments

- in the Quelity Assuranca Program were being met on a program basis. At the

1. functional level, procedure adherence, adequacy of procedures, and adequacy of turnover of plant char.ges were not always very good. Root cause analysis was a weakness. NRC inspection and identification was an input to FPL as was the SALP reviews.

In 1981, two reactor coolant system shutdown pressure transients occurred within hours of each other. These were the subject of Abnormal Occurrence Report 82-2.

Detailed inspection was performed and violations were issued for not having an adequate alignment procedure and not having an adequate functional test procedure.

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In 1983 a sigiiNicant event occurred - Auxiliary Feedwater was isolated. All auxiliary feed pumps were inoperable for approximately five days with Unit 3 at power. Therefore, in the event of a loss of main feed there would be no safety system available to feed the steam generators to remove decay heat.

A Severity Level II violation was issued. Abnormal Occurrence Report 23-4 discusses this issue. Procedure violations continued to be identified. SALP Category 3 in operations was established in SALP Report 83-33.

In late 1983 and early 1984, poor procedure adherence continued and was identified in inspection reports. Poor design reviews were identified during an NRC response to two " loss of offsite power" events. Two serious auxiliary feedwater system Technical Specification violations were identified in December 1983 and January 1984. Enforcement conferences were held, escalated enforcement with civil penalties.were issued, and a major performance enhancement program was confirmed by Order. FPL at this time committed major resources to recover management control. The enhancement program was aimed at both central issues and peripheral items that were known to help performance. It was known that, as these items were completed, a clearer focus might show other weaknesses that should be addressed also. Enhancement areas included: site facilities including administrative, health physics, maintenance, training and simulator buildings; operations enhancement including increased shift manning, administrative support on shift, equipment identification improvements, and improved shift turnover.

procedures; procedures review and upgrade - a substantial project; improved configuration control process and drawing updates; INP0 accreditation of training programs and a plant specific simulator; through management action, enhance organizational efficiencies; develop a commitment tracking system and an integrated living schedule. upgrade QA & QC people, programs and organizations; develop better work order systems and supporting data bases; and to restructure and update the facility Technical Specifications to the extent possible.

Since that time, day-to-day operations have improved, procedures have improved, plant conditions have inproved. The improvements have required time and intense attention from both FPL and NRC. As day-to-day operations improved, design changes and implementation became a more apparent problem. Inspections in the last year have highlighted this. FPL is embarking on a large program to re-constitute the design basis for the plant by the end of this year.

Enforcement action is pending on these issues.

Since issuance of the Confirmatory Order on the " Performance Enhancement Program" NRC management has met routinely with FP&L nanagement to monitor progress of the licensee's efforts to recover management control. These include almost monthly reviews by the Region II projects Section Chief and quarterly reviews by senior NRC management which includes the division Director level and often the Regional Administrator. This most recent review included the Director of IE. Further, the Regional Administrator has met with the company's new President and the Executive Vice President to discuss progress of improvements.

Significant Event Chronology June 6, 1979 Management meeting to discuss concerns regarding the effectiveness of FPLs Operational Quality Assurance Program and Management Control System.

October 5, 19Z9- Management meeting to discuss two Immediate Action Letters concerning unplanned releases of radioactive water.

October 28, 1982 Enforcement Conference to discuss recurring incidents of safety-related heat tracing and associated alarms being inoperable.

March 16, 1983 Enforcement Conference to discuss failure to properly evaluate radiation exposures.

April 28, 1983 Enforcement Conference to discuss the unavailability of auxiliary feedwater when Unit 3 was at full power.

May 3, 1983 Issue CP for failure to perform adequate radiation surveys / exposure evaluations.

/ Jgust 15,1983 Issue CP for Auxiliary Feedwater system inoperability with Unit 3 at power.

January 10, 1984 An enforcement conference was held to discuss two Auxiliary Feedwater System events. .

February 2, 1984 Issue CP for failure to control entry into a high radiation area (reactor sump area).

March 9, 1984 A meeting was N id to discuss the status of Turkey Point Plant Performance Enhancement Program (PEP review).

March 15, 1984 A meeting was held to discuss two Auxiliary Feedwater System events.

March 22, 1984 A PEP review meeting was held.

March 30, 1984 A PEP review meeting was held.

April 4, 1984 A meeting to discuss QA management changes was held.

April 12, 1984 A PEP review meeting was held.

April 15, 1984 A PEP review meeting was held.

April 26, 1984 A meeting to discuss SR0 eligibility requirements was held.

May 17, 1984 A PEP review meeting was held.

May 24, 1984 An enforcement conference was held to discuss security interface activities.

July 12, 1984 A PEP review meeting was held.

July 13, 1984 Issue Confirmatory Order on Performance Enhancement Program.

July 20,1984- ~ Issue CP for three AFW LC0 violations, several procedural violations, and failure to adequately review a design change.

August 14, 1984 A PEP review meeting was held.

September 10, 1984 A PEP review meeting was held. ,

September 19, 1984 An enforcement conference was held to discuss Intake Cooling Water System events.

October 24, 1984 A PEP review meeting was held.

October 29, 1984 A PEP review meeting was held.

November 2,-1984 Management meeting to discuss PEP progress.

November 9, 1984 Enforcement Conference to discuss corrective actions related to an entry into a high radiation area. -

December 7, 1984 Management meeting to discuss PEP progress.

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December 18, 1984 Enforcement Conference to discuss an AFW pump failure.

February 15, 1985 Management meeting to review SALP report.

February 20, 1985 Management meeting to discuss a change to the Physical Security Plan.

February 22, 1985 Management meeting to discuss PEP progress.

February 28, 1985 Issue CP for an intake cooling water TS LC0 violation.

March 28, 1985 Enforcement Conference to discuss the containment spray system.

April 12, 1985 Management meeting to discuss PEP progress.

May 23, 1985 Management meeting to discuss PEP progress.

June 24, 1985 Enforcement Conference to discuss radioactive waste transportation, a security computer outage and spent fuel pool alternative.

August 1, 1985 Issue Level III (No CP) for a security computer outage.

August 20, 1985 Issue CP for failure to determine whether a spent fuel pit modification created an unreviewed safety question.

August 30, 1985 Management meeting to discuss PEP progress and auxiliary feedwater system testing.

September 24, 1985 Management meeting to discuss PEP progress. l l

October 9, 1985- Enforcement Conference to discuss the turbine runback system.

November 26, 1985 Management meeting to discuss PEP progress.

January 8, 1986 Enforcement Conference to discuss maintenance issues an the Gamma-Metrics neutron detectors.

January 31, 1986 Enforcement Conference to discuss AFW system stop check valves and the loss of high radiation area access control.

February 25, 1986 Management meeting to discuss the FPL health physics program.

February 26, 1986 Management meeting to discuss the Select System review milestones.

March 7, 1986 Management meeting to discuss PEP progress. .

March 21, 1986 Management meeting to discuss requalification examination results, CCW flow balancing, and intake '

cooling water flow concerns.

April 28, 1986 Issue CP for failure to control a worker's radiation exposure in the traversing incore probe drive area and several procedural violations.

June 28, 1986 Issue CP for failure to perform startup testing and operator training on newly installed neutron flux instrumentation.

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__- SALP RATINGS

. Operating (Units 1 and 2)

RPT ASSMT. PERIOD OPS RADCON MAINT SURV EP FP SEC REFL QP LIC i

1/81 5/1/79-4/30/80 2 2 2 2 2 2 2 2 2 N j 1/83 9/1/80-6/30/82 2 1 2 2 2 2 2 1 N 2 12/83 7/1/82-6/30/83 3 1 2 2 2 N 2 2 1 2 j 2/85 7/1/83-10/31/84 3 2 3 2 2 2 2 2 3 1 4

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DAVIS-BESSE Backgrcund Davis-Besse Nuclear Power Station, Unit 1, is a single-unit 2772 megawatt (MW) thermal, 906 MW electrical, Babcock & Wilcox - 177 pressurized water reactor nuclear generating station owned and operated by Toledo Edison Comany (TECo) of Toledo, Ohio. The station is located approximately 21 miles east of Toledo near the town of Oak Harbor, Ohio. The station received its full power license (NPF-3) on April 22, 1977, generated its first electricity on August 28, 1977, and was placed in commercial operation on July 31, 1978.

Summary of Management Problems and Recent Operating History As a result of NRC inspection activities the following areas of weak regulatory performance have been identified:

- Multiple equipment failures during reactor trip events

- Licensee has not successfully identified the root causes and provided ,

lasting corrective action for many component and system failures / malfunctions Numercus Level IV and V violations and several recent escalated enforcement cases

- Inadequate maintenance activities resulting in safety-related equipment being degraded or incperable Inadequate implementation of the Performance Enhancement Program Weak licensed operator, non-licensed operator, and maintenance training Based on the above list of regulatory weaknesses, Region III has identified the following management weaknesses at Davis-Besse:

- Many of the regulatory problems had been brought to the attention of senior management and were not addressed because of self-icposed buaget constraints.

- There were not enough first-line supervisors available for the direct monitoring of maintenance work. While group leaders were expected to perform this function, their lack of management training and direction impacted their ability to provide objective and aggressive supervision.

- Ccmmunications between organizations at the plant were inadequate. The result was that problems remained unresolved for extended periods of time.

Clearly established and understood responsibilities for specific j maintenance and surveillance functions were not provided in sufficient detail to preclude omission of certain key functions, such as trending, measuring impact on operations, and identifying long lead-time materials.  ;

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- Difficultfes in providing spare parts to support maintenance activities resulted from insufficient spare parts on hand, poor planning for long lead-time items, lack of effective expediting, and an excessive amount of time to process requisitions.

- Training was not well supported, not systematically developed, not provided in sufficient quantity, and often cancelled due to work load.

There appear to be two primary reasons for the continuing management problems at Davis-Besse:

- Corporate imposed budget constraints rendered site management unable to improve staffing levels and forced site management to prioritize issues such that in some cases sa'fety-related functions were impaired. This promoted the correction of symptoms rather than root causes in order to return the plant to operation more quickly.

- Communications between corporate and station management were ineffective with respect to the need for conscientious implementation of both the Comprehensive Corrective Action Program and the Performance Enhancement Program. Communications between station organizations were weak resulting in matters impacting regulatory performance, plant operations, and '

maintenance remaining unresolved.

Region III used inspections, management meetings, normal and escalated enforcement actions, and Confirmatory Action Letters to correct management problems at Davis-Besse. During the same period, the licensee was encouraged to undertake a variety of self-help programs such as contracting for consultant studies of station programs, the Comprehensive Corrective Action Program, and the Performance Enhancement Program. The NRC staff believes the many improvements being made at Davis-Besse during the current extended shutdown should result in improved performance following restart.

Significant Event Chronology April 1977 Station receives full power license NPF-3 August 28, 1977 Station generates first electricity September 24, 1977 Loss of feedwater transient with system /

component misoperation: Steam Feed Rupture Control System half-trip, Power Operated Relief Valve sticks open, Auxiliary Feedwater (AFW) pump fails to come up to full speed.

April 18, 1979 Enforcement conference dealing with:

enforcement history, number of personnel errors, breakdown in management controls, equipment problems, and ineffectiveness of management in dealing with identified problems.

May 31, 1979 Management meeting to discuss improvements in level of management controls, staffing, training, correction of equipment problems, and plant operations.

April 21, 1980 - Confirmatory Order issued on Crystal River Lessons Learned.

May 2, 1980 Immediate Action Letter issued on security concerns from an ir.spection or. April 30 to May 2, 1980.

June 4, 1980 Management meeting to discu'ss 1) progress and changes made to improve management controls, staffing, training, plant operations, reduction <

in equipment problems and 2) review and assessment of security inspection findings.

. Enforc.ement conference on personnel overexposure.

June 20, 1980 Civil Penalty (E.A.80-037) for $13,000 issued for inadequate exposure rate evaluations, overexposure to direct radiation, and failure to follow procedures regarding planning and -

preparation.

January 29, 1981 Management meeting to discuss recurring problems ,

in the security area.

April 20, 1982 Confirmatory Action Letter issued on licensee's prompt notification system.

August 13, 1982 Confirmatory Action Letter issued on testing and evaluations to be performed during unit startup following 1982 refueling outage due to AFW l header replacement.

October 1, 1962 Management meeting to discuss surveillance testing and operability.

March 9, 1983 Enforcement conference on lack of improvement in ,

the maintenance program, the adequacy of '

corrective action in drawing control, and licensee equipment " operability" philosophy.

March 9, 1983 Toledo Edison Company introduces Comprehensive Corrective Action Program (CCAP).

March 30, 1983 Management meeting to discuss limiting condition I for operation (LC0) interpretation and reportability requirements.

August 16, 1983 Management meeting to discuss findings of the special fire protection inspection.

November 4, 1983 Management meeting to discuss development of a regulatory improvement program. l December 1, 1983 Enforcement conference on results of special fire protection inspection.

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January 10 -1984 Management meeting to discuss licensee's proposed Performance Enhancement Program (PEP).

February 2, 1984 Management meeting to further discuss licensee's Perforrrance Enhancement Program.

March 2, 1984 Inadvertent Main Steam Isolation Valve closure, reactor trip, Main Steam Safety Valve (SP17A4) failed to reseat, and AFW supply valve to Steam Generator (AF599) failed to open.

March 3, 1984 Confirmatory Action Letter issued for corrective action.s following March 2, 1984 stuck open main steam safety valve.

April 27, 1984 Management meeting to discuss licensee's progress in the Performance Enhancement Program.

July 13, 1984 Enforcement conference on circumstances -

surrounding the operability of the Control Room Emergency Ventilation System.

August 28, 1984 Staff meeting to discuss AFW system reliability and AFW pump driver diversity.

November 1984 Management meeting between the President of Toledo Edison, Director IE, and Regional Administrator to discuss the need for improved licensee communication and support for program improvements.

November 21, 1984 Civil Penalty (E.A.84-095) for $90,000 issued for failure to recognize design basis requirements for equipment operability, and failure to take effective corrective actions for identified problems.

December 13, 1984 Management meeting to discuss resolution of environmental qualification deficiencies.

December 28, 1984 Management meeting to discuss inspection findings and regulatory concerns.

January 4, 1985 SALP 4 meeting. Five Category 3 ratings in areas of maintenance, fire protection, emergency preparedness, quality programs and administrative controls, and training.

January 15, 1985 ICS controlling steam generator levels erratically, l reactor trip, AFW 1 transferred suction to service  !

water, attempts to restore proper lineup isolated 1 an AFW pump and caused short-term cavitation of )

the pump. .

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March 6, 1985- Management meeting to discuss licensee corrective actions for Category 3 areas noted in SALP 4.

April 2, 1985 Toledo Edison implements SALP improvement task force.

April 4, 1985 Confirmatory Action Letter issued for corrective actions with respect to failure of control rod lead screw nut leaf springs.

April 24, 1985 Peactor trip on flux / delta flux / flow due to reactor coolant flow indication instabilities with subseq.uent spurious actuation of Steam and Feedwater Rupture Control System and spurious trip of No.1 Main Feedwater Pump.

April 26, 1985 Confirmatory Action Letter issued for corrective actions with respect to damage sustained by several auxiliary feedwater pump turbine steam supply -

piping restraints.

May 24, 1985 Enforcement conference (1) sleeping auxiliary operator, (2) inadequate communications between security and operations personnel, and (3) failure to maintain proper reactor power for indicated reactor coolant flow.

June 9, 1985 Complete loss of feedwater event with subsequent misoperation of several components and systems.

June 10, 1985 Confirmatory Action Letter issued for actions following June 9 loss of feedwater event.

June 11, 1985 Incident Investigation Team begins review of loss of feedwater event.

July 12, 1985 Civil Penalty (E.A.85-071) for $100.000 issued for (1) sleeping auxiliary operator, (2) inadequate communications between security and operations

' personnel, and (3) failure to maintain proper reactor power for indicated reactor coolant flow.

July 24, 1985 Commission briefing on June 9th loss of feedwater event.

August 14, 1985 10 CFR 50.54(f) letter issued for actions following June 9th loss of feedwater event.

September 6, 1985 Inadvertent overpressurization of No. 1 Steam Generator during AFW pump testing.

September 9, 1985 Toledo Edison issues Course of Action (C0A) to resolve issues emerging from June 9th event.

September 17.-l985 Consnission briefing on Davis-Besse restart plan.

October 3, 1985 NRC establishes Davis-Besse Restart Test Review Group.

October 10, 1985 Presentation to full ACRS Committee on

, Davis-Besse restart plan, ,

December 13, 1985 Civil Penalty (E.A.85-107) for $900,000 issued i

for failure to identify torque switch settings 1

as improper resulting in failure to operate as required and failure to identify that AFW pump turbin.es would not operate properly.

January 24, 1986 Ad Hoc Review Group established.

March 14, 1986 Davis-Besse Study Group report issued which concluded that (1) licensee failed to properly j

identify root causes and provide lasting l

corrective action, (2) inadequate maintenance l

activities resulted in safety-related equipment 1 being degraded or inoperable, (3) numerous .

l procedure violations occurred over several years with no indication of improvement, (4) poor housekeeping resulted in many safety-related i

equipment malfunctions.

May 2, 1986 Ad Hoc Review Group issues report.

June 10, 1986 Advance copy of the Safety Evaluation Report (SER) related to the restart of Davis-Besse Nuclear Power Station, Unit 1, (NUREG-1177) is issued.

June 27, 1986 SER presentation to ACRS subcommittee.

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SALP RATINGS f

d

! Functional area SALP 1 SALP 2 SALP 3 SALP 4 i Plant Operations

• 2 2' 2 l

Radiological Controls

• 1 1 1

Maintenance 3 3 3 i Surveillance 2 2 2 i Fire Protection 2 2 3 Emergency Preparedness 1 2 3

! Security 2 2 2 7

Refueling

• 1 1 1 Quality Programs and 3 NR 3 i

Administrative Controls Licensing 2 2 2

Training (1) 3 -

! Environmental Controls (2) 2 l Notes .

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• SALP 1 rating structure differs from those of succeeding SALPs i NR Not rated during this cycle (1) Training area added for SALP 4 i (2) Environmental Controls area rated only in SALP 2

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i FERMI 2

Background

Fermi 2 is a single unit 3292 megawatt (thermal) GE BWR-4 Nuclear Generating Station owned and operated by the Detroit Edison Company. The reactor is contained in a Mark I pressure suppression containment. The facility is located in Frenchtown Township, Monroe County, Michigan, on Lake Erie approximately 30 miles south of Detroit. The facility received a low power license on March 20, 1985, and a full power license on July 15, 1985, but it has not been operated above 5% power. It was shut down for maintenance on October 11, 1985, and has remained shut down since that time.

Sumary of Management Problems and Recent Operating History In spite of the fact that Fermi 2 has held a full power license since July 15, 1985, it has only a brief operational regulatory history. Despite this brief -

history, several significant regulatory weaknesses have been identified by the NRC:

- Early inadequate management involvement in and oversight of reactor

! operating activities.

- Failure by management to ensure that actions taken to compensate for a lack of operating experience were effectively implemented.

- Ineffective engineering support.

Ineffective implementation of the security program.

The NRC took prompt action to ensure that all identified weaknesses were acted upon before plant operation was allowed to continue. A Confirmatory Action Letter (CAL) was issued on July 16, 1985, in response to the premature criticality event which occurred on July 1, 1985. This CAL requires Regional Administrator concurrence for operation above 5% power. In addition, on December 24, 1985 a 10 CFR 50.54(f) letter was issued which required the licensee to address all of the identified weaknesses prior to restart. In response to this letter the licensee developed a Nuclear Operations Improvement Program for the entire nuclear missien, a Reactor Operations Improvement Program l Oddressing facility operation, and established an Independent Oversight Committee for monitor facility progress. These actions still inprogress have been the subject of extensive NRC inspections and numerous management meetings. To date it is felt that the licensee has made significant progress in resolving their regulatory shortcomings.

The primary cause of the management and plant operations problems at Fermi 2 appears to be a lack of nuclear power plant operational experience at all management levels. This was illustrated additionally in the recently discovered engineering design deficiencies which have been one of the major causes for the reactor not being operational since October, 1985. Only recently have these deficiencies been corrected.

l To date, the man'agement problems at Fermi have been identified as pervasive rather than recurrent. This may be due in part to the brief operational history of Fermi. It is believed that the comprehensive nature of the corrective actions being demanded by the NRC will both eliminate the pervasive nature of the problems and prevent recurrence.

The NRC reacted aggressively to identified problems at Fermi in an effort to have those problems permanently and effectively resolved before a history, and '

attitude of poor performance could develop. In this regard the following actions have been taken:

- On July 16, 1985 a Confirmatory Action Letter (CAL) was issued in response to a premature criticality, event which occurred on July.1,1985. This CAL confinned licensee connitments regarding training of operators on control _

rod manipulations and the quality of simulator training. Regional Administrator concurrence is required for op ? ration above 5% power. ,

- A 10 CFR 50.54(f) letter was issued by the NRC on Decenber 24, 1985 to address management problems at the Fermi 2 facility, and requested a formal licensee response on how it would resolution of these problems would be achieved. The problem areas were:

1. The adequacy of management, management structures and systems that' have contributed to the performance of Fermi 2; the adequacy of training to assure that responsible personnel recognize and respond, '

as appropriate, to significant safety conditions; and, changes in controls needed to assure improved regulatory performance. The areas of operations, maintenance, engineering and security are to be included in the evaluation.

2. Actions planned to be taken by DECO to ensure readiness of the facility to support restart of the unit and power escalation after testing is completed at each power ascension plateau. Also to be included is DECO's assessment on how they will perform the review, objective criteria for determining adequacy of performance at each plateau, and the manager who will authorize proceeding to the-next plateau.

3. Actions to be taken to improve regulatory and operational performance during and after the startup testing phase of operations.

The licensee committed to a formal corrective action program which f s being monitored by the NRC. Because of the corrective actions required, the reactor has been shut down since October,1985, and will not be restarted without NRC approval.

This corrective action program has included acquisition of more experienced management at levels up to and including the vice presidential ~ level, facility; assessment by the Institute of Nuclear Power Operations, and the creation of an Independent Oversight Committee to monitor corrective actions and evaluate restart status.

l 1

- Numerour1hanagement meetings and enforcement conferences have been held with senior licensee management on both specific and general issues of

., concern.

- A detailed restart inspection program is being developed which will call for augmented inspection activities throughout plant restart using an experienced team of NRC inspectors and managers.. Recommendations regarding

., whether restart should continue will be made to the Regional Administrator by the team at specified plateaus. This augmented effort will not only monitor detailed plant activities, but will assess the overall effectiveness of the licensee's corrective actions directed at solving identified management problems.

Significant Event Chronology March 20, 1985 Fermi 2 low power license issued April 4, 1985 Management meeting to discuss NRC's perspective on potential problem areas during startup and testing. Also used to discuss NRC's inspection and .

enforcement practices for operating reactors.

May 15, 1985 Management meeting to discuss full power licensing readiness at Fermi.

May 20, 1985 Fermi 2 lower power license issued.

May 21, 1985 Management meeting to discuss physical security findings.

July 1, 1985 Reactor operator inadvertently moved eleven control rods out of sequence ,

resulting in a premature criticality, i July 18, 1985 Fermi 2 full power license issued.

July 23, 1985 Management meeting to discuss criticality event of July 2,1985.

I September 10, 1985 Management meeting to discuss issues to be resolved prior to exceeding 5% power.

/

November 1985 Fermi diesel generators experienced a series of bearing failures. This is a continuation of a problem first identified in February 1984.

January 24, 1986 Management meeting to review DECO action plan to repair and test the emergency diesel generators.

, =

W-February 14;"1986 , Management Meeting to discuss diesel

( generator issues.

May 9, 1986 Enforcement conference to discuss the July 1,1965 rod pull error.

May 30, 1986 Enforcement conference.to discuss weaknesses in Deco surveillance program.

June 3, 1986 Briefing by Independent Overview Committee.

June 26, 1986 Management meeting to discuss engineering i

issues.

July 3, 1986 Escalated enforcement action taken for July,1 rod pull e'rror. $300,000 proposed civil penalty and immediately effective Order issued.

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l SALP RATINGS Functional Area Rating

! Plant Operations 2 1'

Radiological Controls 2 Maintenance 2 Surveillance 2 Fire. Protection 3 Emergency Preparedness 1 Security 2 Refueling -- -

Quality Assurance / Administrative Controls 2 Licensing Activities 2 4

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LASALLE

Background

LaSalle County Station is a two unit 1120 Megawatt Electrical GE BWR-5 nuclear generating station owned and operated by Commonwealth Edison Company (CECO) of Chicago, Illinois. Each reactor is contained in a Mark II pressure suppression containment. The station is located approximately 50 miles southwest of Chicago near the town of Marseilles, Illinois. Unit I received its Low Power License on April 17, 1982, and its Full Power License on December 3, 1982. Unit 2 received its Low Power License.on December 16, 1983, and its Full Power License on March 23, 1984.

Summary of Management Problems and Recent Operating History As a result of NRC inspection activities, the following areas of weak regulatory performance have been identified:

- Recurrent eouipment failures in numerous systems including

- Fire Protection

- Effluent Radiation Monitors

- Control Room Noxious Gas Detection

- Reactor Water Cleanup System Isolation

- Residual Heat Removal Service Water

- Excessive Drift in Emergency Core Cooling System and Reactor Protection System Instrumentation

- Failure to control equipment status including numerous examples of improperly positioned valves and improperly controlled jumpers / lifted leads.

- Failure to adequately implement the modification program including inadequate packages, drawing update problems, hardware installation problems, and post modification operator training deficiencies.

- Failure to control access to high radiation areas.

- Failure to adequately implement Technical Specification and ASME Section XI testing requirements with the result that required tests were either not performed or inadequately performed.

- Excessive backlogs of work requests,it.odifications, procedure changes and drawing changes.

- Failure on the part of operations personnel to identify off-normal conditions in a timely fashion.

- Inadequate inter-departmental communications.

Many of these problems were identified by Commonwealth Edison during an onsite review conducted on July 16, 1982, and subsequently addressed in a Regulatory Performance Improvement Plan implemented in February 1983. This licensee initiative, whi-le focusing attention on areas requiring improvement, failed to produce sufficient improvement in Regulatory Performance at LaSalle County Station. Consequently, on November 22, 1985, Region III issued a letter to the licensee requesting that they evaluate and address the adequacy of Management and Management Structures, of Maintenance and Modification Programs, of Control of Work Activities, of the implementation of the Regulatory Improvement Program, and of resources committed to laSalle County Station in order that the NRC could make a determination pursuant to 10 CFR 50.54(f) as to whether the operating licenses should be modified, suspended, or revoked. Since issuance of the letter on November 22, 1985, Region III has held meetings approximately monthly with Senior Station and Corporate Management to evaluate licensee progress in performance improvement. Based on these meetings and other performance indica-tors (e.g., personnel errors, scrams), performance at LaSalle has shown an improving trend.

Weak station management, the continuing inability of corporate management to adequately compensate for the weak station management and the major work load in bringing two large units on line sequentially are the root causes of the poor regulatory and operating performance at LaSalle. Examples of these '

weaknesses are:

Corporate management failed to recognize and accept Station management deficiencies. Therefore, corporate guidance and assistance was late in.

coming.

- Corporate engineering did not provide adequate, quality products in support of facility modifications.

- Station management failed to motivate the staff towards excellence.

Management failed to establish an atmosphere of accountability extending down to the working level and was and continues to be reluctant to take personnel actions.

Management failed to establish an effective planning and scheduling mechanism with the result that work has not been completed efficiently and, at times, the work load placed on the operators was excessive.

- Management failed to recognize the impact of prcblems in non-safety related systems on safe, reliable plant operation.

With respect to LaSalle the NRC has adopted a two front approach to Regulatory /

management problems. First, an extremely low threshold for aggressive response to individual events was adopted. This is reflected in the Five Civil Penalties totaling $237,500 issued to date, the 13 Enforcement Conferences and three management meetings convened to discuss specific problems and concerns, and six Confirmatory Action Letters Second, the NRC, in parallel with the response to specific events, has aggressively pursued overall improvement in facility performance via a number of mechanisms including the licensee's Regulatory Performance Improvement Program, a special task force assessment of LaSalle performance conducted in 1985, the 10 CFR 50.54(f) letter issued in November 1985, with concurrent implementation of monthly plant status meetings, between the Regional Administrator and senior licensee management, and the development of a detailed Master Inspection Plan

focusing NRC inspection resources on identified weaknesses. To date, 14 Management MeTtings have been convened with the licensee to discuss over all Regulatory / Management performance.

Significant Event Chronology April 17, 1982 Unit 1 Low Power License Issued.

June 1982 Ten examples of improper valve lineups rendering secondary containment, effluent radiation monitoring equipment, and encqency core cooling systems degraded / inoperable.

June 11, 1982 Enforcement conference on security issues.

Management meeting with licensee to discuss NRC concerns over the excessive number of reportable events occurring after lower power license issuance. ,

August 1982 Allowable plant heatup rate exceeded.

October 1982 Violation of primary containment integrity. -

November 1982 Violation of secondary containment integrity.

December 3, 1982 Unit 1 full power license issued.

January 26, 1983 Management meeting to discuss proposed CECO guidelines to be used for providing information to NRC Region III inspectors.

February 17, 1983 Management meeting to discuss future improvements of the regulatory performance of CECO.

March 1983 Allowable Plant cooldown Rate exceeded.

May 13, 1983 Enforcement conference on concerns on programmatic deficiencies identified in the surveillance testing program for LaSalle Unit 1.

June 1, 1983 Discussion on recent adverse performance trends at the CECO nuclear facilities.

June 23, 1983 Enforcement conference on circumstances that resulted in a mispositioned drywell to suppression chamber vacuum breaker isolation valve during operation. Civil Penalty ($40.000)

July 26, 1983 Management meeting in CECO corporate offices to discuss improvement of licensee regulatory performance and enhancement of communications betwear the NRC and CECO.

August 1983 Allowable plant cooldown rate exceeded.

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August 24, 198,3- Inadvertent plant heatup and mode change.

September 9, 1983 Management meeting to discuss improvement of licensee regulatory performance and enhancement of communications between CECO and NPC.

September 27, 1983 Management meeting to discuss cable separation issues. -

September 30, 1983 Enforcement conference on the circumstances leading to the inadvertent heatup event, occurring on August 24, 1983.

October 19, 1983 Management meeting to discuss improvement of licensee regulatory performance and enhancement of communications between CECO and NRC.

October 1983 Loss of secondary containment integrity.

October 1983 Enforcement conference on and civil penalty issued for an unsecured vital area ($10,000).

November 10, 1983 Management meeting to discuss potential .

enforcement actions with respect to Engineered Safety Features (ESF) reset problems and an inoperable primary containment isolation valve.

November 21, 1983 Enforcement conference on Engineered Safety Features (ESF) reset and an inoperable containment isolation valve.

November 28, 1983 Confirmatory Action Letter (CAL) issued to confirm licensee commitments with respect to accelerated leakage rate testing of feedwater check valves and qualification of valve soft seats following a series of leak test failures.

December 16, 1983 Unit 2 low power license issued.

January 24, 1984 Management meeting to discuss concerns associated with personnel errors which resulted in degradation of the secondary containment on November 10-15, 1983.

February 28, 1984 Management meeting to discuss deficiencies in the submittals regarding ESF reset functions.

March 23, 1984 Unit 2 full power license issued.

June 22, 1984 Management meeting to discuss concerns

• surrounding RWCU isolation functions for temperature and differential flow being inoperable when the system not isolated.

September 7 -1984 Management meeting to discuss regulatory improvement and enhancing two way communications between CECO and NRC.

September 11, 1984 Enforcement conference for exceeding Limiting Condition for Operation (LCO).

September 1984 Loss of shutdown cooling due to a valve failure.

October 1984 Failure to control the status of the standby gas treatment system thereby degrading secondary containment integrity. This resulted in an enforcement conference and a S25,000 civil penalty.

December 7, 1984 Enforcement conference on violation of Technical Specification 3.6.5.3 and the continuing problem of control room operators being inattentive.

February 20, 1983 CAL issued in confirmation of licensee _

commitments regarding misaligned safety systems.

March 7, 1985 Management meeting to discuss the licensee's

• regulatory improvement program status.

March 1985 Three examples of loss of shutdown cooling due to personnel errors.

May 28, 1985 Enforcement conference on circumstances surrounding miswiring of Trip System B for the automatic depressurization system which resulted in an LC0 being exceeded and continued personnel errors by maintenance personnel at the site.

June 5, 1985 All three divisions of emergency core cooling were rendered inoperable simultaneously with degraded secondary containment integrity.

June 17, 1985 CAL issued in confirmation of licensee commitments regarding improperly installed safety related modifications which degraded emergency core cooling systems.

June 19, 1985 CAL issued in confirmation of licensee commitments regarding improperly installed residual heat removal isolation switches.

June 24, 1985 Conference with Management representatives of CECO to discuss events involving the loss of all Emergency Core Cooling Systems from June 5-10, 1985 at LaSalle.

June 24, 1985 Management meeting at LaSalle to discuss the ongoing regulatory improvement program for Commonwealth Edison Plants.

July 16, 1985 Management meeting to discuss additional aspects of the licensee's regulatory improvement program.

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June 29, 1985 -

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CAL issued in confirmation of licensee commitments regarding uncontrolled security badges.

September 17, 1985 Enforcement conference to discuss the circumstances of the uncontrolled security badges found at the site refuse dump in August 1985. -

November 22, 1985 Letter issued by Region III pursuant to 10 CFR 50.54(f) requesting information to support a determination as to whether the LaSalle County Station operating licenses should be suspended, modified, or revoked based on failure to resolve equipment problems, ineffective planning and control of site activities, excessive personnel error rate, and failure of the Commonwealth Edison Regulatory Performance Improvement Plan instituted in February 1983 to produce meaningful performance improvements at LaSalle County Station.

March 17, 1986 Management meeting to discuss snubber failures.

March 26, 1986 Management meeting to discuss progress on the 10 CFR 50.54(f) letter.

April 30, 1986 Management meeting to discuss progress on the 10 CFR 50.54(f) letter.

May 9, 1986 Reactor scram on low water level. Licensee failed to adequately evaluate the fact that water level fell below the allowable scram point before the scram occurred.

May 12, 1986 Management meeting to discuss a March 19, 1986 valving error.

June 1, 1986 Reactor water level fell below the allowable automatic scram setpoint and no automatic reactor scram occurred.

June 2, 1986 CAL issued in confirmation of licensee

- commitments regarding a Unit 2 reactor water level transient where reactor scram did not occur as expected.

June 2, 1986 Augmented Investigation Team dispatched to the site to investigate the June 1, 1986, apparent failure to scram at the required water level.

June 12, 1986 EDO issued letter to CECO Chief Executive Officer expressing need for upgrade in performance and requesting personal action to improve operational and management performance.

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SALP RATINGS 4 Functional Area Cycle 3 4 5 Plant Operations 2 3 3 Radiological Controls 2 2 2 Maintenance 1 2 3

, Surveillance 3 2 3 Fire Protection 2 2 1

Emergency Preparedness 2 2 2 Security 3 2 2 Refueling 1 1 -

Quality Assurance / - 2 3 Administrative Controls l

Licensing Activities 2 2 2 L

Note:

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SALP Cycles 1 and 2 encompassed construction and pre-operational activities.

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- FORT ST. VRAIN

Background

The Fort St. Vrain reactor plant was licensed to operate on December 21, 1973.

The plant was initially taken critical on January 31, 1974, and generated electrical power for the first time on December 11, 1976. On July 1, 1979, Fort St. Vrain was declared to be in commercial operation. Fort St. Vrain is a high temperature gas cooled reactor (the only plant of this design in the United States).

Sumary of Management Problems and Recent Operating History For several years, NRC management has been concerned over the effectiveness of the management of the Fort St. Vrain facility. This concern was first expressed in the Systematic Appraisal of Licensee Performance (SALP) report for the period ending September 30, 1983. In June 1984, the licensee had a reactor trip from low power. During this reactor trip, six of 37 control rod pairs failed to insert automatically. The reactor did shutdown, however, and the six rod pairs were manually driven in. The reactor remained shutdown while all control rod drive mechanisms were refurbished. As a result of this event, a-special assessment of the Fort St. Vrain facility was made by a team from Region IV and the Office of Nuclear Reactor Regulation. This special assessment was documented in a report dated October 1984. The special assessment confirmed the previously identified problems with licensee management and recommended an indepth, third party audit of licensee management structure and performance.

The licensee contracted with the NUS Corporation to perform this audit. A meeting was held between the NRC, the licensee, and NUS representatives in November 1984 to discuss the NRC assessment report and the identified management

. problems. One of the principal objectives of this meeting was to assure that the NUS audit would not be limited to only those issues highlighted by the control rod drive event.

As a result of this audit, the licensee developed a nuclear Performance Enhancement Program (PEP). This program was developed in March 1985 and was also presented by the licensee in their response to the SALP report for the period ending February 28, 1985.

PEP is a broad-based, open-ended program to upgrade performance at all levels.

The licensee's original schedule to complete the program was the end of 1986.

The licensee has added new tasks to the original PEP and has provided the staff with quarterly status briefings on the program.

The Fort St. Vrain plant remained shutdown until the late summer of 1985. It was then allowed to operate at icw power (highest power level was 8%) to keep the reactor core dry (i.e., free of oxidizing moisture). During this period, ,

the licensee discovered problems with the qualification of equipment and  !

components. This contributed to the decision to only allow low power operation.

On November 26, 1985, the Commission authorized operation up to power levels of 35% until May 31, 1986. This was bared on the staff's acceptance of the licensee's analysis that there would be no hazard to the public from an i

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equipment qualification component failure resulting from a high energy line break at 35% power or below. On May 31, 1986, the licensee shut down to make equipment qualification modifications.

In November 1985, the corporate officer responsible for Fort St. Vrain was relieved of duties. The reported reason for this removal was not related to Fort St. Vrain activities. The President of the company assumed the Vice President's duties for Fort St. Vrain. On July 1, 1986, a new Vice President for Nuclear Operations reported for duty. Although the Chief Executive Officer (CEO) for the licensee has a strong background in high temperature gas reactor technology, the demands on his time caused by the multiple responsibilities are considered to have had a slowing effect on the licensee's action to revamp management control of Fort St. Vrain. The new Vice President for Nuclear Operations has a very strong ba'ckground in management and nuclear matters; he recently retired as the president of a major division of Rockwell International.

The latest SALP report, which is for the period from March 1,1985, through May 6, 1986, shows that some management problems continue to exist, but the SALP Board also found uptrends in several areas. Another SALP will be conducted in the Spring of 1987 after completion of the current outage to determine if these uptrends have been sustained.

The unique design of the Fort St. Vrain plant imposes special challenges on

• the management of Public Service Company of Colorado. As a high temperature gas reactor in a national framework of light water reactor regulation, the plant suffered because of the increased regulatory attention given to the light water reactors in the aftermath of TMI-2. The stable design features and low risk to public health and safety inherent in its design did not make it a candidate for extended staff scrutiny. The June 1984 control rod drive event changed.this, and staff attention was suddenly focused on this plant. The licensee has been essentially a passive participant in the industry efforts to upgrade performance following TMI because these programs were primarily directed toward light water reactors.

In summary, the management problems at Fort St. Vrain result from or have been exacerbated by:

A research reactor mindset

- Poor inter- and intradepartmental communications

- A weakness in corporate oversight that went undetected and uncorrected for a prolonged period

- A deteriorating QA department that was not recognized by management even though clearly identified by decreasing SALP ratings These deficiencies were manifested as material and operational problems, which have resulted in the plant being either shutdown or restricted to low power operation for over 2 years.

The NRC and P r have had FSV management issues under discussion for some time.

These discussions began with the management meeting for SALP III in December 1982, when the management control over the areas of plant operations and design changes were identified for additional PSC attention. Licensee management promised and implemented some actions to improve performance but there was no apparent turnaround. In July and August 1984, a special assessment was initiated by NRR and RIV as a result of the control rod drive failure in June 1984 The report of 'the special assessment was issued in. October 1984, and a special management meeting was held in November 1984, during which NRC management insisted on demonstrable change. Shortly thereafter, the licensee developed and implemented the Performance Enhancement Program (PEP). Since the initiation of the PEP in March 1985, quarterly meetings have been held with the licensee to review the progress of the program.

An enforcement conference was held with the licensee on June 6, 1986, to discuss security violations. As a result, a civil penalty of $65,000 was assessed on July 7, 1986.

On May 9, 1986, an enforcement. conference was held to discuss the violation of a power limit that occurred on May 6,1986. A civil penalty of $75,000 was assessed on July 7, 1986.

A meeting has been scheduled with licensee management for August 5,1986, to-discuss the results of SALP V (period ending May 6, 1986) and the concerns of the SALP Board and NRC management.

An enforcement conference will be held in late July 1986, to discuss issues

related to QA audits and corrective action.

Significant Event Chronology November 1980 Management meeting to discuss the results of this first SALP. Security Safeguards was rated 3. All other functional areas were rated 2.

October 1981 Management meeting to discuss the results of the SALP for the period July 1, 1980 through June 30, 1981. Training and QA were rated 1. Operations was rated 3, and all other functional areas were rated 2.

December 1982 Management meeting to discuss the results of the SALP for the period September 1, 1981 through August 31, 1982.

Maintenance, Fire Protection, Licensing Activities, l Training, and Quality Assurance were rated 1. Operations was rated 3. All other functional areas were rated 2.

January 1984 Manage: rent meeting to discuss the results of the SALP for the period September 1, 1982 through September 30, 1983.

Emergency Planning was rated 1. Operations, Licensing Activities, Design Control, and Management Control were rated 3. All other functional areas were rated 2.

Confirmatory Action Letter issued to not restart until June 1984 -

NRC authorization. This was in response to the event where six rod pairs failed to scram on June 23, 1984.

July-August 1984 Joint NRR/RIV special assessment of Fort St. Vrain Nuclear Generating Station.

October 1984 Special assessmeni report issued.

November 1984 Management conference to review the major conclusions of the October 1984 special assessment report by NRC.

December 1984 - Series of meetings and technical reviews concerning June 1985 corrective ' actions identified in October 1984 special assessment report including:

Control Rod Drive Operating Assembly (CRD0A) Refurbishment Circulator Repair Water Ingress _

Prestressed Concrete Reactor Vessel (PCRV) Tendon Corrosion Technical Specification Upgrade

Third Party Management Study ,

February 1985 Management meeting to discuss security matters.

April 1985 Enforcement conference to discuss maintenance QC with respect to CRD0A refurbishment.

June 1985 Quality assurance / equipment qualification outage / fire protection team inspection. Found QA program audit and timely corrective action followup weakness. EQ outage work, and fire protection appeared satisfactory.

May 1985 Management meeting to discuss the results of the SALP for the period October 1,1983 through February 28, 1985.

Radiation Protection arid Refueling were rated 1.

Operations, Maintenance, Licensing Activities, Design Control, and Quality Assurance were rated 3. All other functional areas were rated 2. Licensee also presented its new performance enhancement program (PEP).

July 1985 Confirmatory Action Letter allowing operation up to 15*.

power.

July 1985 Regulatory effectiveness review of Security Safeguards.

Several weaknesses were identified.

August 1985 Performance appraisal team inspection conducted by IE.

Inspection examined Operations, Surveillance Program, and Maintenance. Operations weaknesses were identified.

September 1985 Confirmatory Action Letter issued allowing power operation up tu 8% for 45 days not to extend beyond November 30, 1985.

October 1985 Management meeting to discuss PEP status.

November 1985 -

~~

Commission memorandum and order authorizing power up to 35% until May 31, 1986.

January 1986 Enforcement conference on security deficiencies found 4 in regional inspections conducted in October and November 1985.

Jantary 1986 Management meeting to discuss PEP status.

April 1986 First of two-part maintenance team inspection. Found procedures being rewritten. Followup inspection scheduled for Fall 1986. ,

May 1986 Enforcement conference for violation of 35% power limit specified by NRC memorandum and order of November 26, 1985.

1 Management meeting to discuss PEP status.

June 1986 Management meeting to discuss requalification training.

July 1986 Escalated enforcement and Civil Penalties issued for security deficiencies and overpower event.

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- - - SALP RATINGS FUNCTIONAL AREA SALP PERIOD Initial 9/1/80- 9/1/81- 9/1/82- 10/1/83- 3/1/85-8/31/81 8/31/82 9/30/83 2/28/85 5/6/86 Operations 2 3 3 3 3 2 Radiation Protection 2 2 2 2 1 1 Maintenance 2 2 1 2 3 3(a)

Surveillance 2 2 2 2 2 2 Fire Protection 2 2 1 (x) 2 1 Emergency Planning 2 2 2 1 2 3 Security 3 2 2 2 2 3(b)

Refueling 2 2 (N/A) 2 1 (x)

Licensing Activities (x) 2 1 3 3 3(a)

Training 2 1 1 2 2 2 Outages (x) (x) (x) (x) (x) 3 Design Control 2 2 2 3 3 (x)

Quality Assurance 2 1 1 2 3 3 Management Control 2 (x) (x) (3) (x) (x)

Notes:

(a) An upward trend was noted toward the end of the period.

(b) An inspection subsequent to the SALP period found a turn around in management attitude. The licensee was aggressively pursuing systems up-grade with tangible observable progress evident.

(x) Not a separate category in this report.

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! .- RANCHO SECO

Background

The Rancho Seco Nuclear Generating Station was licensed to operate on August 16, 1974. The plant was initially critical on-September 16. 1974, and generated electrical power for the first time on October 13, 1974. On April 17, 1975, Rancho Seco was declared to be in commercial operation.

Rancho Seco is a pressurized water reactor of the Babcock & Wilcox (B&W) once through steam generator design.

Summary of Management Problems'and Recent Operating History The December 26, 1985 loss of integrated control system power / overcooling transient is the focus of current NRC concern about Rancho Seco. This event demonstrated weaknesses of SMUD in engineering and in quality assurance (particularly procedural adequacy), and deficiencies in operator training and performance.

There are many reasons for the current management problems, of which two seem most important. Each of these started to turn around in mid-1984; this -

turnaround accelerated in 1985, and in 1986 is continuing.

a. SMUD's traditional practice of doing the least amount of corrective action which the NRC would accept, and to do so as slowly as the NRC would accept;

b. SMUD's overall pervading lack of a self-critical attitude which has' led to poor performance in its engineering program, token performance in quality assurance, and minimal training activities.

SMUD historically had a strong and capable operating group, but as the plant systems and equipment continued to age (Rancho Seco became operational in 1975) stronger engineering, OA, training and other support programs needed to reduce challenges to the cperations staff failed to keep pace.

The consistent NRC regulatory approach which has been tried since mid-1984 has been heavy regional inspection and management involvement to insist on rising standards for SMUD. Management meetings, enforcement meetings, civil penalties, outside management audits, 50.54(f) letters, and direct ED0/ Commission involvement have occurred in a steady escalation throughout this period. The result has been a perception that SMUD has improved organizationally in most areas. However, Rancho Seco has been shut down to ,

such an extent that the effectiveness of the changes cannot be definitely known. Moreover, most senior managers in the nuclear organization are new to their jobs, and are untested in them. Currently, SMUD is heavily reliant on 1 interim contractor managers (from the Management Assistance _ Corporation).

These people appear competent, but are not expected to remain at SMUD more than a year or two. On July 1, 1986 the General Manager for SMUD resigned in conflict with the elected Board of Directors of SMUD. He had been installed only teri months previously as part of a SMUD program to improve their ]

performance. ,

l

Future NRC actions will hinge upon the thoroughness of the restart program SMUD intends ~fo submit to the NRC in July, 1986 and the successful permanent restaffing at SMUD.

Significant Event Chronology April 1980 Civil Penalty ($25,000). Inoperab.ility of high pressure injection system cross connecting piping Jor twenty days.

June 1981 Emergency Preparedness Appraisal Team inspection. Twenty-one significant deficiencies, 28 improvement items and one violation.

August 1981 Management meeting to discuss EP Appraisal findings, "Immediate Action Letter" issued.

June 1982 Civil Penalty ($120,000) Inoperability of "B" Diesel Generator for twenty-nine hours, Inspection (50-312/82-08) _

March 1983 Inspection of emergency preparedness identified two violations and several deficiencies identified by FEMA. Letter issued pursuant to 50.54(s)(2)(ii) (120 day letter) requiring . i corrections within 120 days of plant shutdown. Deficiencies were promptly corrected.

July 1983 Management meeting to discuss several radiation protection and one emergency preparedness issue (workers responsibilities, internal audits, use of escorts and one shift supervisors qualification in EP).

November 1983 A Performance Appraisal Inspection (50-312/83-25) found significant weaknesses in committee activities, quality assurance audits, plant operations, non-licensed training and procurement. Resulted in eight Severity Level IV violations.

Many of these were similar to weaknesses identified in the 1980 Parformance Appraisal Inspection. These finding's were reviewed with SMUD management.

January 1984 The Systematic Appraisal of Licensee Performance for October 1, 1982-November 30, 1983 identified plant operations, surveillance, and licensing activities as only minimally satisfactory. A management meeting to discuss these results was held on April 23, 1984.

March 1984 An " Alert" Emergency Action Level was declared following a main generator hydrogen explosion and loss of non-nuclear instrumentation. Subsequent NRC inspection determined event was due to equipment failure compounded by operator oversights.

May 1984 Region V held public meeting with SMUD Board of Directors to review problems with SMUD performance identified in the 3/83, 11/83 and 1/84 inspection above.

l June 1984 - Auxiliary boiler prematurely opened by two plant mechanics for maintenance; both later died from burns. Falls outside NRC regulatory authority.

August 1984 Region V met with SMUD Board of Directors and SMUD managerent for second time 'a public meeting concerning poor and apparently deteriorating performance record of SMUD.

September 1984 Licensee commenced extensive contractor appraisal of SMUD performance in response to August NRC review with Board of Directors. Contractor is LRS Associates. Enforcement Conference was held on radiation protection program weaknesses.

October 1984 Severity III violation issued to licensee for radiation protection problems during outage. No CP due to licensee's comprehensive and effective corrective actions.

November 1984 LRS Associates issues detailed report with 119 wide ranging recommendations for licensee's performance improvement. Region V closely begins close tracking of licensee followup actions on LRS recommendations.

January 1985 Regional Administrator met with President of SMUD Board of' Directors to urge prompt and effective resolution of LRS report recommendations.

Follow-up inspection (50-312/85-03) related to the liquid radioactive effluent issue found the licensee's land use census to be inadequate. In addition, one Severity level IV violation was issued for failure to collect an environmental air sample.

! Region V Team inspection (50-312/85-01) identified significant weaknesses in management control of contractor design work and field modifications.

March 1985 Seccnd Region V meeting with SMUD board members and staff to review licensee progress in implementing LRS recommendations.

June 1985 Third Region V meeting with SMUD board members and staff to t review licensee progress in implementing LRS recommendations.

June 1985 Inspection (50-312/85-19) identified two Severity Level III violations in the control of engineering work and in qualit control of modifications ($50,000 Civil Penalty Issued .

July 1985 Region V and representatives of IE and NRR met with the SMUD Board of Directors to discuss improving the performance of Rancho Seco. Areas covered were the concepts of using standards of excellence, technical adequacy, facing facts, respect for radiation, training, responsibility, and capacity  ;

to learn from experience. l l

August 1985 _ Small primary piping leak discovered during plant startup.

Region issues Confirmatory Action letter (dated August 26) which requires plant be kept shut down until critical prior systems are reinspected and management improvements made. The letter requires that SMUD would enhance management involvement in plant, improve non-licensed operator performance and more closely control maintenance as well as reinspect piping systems for conformance to IEB 79-14 activjties.

September 1985 SALP appraisal for December 7, 1983 - May 31, 1985 issued.

Some improvements noted, with engineering and construction, radiological controls, quality programs, and training

identified as requiring more effort.

I October 1985 Problems with feedwater and condenser identified during plant startup. Confirmatory Action Letter issued on 10/4/85 to keep plant shut down until extensive reviews of secondary plant '

were completed.

November 1985 Enforcement conference related to safeguards Inspection -

(50-312/85-33) which resulted in a Severity Level III violation. ($25,000 Civil Penalty).

December 1985 Loss of Integrated Control System (ICS) Power event (December 26,1985) followed by Region V Augmented Investigation and NRC Incident Investigation Team (IIT) Inspection.

Confirmatory Action Letters issued by Region V to ensure Rancho Seco remains shutdown until all regulatory concerns are satisfactorily resolved. Plant still shutdown.

February 1986 Region V began an inspection to identify all enforcement actions related to the IIT report (NUREG-1195), and to identify all restart issues (Inspection 50-312/86-07). Inspection completed May, 1986.

A special inspection of the licensee's emergency plan / radiological controls implementation during the December 1985 event identified four apparent violations (which are presently being considered for escalated enforcement).

March 1986 EDO assigned detailed NRC responsibilities for restart of Rancho Seco. SMUD/NRC meeting including SMUD board members to discuss corrective action plans.

Enforcement conference related to safeguards Inspection (50-312/86-04) which resulted in a Severity Level III violation.

April 1986 SMUD met with NRC staff to outline " Performance and Management Improvement Program" to be implemented prior to plant restart.

i

May 1986 ~'

An Enforcement Conference was held to discuss SMUD failure to establish, implement, and maintain required procedures associated with the December 26, 1985 transient. Enforcememt action is pending.

June 1986 An Enforcement Conference was held at Region V to discuss with the licensee the emergency planning / liquid effluent inspection findings. The licensee presented significant organizational changes and specific corrective action goals toward eventual restart. Enforcement action is pending.

July 1, 1986 Escalated enforcement action taken for the December 26, 1985 loss of integrated control system power and overcooling transient.

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_ . _ SALP RATINGS I

RPT

• ASSMT. PERIOD

• OPS *RADCON*MAINT*SURV* EP

• FP *SEC*REFL* QP *LIC*TRA!h*

• 1* 2* 2*2* 2* 3*N* N

• 08/80

• 04/15/79 - 04/15/80

• 2

• 2

• 2 04/82

• 06/06/80 - 06/30/81

• 2

• 2 2 2* 2* 1*2* 1* 2*N* N i

03/83

• 07/01/81 - 09/30/82

• 2

• 2 2

• 2* 2* 2*1* 1* N*1* N 06/84

• 10/01/82 - 11/30/83

• 3

• 2

• 2

• 3* 2* 2*1* 1* h*3* N 11/85

• 12/01/83 - 05/21/85

• 2

• 3

• 2 2* 2* 2*1* 1* 2*2* 2

• i l

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- _ _ . _ . . _ . . _ , _ - _ _ - - _ . _ . _ _ _ _ , , ~ , . _ _ . _ _ _ _ , , . _ _ . _ , , _ , . , . . , _ . _. - . . - - . . . _ , , . , , _ _ _ . , - . . _ , . , _ . , . . , _ , , - - _ _ . , _ , . .

t QUESTION'6. What are the lessons learned from NRC's Systematic

, Assessment of Licensee Performance program?

ANSWER.

The NRC has gained a great deal of experience from the Systematic Assessment of Licensee Performance (SALP) program.

There is a short description below of the SALP process and the changes in the program which have been made based upon lessons learned.

Over the past six years the SALP evaluations have proven to be a useful mechanism for periodically integrating available staff information on overall licensee performance. The information contained in NRC SALP reports are also of considerable value to utility management. SALP evaluations are normally conducted at 12 to 18 month intervals at j individual plants. Various functional areas of licensee operations are rated. These ratings reflect licensee performance and are used as one basis for determining the proper NRC-level of inspection effort during the period before the next SALP evaluation.

The functional areas covered by NRC SALP evaluations have been expanded. For instance, new areas subject to SALP evaluations l

4

i QUESTION _6. (Continued) ~~

include: training; outage; quality control and administrative programs. In order to improve the objectivity of NRC SALP reports, quantitative data such as the number of Licensee Event Reports, numbers of violations of MRC regulations, civil penalties, number of reactor scrams, number of licensing actions taken and completed are included and analyzed.

T5e NRC is also considering the desirability of adjusting the

frequency of the SALP evaluations. Plants with relatively more identified operational problems would receive more frequent NRC inspection, vis-a-vis plants with better performance.

Additional improvements in the NRC SALP program may be

desirable. For instance, at this time the SALP focuses more i on the symptoms rather than identification of the root causes of plant operational problems. The SALP process may give an

incomplete or even erroneous sense of confidence in the safety I of a plant. In addition, the SALP process does not always provide a timely indication of emerging plant operational i

1 problems as would be desirable in order to detect and take corrective regulatory action. Consequently, to supplement the SALP program, the NRC is considering whether a set of plant operations performance indicators could be helpful to periodically monitor plant performance between SALP evaluations, These data could form a basis for prompt and I

I l

QUESTION 6 3 (Continued) 1

' corrective regulatory action when significant plant safety

i. problems are identified. ,

I l Lately, the SALP process has developed within the staff an i

j increased awareness and appreciation for the key role which i

{ licensee management performance plays in ensuring safe nuclear

operations.

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1 I 3

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QUESTI0N 7. Members of the Subcommittee have criticized the NRC's failure to correct known management weaknesses and design defects prior to their contributing to the June 9, 1985, loss of feedwater accident at the Davis-Besse nuclear reactor. The Subcommittee requested that NRC conduct 'an internal investigation of NRC's responsibility for the accident. Now that this investigation is complete, please inform

~

i the Subcommittee of what conclusions can be i

j made and what changes have or will be made in ,

I NRC's management, i

l ANSWER.

An independent Ad Hoc Group was established by the Commission in January, 1986, to review issues subsequent to the June 9, 1985,

, loss of feedwater event at the Davis-Besse Nuclear Power Station.

The Ad Hoc Group completed their study covering: (1) pre-event

, interactions between the licensee and NRC concerning reliability 1

of the auxiliary feedwater and associated systems; (2) pre-event i

probabilistic assessments of the reliability of plant safety

! systems, NRC's review of them, and their use in regulatory decisionmaking; (3) licensee management, operation and 1

maintenance programs as they may have contributed to equipment i

I

CUESTf0N 7. (Continued) ~

failures and NRC oversight of such programs.; and (4) the mandate, capabilities of members, operation, and results of NRC Davis-Resse i

i incident Investigation Team (IIT), and the use to which its report was put by the regulatory staff. At the' request of the Commission, i

the NRC Executive Director for Operations has directed that a coordinated review of the report by all offices be performed and that an action plan be developed by July 18, 1986. Conclusions and recommendations concerning what changes should be made in NRC

! management, if any, will not be finalized until this review has been completed by the staff and acted on by the Commission.

I j Commissioner Asselstine adds:

i Although the Davis-Besse Ad Hoc Review Group Report provided some useful insight into NRC staff actions concerning the

! reliability of the Davis-Besse auxiliary feedwater system, I j was disappointed in its failure to identify the root causes of

'i The report also did not the staff's performance in that case.

l address the key issue of the role of licensee management in the weaknesses and failures identified as a result of the June 9, 1985 event. As a result, I believe that the Peview Group I effort was not as useful as it might have been.

j

)

4

/

QUESTION 8. Although the Commission has variously concluded that the risk of a core melt accident could be as high as 12 or 45 percent in the next 20 years ,

at a U.S. plant, the NRC has informed the ,

Subcommittee that this risk is deemed acceptable because of the ability of containment buildings i

to prevent a major radioactive reluase.- Given a core melt accident, what does the Commission '?3 believe is the maximum acceptable' probability of a subsequent failure of the conttinment building inordertoreachafindingthatpublicheal[th ,

I

and safety can and will be protected? '

1 ANSWER.

i The Commission currently has not specified a maximum acceptable probability of containment building failure given a core melt f accident. The Commission recently adopted a Policy Statement

! on Safety goals for the Operation of Nuclear Power Plants, which is being readied for publication in the Federal Register.

Guidance concerning acceptable containment failure probabilities 1

1 is being developed in light of that Policy Statement, i s a

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1. - . , - , --. . ..- . ~ - - - . .. , - - - . . - . . . . - , _ . - , - . _ - , _ , , _ . _ . - , . _ _

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QUESTION 8.- (Continued) s Two provisions of the Policy Statement bear directly on the ouestion posed:

1. The Commission di*ects the staff to' develop guidelines for j

regulatory implementation for the Commission's review and approval. As part of its direction to the staff included in l .

the Policy Stateme'nt, the Commission directs that this guidance would be based on the following general performance

guideline which is proposed by the Commission for further i

staff examination:

l

" Consistent with the traditional defense-in-depth approach and the accident mitigation philosophy i

requiring reliable performance of containment 6

systems, the overall mean frequency of a large I release of radioactive materials to the environment

from a reactor accident should be less than 1 in

] 1,000,000 per year of reactor operation."

i I

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--e y - - - -m -.g ., - . , . . . - . _ . - _ ~ . - - , - y, . . .- -.-r-- _. -- -- . _, _ ., . . _ _ - - _ - ,, - - . . - -

00ESTION_8. (Continued)

2. The Policy Statement includes the following statement:

" Severe core damage accidents can lead to more t

serious accidents with the potential for life-threatening offsite releases of radiation, for evacuation of members of the public, and for contamination'of public property. Apart from their health and safety consequences, such I

accidents can erode public confidence in the safety of nuclear power and can lead to further instability and unpredictability for industry. ,

In order to avoid these adverse consequences, the Commission intends to continue to pursue a regulatory program that has as its objective providing reasonable assurance, giving appropriate consideration to the uncertainties involved, that a severe core damage accident will not occur at a U.S. nuclear power plant."

These two provisions between them will form a principal part of 4

the basis for determining containment performance objectives.

i t

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a. , ~ ~ - . -, -

QUESTION 8. (Continued) ,

Commissioner Asselstine adds:

I believe that the Commission should specify minimum contain-ment performance standards. I proposed such a standard -- that containments perform in a manner that would ensure with high ccnfidence that no more than 1 in 100 core meltdown accidents result in a large offsite release of radiation -- as an addition to the Commission's Safety Goal Policy Statement.

This standard, when coupled with the Commission's commitment to

~

provide reasonable assurance that a severe core damage accident

will never occur at a U.S. nuclear power plant, would provide a ,

strong regulatory commitment to safe plant operations, including a balance of accident prevention and mitigation measures. I also supported a similar standard proposed by Commissioner Bernthal. Both his proposal and mine failed to obtain majority support within the Commission. Such a standard is needed, in my view, to help ensure that an accident having Chernobyl-type consequences does not happen in this country.

4 4

0

,n- ,-- - -

,nn ,

QUESTION 9, - NRC's chief safety officer has reportedly told the industry that he is concerned about Mark I containment buildirgs because given a core melt accident they have a 90 percent chance of failure. Please answer the following:

(A) Is a 90 percent chance of failure in the event of a core meltdown an acceptable failure rate?

ANSWER.

The NRC holds the position that the likelihcod of core melt accidents in any plant should be very low and, in addition, that there should be substantial assurance that the containment will mitigate the consequences of a core melt should one occur in order to ensure low risk to the public. It is not merely a question of having low risk but of having as well the defense-in-depth assurance of combined protection by prevention and mitigation. This concept was identified i n the Commission's Policy Statement as noted in response to Question 8. However, a number of regulatory actions have been taken, as outlined below, which will reduce the probability of containment failure for Mark 1 containment buildings.

I

- - +m m -,-

QUESTION 9. (Continued The recent -expression of concern cited in Question 9 was expressed with the intention of encouraging utility owners of BWR MK I plants to give priority to the continuing need for ensuring MK I containment integrity. The 90 percent chance estimate was a rough approximation of the results of the WASH-1400 assessment published in 1975. That assessment was based on the Peach Bottom plant as it stood at that time, and on the operating and emergency procedures of that time. The results, which indicated a virtual certainty of a fairly large release with every core melt, also showed many circumstances where lesser accident -

conditions could lead to overpressure failure of containment --

~

which failure in turn actually caused the core melt. The risk dominant accident sequences were transients such as anticipated transients without scram (ATWS) in which excessive energy is released to containment or other transients with an associated scram where containment heat removal capability was lost. It is important to note that the WASH-1400 analysis still found that the overall risk of the BWR was equivalent to the risk of the PWR even though the PWR containment was estimated to provide greater mitigation of core melt consequences. This was because WASH-1400 estimated a lower likelihood of core melt in the BWR due to its diverse and flexible water supply systems.

QUESTION 9. (Continued ~

Since the TMI accident a great deal has been done and is still in progress to lower the risk of the BWR MK I plants, both by suppressing the likelihood of core melt accidents and by ensuring consequence mitigation by the containment. , Improved training and symptom-based procedures for plant operators have been adopted.

These are especially effective in BWRs because of the inherent I

flexibility of the plant systems. One of the major risk contributors, ATWS, has been substantially reduced by NRC rule I mandated improvements. Since further studies showed that the BWR suppression pool water had a much greater capability to scrub releases than was recognized by WASH-1400, a filtered vent containment strategy was adopted. While within the design basis' envelope, the BWR containment remains sealed. If, through some beyond design basis failure, the pressure threatens to cause uncontrolled failure of containment, the strategy calls for venting the containment from the wetwell, above the pool, so that releases pass through the water where essentially all the major constituents except the noble gases are removed. Containment venting procedures are being developed and implemented at many BWRs. Some small design changes may be necessary to implement or improve the ability to avert containment failure from overpressure or other failure modes.

l l

QUESTION 9. (Continued Both the NRC- and the industry are active in this process through our independent work and interaction with the Industry Degraded Core (IDCOR) group and the owners directly.

Because of the continuing work and the incomplete implementation, it is not possible to give a representative MK I containment performance figure at this time but, consistent with the NRC Severe Accident Policy Statement, the current process for evaluating and improving existing plants is expected to achieve conditions where a MK I containment provides substantial -

assurance of mitigating the consequences of a core melt should one occur. Further, with adoption also of the many ways to reduce the likelihood of core melt, the risk of BWR MK I plants is low.

l l

9-- ~ (B) Does the NRC believe that Pilgrim's QUESTION containment building is more vulnerable to failure given a core melt accident than other types of containment buildings in use at other plan.ts?

AHSEER Studies of severe accidents for many years have indicated that i

BWR MK I containments such as the Pilgrim plant has are more ,

vulnerable to failure given a core melt than some other types of

' I containment buildings due to smaller relative size, compact geometry, etc. Nevertheless, the work referred to in response to 9A above indicates that substantial assurance of core melt consequence mitigation can be achieved with the BWR MK I containment.

J As to Pilgrim specifically they, like other plants of this type, are in the process of~ developing and implementing the necessary improvements. For example, emergency operating procedures up through Revision 2 of the BWR Emergency Procedure Guidelines have be'en implemented; this includes containment venting. Two of the three elements of the ATWS improvements have been made. But the Individual Plant Evaluation for severe accidents has'not yet been conducted so no specific risk estimate can be made at this time

. for the Pilgrim plant.

l

QUESTION 9: (C) Rank the 17 plants with management problems in~ descending order of the estimated containment failure rate.

[

ANSWER.

I It is not feasible to do such a ranking on a plant by plant basis i

meaningfully due to the uncertainties inherent in current .

predictions of containment behavior during severe accidents, and in plant specific design differences. . i l

i i

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1 - --. _-__.-_ .

M --,+- ,

QUESTION 9 (D) Is the NRC considering any new requirements or backfits relating to containment issues?

ANSWER.

As indicated in the answers to parts a through b of Question 9, the NRC expects to consider new requirements and backfits in the implementation of its severe accident policy.

O

f*

1982 Evaluation Pilgrim Nuclear Power Station i

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EVALUATION of 1

i PILGRIM NUCLEAR POWER STATION 1

1 Boston Edison Company 1

I 1

l January 1983 S

e G

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PILGRIM (1982) l 3

Page 1 l

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SUMMARY

INTRODUCTION The Institute of Nuclear Power Operations (INPO) conducted an evaluation of Boston Edison Company's (BECO) Pilgrim Nuclear Power Station during the weeks of October hl 18 and 25,1982. The station is located on Cape Cod Bay near Plymouth, Massachusetts.

Pilgrim is a single-unit, 655-megawatt (electrical) General Electric boiling water

_ reactor plant that began commercial operation in December 1972.

4 PURPOSE AND SCOPE INPO conducted an evaluation of site activities to make an overall determination of plant safety, to evaluate management systems and controls, and to identify areas -

needing improvement. Information was assembled from discussions, interviews, obser-vations, and reviews of documentation.

~

The INPO evaluation team examined station organization and administration, oper-ations, maintenance, technical support, training and qualification, radiological pro-tection, and chemistry. The team also observed the actual performance of selected evolutions and surveillance testing. As a basis for the evaluation, INPO used performance objectives and criteria relevant to each of the areas examined; these were applied and evaluated in light of the experience of team members, INPO's observations, and good practices within the industry.

INPO's goal is to assist member utilities in achieving the highest standards of excellence in nuclear plant operation. The recommendations in each area are based on best practices, rather than minimum acceptable standards or requirements. Accord-

' ingly, areas where improvements are recommended are not necessarily indicative of unsatisfactory performance.

DETERMINATION Within the scope of this evaluation, the team determined that the plant is being operated safely by experienced and qualified personnel.

The f ollowing beneficial practices and accomplishments were noted:

There appears to be a strong corporate commitment to improvement of the station.

Operations and maintenance personnel demonstrated a strong sense of responsi-bility for safe and reliable operation of the plant.

Substantial improvements in training are planned and being implemented.

Significant progress has been made in improving plant cleanliness and preserva-tion.

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' i PILGRIM (1982)' l Page 2  !

Improvein~ents'were recommended in a number of areas. The following are considered to be among the most important: l i u . Communications and coordination among personnel need to be improved.

The plant chemistry program needs significant improvement.

The number of plant areas where access is restricted for radiological reasons '

needs to be reduced.

In-place training programs need to be strengthened.

Material and housekeeping conditions in the screenhouse, reactor building corner 1

rooms, and radweste system need to be improved. .

1 Vacancies in the plant staff technical support group need to be filled.

In each of the areas evaluated,INPO has established PERFORMANCE OBJECTIVES and -

supporting criteria. All PERFORMANCE OBJECTIVES reviewed during the course of this evaluation are listed in APPENDIX II.

Findings and recommendations are listed under the PERFORMANCE OBJECTIVES to

. which they pertain. Particularly noteworthy conditions that contribute to meeting PERFORMANCE OBJECTIVES are identified as Good Practices. Other findings describe' conditions that detract from meeting the PERFORMANCE OBJECTIVES. It would not be productive to list as Good Practices those things that are commonly done properly in the industry since this would be of no benefit to BECO or to INPO's other member utilities. As a result, most of the findings highlight conditions. that need improvement.

The recommendations following each finding are intended to assist the utility in ongoing efforts to improve all aspects of its nuclear programs. In addressing these findings and

- recommendations, the utility should, in addition to correcting or improving specific conditions, pursue underlying causes and issues.

As a part of the second and succeeding evaluations of each station, the evaluation team will follow up on responses to findings in previous reports. Findings with response

. actions scheduled for future completion have been carried forward in APPENDIX I to this report. In areas where additional improvements were needed, a new finding that stands on its own merit has been written. Thus, this report stands alone, and reference

, to previous evaluation reports should not be necessary.

The findings listed herein were presented to BECO management at an exit meeting on November 5,1982. Findings, recommendations, and responses were reviewed with BECO management on December 17,1982. Responses are considered acceptable.

To follow the timely completion of the improvements included in th'e responses, INPO requests a written status by May 1,1983. Additionally, a final update will be requested six weeks prior to the next evaluation.

The evaluation staff appreciates the cooperation received from alllevels of BECO.

O I

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i t PILGRIM (1982)

Pqe3 BOSTON EDISON COMPANY Response Summary .

Boston Edison (BECO) concurs with the Institute of Nuclear Power Operations' (INPO) general conclusion that Pilgrim Station is being operated safely by experienced and qualified personnel.

BECO also appreciates the acknowledgement of our strong corporate commitment to improvement of the station. This commitment is embodied in our Performance Improvement Program (PIP) document, which is on file with the Nuclear Regulatory Commission, and our aggressive reorganization of the nuclear organization from the top down. It should be noted that during the INPO evaluation, BECO was in the midst of this reorganization; a certain amount of settling down is needed before focusing on specific weaknesses and making corrections.

BECO also acknowledges that there are areas that can be improved. These areas are as follows:

1. communications and coordination among personnel ,

2. the plant chemistry program

3. in place training programs

4. the number of areas where access is restricted for radiological reasons

5. vacancies in the plant staff technical support group

6. material and housekeeping conditions in the screenhouse, reactor building corner rooms, and radwaste system These areas will De improved by aggressive actions.

BECO has not established specific completion dates in the responses because other performance improvement actions and programs at least partially address many of the recommendations. Additional actions that may be required will be identified and internally fitted into the overall program. BECO will report more fully on the progress of corrective actions and will give projected completion dates for all incomplete actions in a status report by May 1,1983. As the INPO team observed, BECO is involved in a multi-faceted improvement program, and the evaluation provides another useful perspective. Also, BECO has requested, and INPO has agreed to provide, additional assist visits in training and chemistry to supplement the evaluation.

Boston Edison appreciates the efforts of the INPO team and believes their recommen-dations will be helpful in our commitment to improvement of the station.

1 1

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PILGRIM (1982)

Page 4 e INPO COMMENT In recent months, BECO has 25veloped a comprehensive Performance Improvement Program for the Pilgrim Nuclear Station and the supporting nuclear organization. The plan reflects inputs from a number of reviews by outside organizations and demon-strates an aggressive commitment by BECO management.

INPO considers it appropriate for BECO to coordinate response actions to this evaluation into the existing improvement plans. Recognizing the already substantial burden on BECO management, INPO considers it acceptable to delay determination of projected complet!cn dates and some specific corrective actions in order to permit a coordinated approach. BECO has agreed to provide a detailed report on the status of improvements and projected completion dates for all outstanding actions by May 1, 1983.

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PILGRM (1982)

Pqe5

- ORGANIZATION AND ADMINISTRATION

. l STATION ORGANIZATION AND ADMINISTRATION PERFORMANCE OBJECTIVE: Station organization and administrative systems should ensure effective implementation and control of station activities.

Finding The recent reorganization of the plant staff has resulted in

_ (OA.1-1) uncertainty among staff personnel m %4 assignment of re-sponsibDities and accountabDities. Specific responsibilities of some staff groups are still being developed and those for other groups are not clearly defined. Some personnel are assigned temporary responsibilities. As a result, some activities are not receiving appropriate attention.

Recommendation Expedite development of jurisdiction and responsibility statements -

for each staff group and individual position descriptions for each staff position. Inform affected personnel of their new responsibili-ties and the goals of the reorganization effort as soon as possible.

Response BECO will continue to develop responsibility and jurisdiction statements as part of the reorganization and, where position descriptions do not already exist or are changed, the affected

~

personnel will be informed. The reorganization had been in place only six weeks at the time of the evaluation.

Finding Communications hom management to all levels of the plant (OA.1-2) organization need to be improved. Many persons have little confidence in the effectiveness of the recent organizational and management changes. Some supervisors had little understanding of the Performance Improvement Program (PIP) even though they were working PIP action items.

Recommendation Increase efforts to familiarize alllevels of the plant staff with the factors that led to the reorganization, the expected results, and the action or support required from each member of the staff. Use periodic meetings to inform staff members of current PIP progress and to answer questions pertaining to the direction the company is pursuing.

Response BECO has established additional communications channels. These include meetings, instructions, and memoranda that are designed to l l _ communicate between all levels of the organization. Additional specific actions are described in other responses in this report. ,

BECO will continue to communicate the reasons for reorganization  !

i and emphasize our willingness to consider any suggestion to im-prove the organizational structure.

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PILGRIM (1982)

Page 6 ,

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MISSION, GOALS, AND OBJECTIVES PERPORMANCE OBJECTIVE: Station mission, goals, and objectives should be estab-lished and progress monitored through a formal program.

Finding The 1983 nuclear operations goals and objectives need expansion

. (OA.2-1) and need an action plan to assist in monitoring progress toward goals and objectives.

Recommendation Extend the nuclear operations goals and objectives program to include the individuals reporting to the station manager. Develop a

trackable action plan to achieve individual goals and objectives, and periodically assess progress toward objectives.

Response The recommended improvements will be implemented. Action is currently in progress.

~

MANAGEMENT ASSESSMENT AND QUALITY PROGRAMS PERPORMANCE OBJECTIVE: Management should assess station activities to ensure and enhance quality performance of all aspects of nuclear plant operation.

_ Pinding Action is needed to resolve the backlog of ncs eenformance (OA.3-1) reports (NCR) and Operations Review Committee (ORC) follow-up itema.

-~

Recommendation Expedite resolution of the backlog of NCRs and ORC follow-up

_ items. Track resolution of NCRs and ORC follow-up items in a manner similar to that used for quality deficiencies. Ensure that progressively senior levels of management are informed when undue delays in resolution are encountered.

Response BECO agrees and willimplement the recommended improvements, including publication of a monthly status report to senior manage-ment.

• 4-em M-

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- PILGRIM (1982)

Pqe7 Finding A graduated quality program should be applied to important (OA.3-2) activities on selected balance of plant (BOP) equipment. Use of the full nuclear quality program for equipment important to reliability ("R" list equipment) was recently discontinued because the gain in equipment reliability was not commensurate with the administrative burden. However, a substitute quality program for "R" list equipment has not yet been developed.

Recommendation Establish a graduated quality program for BOP equipment that is important from a safety or reliability standpoint. Include appropriate controls to ensure quality of workmanship and materials, including selected inspection points during maintenance, post-maintenance operability tests, and appropriate inspections and tests to enhance plant reliability.

Response BECO agrees that some quality controls should be applied to activities associated with "non-Q" equipment. A policy statement has been issued that addresses management's desire to implement quality requirements on "non-Q" equipment. Specific controls and implementing methods are being evaluated. INPO has agreed to provide some assistance in this area. .

Finding Management assessment programs need to be improved to include (OA.3-3) the followmg:

a. periodic independent effectiveness reviews of selected programs and activities (e.g., modification program, work control system, operating experience review)

I

- b. an audit to ensure that all technical specification require-ments are adequately addressed by surveillance tests, audits, or other routine administrative controls Recommendation Upgrade the quality assurance and quality control programs to include the above elements.

Response The Nuclear Safety Review and Audit Committee is currently developing management review and audit techniques to be used to evaluate program effectiveness for safety-related Pilgrim activi-ties. Implementation of these reviews is expected in 1983.

- BECO will perform an audit to affirm that all technical specification requirements are adequately addressed.

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PILGRIM (1982)

Page8i

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INDUSTRIAL SAFETY PERFORMANCE OBJECTIVE: Station industrial safety programs should achieve a high degree of personnel safety.

Finding The industrial safety program needs ggrading to reduce the (OA.5-1) number of injuries and last-time accidents. Accident reports seldom reflect substantive follow-up action.

Recommendation Conduct more substantive accident /near-accident investigations to identify the root causes of accidents and to develop corrective actions. Trends of accident /near-accident types should be ana-lyzed to' identify generic safety problems. Use the results of accident investigations as a basis for training station personnel and improving overall attention to industrial safety.

Response BECO is recruiting a safety engineer who will have functional _l responsibility to the corporate safety official. Part of his duties 1 will be to assist in the conduct of substantive accident /near- I accident investigations, identify the root causes, trend these causes, and advise management. .

~

BECO has instituted a program in which the responsible group l leader and first-line supervisor meet with their vice president to review any lost-time accident.

Finding Plant personnel need training in fire protection and fire prevention.

(OA.5-2) The trailer complex that contains the document control center (DCC) contains significant amounts of combustible material, yet the DCC personnel interviewed were not familiar with the opera-tion of available fire equipment. The plant fire brigade observed during the evaluation was not sufficiently familiar with the plant layout and their fire brigade duties.

Recommendation Improve training of plant personnel in fire prevention and fire

. protection. Improve training of fire brigades in plant layout, location of fire fighting equipment, and coordination of brigade efforts. Use monitored drills to improve and evaluate brigade proficiency.

Response The recommended improvements will be implemented. Action is currently in progress.

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PILGRIM (1982)

. Page 9 >

_ DOCUMENT CONTROL PERFORMANCE OBJECTIVE: Document control systems should provide correct, read-Ily accessible information to support station requirements.

Finding An areessive period of time is reiguired to make permanent changes (OA.6-1) to station procedures. Although high priority changes can be made in one day, routine changes often require two months. Both the document processing capability and the review process contribute

_ to the delay.

Recommendation . Evaluate 'the adequacy of document processing facilities to support timely processing of documents and make changes. Identify and correct the problems contributing to the lengthy technical reviews.

Response The recommended improvements will be implemented. A new _1 process notifies upper management of extraordinary delays. BECO l l is developing an action plan to correct this problem.

l 1

Finding Improvements are needed in the handling and storage of permanent  !

(OA.6-2) records Backlogs exist in microfilming documents for permanent l storage. The computer system used to index document locations i and equipment used to view microfilmed documents are sometimes

{

i unreliable. They degrade the abuity of the DCC to retrieve l records needed by station personnel. These problems have led to development of backup retrieval systems and have increased the workload and volume of material in the already overcrowded DCC.

In addition, the volume of hard copy documents is increasing because of problems in identifying and destroying duplicate copies of documents that have been microfilmed.

Recommendation Improve the reliability of the computer records system and micro-film readers in order to reduce the extensive need for backup retrieval systems. Reduce the backlog awaiting permanent storage. Improve the identification and elimination in the DCC of those documents that have been microfilmed. Reduce the volume of unnecessary documents and material stored in the DCC.

Response New records management software has recently been purchased and installed on the records management computer. Nuclear organization personnel will be trained as required. The records backfit project to film all permanent records has been started. An effort to reduce the volume of material stored in the DCC has also

_ been initiated.

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t PILGRIM (1987)

Page 10 Finding ControBed oopies of procedures are not always current. A recent (OA.6-3) quality assurance audit revealed numerous problems with missing and out-of-date contro11ed ' procedures. The, following factors contribute to the document inaccuracies:

a. Copyholders are responsible for maintenance of the pro-cedure volumes, but no index listing the effective revi-

_ sions of procedures is provided to ensure the copies are current.

b. A periodic review of controlled procedure volumes to check their accuracy is not conducted.

c. Station procedures and the quality assurance manual do

< not agree on assignment of responsibility for maintaining controlled procedure volumes current.

d. The average two-month period to process a procedure change and the typing of procedure changes both on-site and off-site contribute to difficulties in maintaining an accurate status of revisions. Different changes to the

~

same procedure can be in progress on site and off site at the same time.

- Recommendation Assign clear responsibility for maintenance of procedures, and eliminate conflicting information in present documents. Provide controUed procedure copyholders with information showing the effective revision of all procedures. Periodically verify that controlled procedure volumes are current. Consider consolidating

. administrative processing of procedures under one group, and reduce the time required to process procedure changes.

Basponse 'Ihe recommended improvements win be implemented. The policy for handling controued documents win be promulgated by an organization level procedure. BECO win also add word processing equipment in 1983 to help speed up the process, and the quality

- assurance department win audit to ensure controlled procedures are kept current.

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i PILGRIM (1982) i Page 11 OPERATIONS OPERATIONS ORGANIZATION AND ADMIN 1STRAT!bN PERFORMANCE OBJECTIVE: The operations organization and administrative systems )

should ensure effective control and implementation of department activities.  :

Finding The number of licensed operators is not sufficient to accommodate (OP.1-1) the demands of vacation, sick leave, and an effective continuing training program without the use of excessive overtime. Scheduled training for ifcensed operators is frequently missed or postponed.

Recommendation Take action to provide additional licensed operators to relieve the 4

current shortage.

Response Several operators will complete license training under a new, _

improved training program in the near future. BECO is studying additional steps that may be taken.

Finding The chief operating engineer (COE) is not assigned sufficient (OP.1-2) administrative and technical support personnel to allow adequate time for personal supervision of plant activities.

Recommendation Pursue filling the vacant day-watch engineer position with a senior licensed individual. In addition, provide the COE with technical support personnel in accordance with the PIP revised organiza-tional structure.

Response An administrative assistant has been assigned to the chief operat-ing engineer. The budget has additional personnel approved for 1983. BECO plans to assign a day-watch engineer when additional

. licensed personnel are available for shift duties.

i 1

i Finding Shift technical advisors (STAS) have not been effectively inte-(OP.1-3) grated into the shift organization. Cooperation and support between plant operators and STAS need significant improvement.

! The STA's ability to provide assistance in off-normal situations may be adversely affected by this situation.

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PILGRIM (1982)'

Page 12 Recomm~endation Take steps to more effectively integrate STAS into the shift organization. Specific recommendations for consideration are as follows: -

a. Assign STAS to operating shifts during plant outages.

, b. Have STAS make recommendations concerning plant operation to the watch engineer rather than directly to plant operators,

c. Increase the involvement of the STAS in normal shift operating and maintenance activities.

Response STAS will remain on shift during outages other than extended refueling outages. To further improve the relationship, the STAS will participate jointly with operations in future training programs such as specialized technical specifications training and simulator requalification. STAS have been instructed to work with the watch -

engineers to resolve concerns about plant operations and mainte-nance activities.

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j CONDUCT OF OPERATIONS l PERFORMANCE OBJECTIVE: Operational activities should be conducted in a manner that achieves safe and reliable plant operation.

Finding Ezeessive control room traffle often distracts operator attention l (OP.2-1) from shift activities and control board monitoring. This is caused l in part by the location of the operating supervisor's desk in the center of the control room where all maintenance requests and tagouts are processed. In addition, personnel routinely pass through the control room to reach the reactor building.

i Recommendation Implement the current performance improvement plan to relocate

, shift coordination activities to a room outside the control panel

area. In the interim, take action to reduce pass-through traffic in t

, the control area.

Response The recommended improvements will be implemented. When the control room improvement plan is complete, ace.ess to the control room will be rigidly enforced and restricted.

In the interim, control room traffic will be limited to necessary business.

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PILGRIM (1982)

Page 13 Finding The practice of having the operating supervisor (control room (OP.2-2) senior reactor operator) process maintenance requests, tagouts and I administer the plant surveDlance program detracts from his ability j to effectively supervise control room activities. i l

Recommendation Continue with current plans to staff the position of shift coordina- l tor, and assign that position the responsibilities of processing maintenance requests and tagouts. Shift coordinators should be knowledgeable of systems and plant operation so they can provide substantive relief to the operating supervisor.

Response The position of shift coordinator has been approved. Specific requirements for this position are currently being evaluated. The position will be staffed when plant improvements to relocate shift coordination activities outside the control room are completed.

Finding Defective or out-of-tolerance instrumetation and controls are not (OP.2-3) adequately identified so that operators are alerted to the condi- ,

tion. In addition, the yellow sticker system presently used to denote disabled control room annunciators does not ensure that all disabled annunciators are identified.

Recommendation Establish a method to clearly and consistently identify defective or out-of-tolerance instrumentation.

Response The applicable procedures will be revised to correct the concerns stated in the finding.

PLANT STATUS CONTROIJi PERFORKANCE OBJECTIVE: Operational personnel should be cognizant of the status of plant systems and equipment under their control, and should ensure that systems and

. equipment are controlled in a manner that supports safe and reliable operation.

Finding Current shift turnover practices do not ensure a complete and (OP.3-1) comprehensive turnover of plant status. Nuclear plant operators and auxiliary operators rely on informal notes and memory to pass on pertinent information. Turnovers by these operators are often ,

too brief for an effective transfer of information.

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PILGRIM (l'982)

Page 14 -

l Recommentiation Expand the existing turnover requirements to include the following:

a. Provide adequate space on turnover sheets to record pertinent plant status information.

b. Utilize the existing turnover sheets in lieu of the pre-sently used notes and desk pad comments to guide the turnover process.

c. Include a review of outstanding tagouts as part of the operator turnover.

d. Require operators to perform a walkdown of control panels incident to shift turnover.

INPO's Good Practice OP-201, " Shift Relief and Turnover," could be of assistance in this area.

Response The recommended improvements will be implemented. Action is currently in progress, including development of an expanded turn-over sheet and a more formal record of watch activities, and the enforcement of control panel walk down requirements. -

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Finding Independent position verification is needed for safety-related com-(OP.3-2) ponents that are repositioned following maintenance or testing. It is recognized that independent verification is performed on selected systems following an extended outage.

Recommendation Revise procedures to require an independent verification of the '

position of all safety-related components that are repositioned following maintenance or testing. Consideration should also be given to conducting independent verification of important non-safety-related valves following maintenance and testing.

Response Procedures will be revised to incorporate the recommended im-provements. Action is currently in progress to determine an effective way to make the needed changes.

PILGRIM (1983) j . Page 15 Finding - Operators cannot readily determine what lifted leads and jumpers (OP.3-3) exist in the plant. Tracking of jumpers and lifted leads that originate with a maintenance request is particularly difficult. A

, periodic physical review of lifted leads and jumpers is not con-

ducted.

Recommendation Document the placement of lifted leads and jumpers in the ,

temporary modification record book. Identify lifted leads and '

,' jumpers with temporary modification tags. Conduct a periodic physical review of outstanding lifted leads and jumpers to ensure that an inder accurately identifies all installed temporary jumpers and lifted leads, tags are properly attached, and tagged leads and jumpers are installed as intended.

INPO's Good Practice OP-202, ' Temporary Bypass, Jumper, and Lifted Lead Control" could be of assistance in this effort.

Response A log documenting lifted leads and jumpers will be established and ,

maintained in the control room. Additional controls to address the recommendations will be implemented after further evaluation.

Finding The status of effective danger and test tagouts cannot be accu-(OP.3-4) rately determined. A number of tags in the plant could not be correlated to authorized tagouts, and tags are sometimes not completed and posted as specified. The status of posted tags is not l . periodically verified.

Recommendation Strengthen the controls used for authorization, placement, and removal of danger and test tags so that operations personnel can i

quickly and accurately determine the tagout status. Perform

_ periodic reviews of outstanding tagouts to verify the following: i l a. Only needed tagouts remain effective.

b. Authorized tags are posted as specified.

c. Tagged equipment is properly aligned.

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! d. No unauthorized tags are present.

l INPO's Good Practice OP-203, " Procedures for the Protection of Employees Working on Electrical and Mechani' cal Components" could be of assistance in this effort.

Response The recommended improvements will be implemented. INPO Good Practice OP-203 is being reviewed to determine how the recom-mended improvements can best be integrated into existing BECO policies.

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1 PILGRIM (1982)

_- Page 16 ,

Finding Many control room and adH=7 panel indications and controls -

(OP.3-5) were obscured by tags that were hung on adjacent switches. The large size of the tags contributes to this problem. .

Recommendation Correct current conditions where tags obscure lights and switches.

Obtain and use smaller tags or other means that will not obscure control board lights or switches.

INPO's Good Practice OP-203, " Procedures for the Protection of l Employees Working on Electrical and Mechanical Components".

could be of assistance in this effort. -

~ 1 Response Smaller tags have been ordered to replace the existing tags. l Implementation will occur once the tags are received an,d proce-dures changed. ,

i

/

s Finding Some aspects of the caution tag system need improvement. .The:

(OP.3-6) following problems were noted: ,y

a. A log or record is not kept of cauthn(ings posted in the plant.

b. There is no periodic review of caution tags for continued ~ )

applicability and legibility. ~ '

c. Caution tags are used for purposes other than conveying operating precautions or temporary instructions.

a'

d. Numerous improperly completed caution tags were found hanging throughout the plant. I Recommendation Revise the caution tag procedure to address the problems identi-fied above. A periodic review of caution tags should be impl'es mented.

INPO's Good Practice OP-203, " Procedures for the Protection of Employees Working on Electrical and Mechanical Components"

! could be of assistance in this effort.

Response A log documenting the status of caution tags will be maintained in the control room. Additional controls are being evaluated. BECO will review OP-203 and report, in the May I status report, how specific improvements will be achieved. -

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PILGRIM (1982)

Page 17

. ' OPERATOR KNOWLEDGE AND PERFORMANCE PERFORMANCE OBJECTIVE: Operator knowledge and performance should support l safe and reliable plant operation.

Finding Operator knowledge needs improvement in the following areas:

(OP.4-1)

a. automatic reactor trips and containment isolation

b. factors affecting core reactivity during startup  ;

- c.. ' basic heat transfer principles as they relate to plant  !

parameters and secondary plant efficiency Recommendation Improve operator requalification training to include the specific j areas listed above. Emphasize practical application of basic

- reactor theory and heat transfer principles. -

Response The overall operator training and requalification program is under active review. When revised, it will include the recommended i training.

- l u

Finding Operation of the condensate demineralizer system needs to be (OP.4-2) improved. During backflushing, resin is often deposited on the HPCI room floor. This appears to be caused by a combination of design, procedure deficiencies, and a lack of operator proficiency L. on the system. Corrective actions to prevent spillage have been delayed pending approval and installation of design changes.

i -

i Recommendation Continue with efforts to implement appropriate design changes. In f

the interim, revise applicable operating procedures to ensure that they provide adequate instructions to operators. Train operators to ensure that they understand the systems involved and the correct

'- operating methods to prevent resin spills. Ensure adherence to approved procedures for these operations.

Response The recommended improvements will be implemented. Action is currently in progress. The condensate demineralizer system is

- being redesigned to eliminate the possibility of resins being trans-ported to the HPCI room. This modification effort should be '

completed in the spring of 1983.

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PILGRIM (1982)

• Page 18

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OPERATIONS PROCEDURES AND DOCUMENTATION PERFORMANCE OBJEC7T!VE: Operational procedurss and documents should provide appropriate direction and should be effectively used to support safe operation of the Pl ant.

Finding The fcllowing Good Praetfee was noted: Operating procedures (OP.5-1) include a demeriptive section prior to procedural steps that de-scribes general system function, automatic system response, latest system modifications, and interlocks associated with system opera-tion.

Finding The following Good Practice was noted: Controlled copies of (OP.5-2) operating procedures are posted at operating stations throughout the plant in locations that are especially convenient for operator reference. -

Finding Uncontrolled notes, graphs, portions of procedures, and sketches (OP.5-3) are posted throughout the plant. A method is needed to authorize and update these operator aids.

1 Recommendation Implement an administrative program to control posted operator l aids. This program should include authorization of posting and 1 periodic review to ensure that posted aids are current and legible.

The number of posted operator aids should be minimized.

Response A program is underway to remove unauthorized documentation posted throughout the station,. A program will be developed to replace such documents vtl. uuthorized documents, where appro-priate, and to maintain (Y1ste< documents current and legible. The possible features of ' nit ;cer m are currently being evaluated.

i l 1

P1LGRIM (1982)

Page 19 Finding Some aspects of operating procedures need improvement. The (OP.5-4) following are examples:

a. Cautions often follow the steps to which they apply.

b. Notes and cautions sometimes contain action steps.

c. Some action steps contain excessive numbers of subpara-graphs.

1 Recommendation Plant operating procedures should be reviewed to identify and correct these areas.

Response The review plan for operating procedures is being developed and will be implemented in the near future. The examples identified in the finding will be addressed during the review.

Finding Alarm response procedures need to be upgraded. Several annun-(OP.5-5) clators on the main control boards are not included in the alarm response procedures. In addition, several procedures contain technical inaccuracies.

Recommendation Review alarm response procedures to ensure that they address all installed annunciator alarms and contain accurate information.

Response The recommended improvements wib be implemented. Action is currently in progress.

Finding Special orders and caution tags are often used to provide direction (OP.5-6) on equipment operation. This information should be incorporated into applicable operating procedures.

Recommendation Review the outstanding special orders and caution tags and incor-porate those which provide directions on equipment operation into properly approved operating procedures. Discontinue the use of special orders and caution tags as a means to provide operating instructions for other than temporary situations. '

Response The recommended improvements will be implemented. Action is currently in progress.

o

l PIZ, GRIM (19'82)

Page 20

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OPERATIONS FACILITIES AND EQUIPMENT PERFORMANCE OBJECTIVE: Operational facilities and equipment should effectively support plant operation.

Finding A more effective means of communicating between the control (OP.6-1) room and operators in the plant is'needed. Several instances were cbserved where inadequate communications delayed performance of surveillance tests and plant operations. This is due in part to the high communications traffic on the plant paging system.

Recommendation Action should be taken to provide operations personnel with improved methods of communication. Consideration should be given to the following:

a. Enforce more disciplined use of the plant paging system to decrease the amount of non-operational activity.

b. Provide operations personnel with multichannel portable communication equipment. i

c. Provide supervisors with individual pagers.

Response Action will be taken to improve communications for operators.

Management will restate the policy on use of the paging system by unauthorized personnel as unacceptable conditions occur. An additional system is being evaluated to improve the paging system by identifying isolated nuisance users. Several types of portable communications systems, including pagers, are being evaluated.

Finding Many plant valves and components are not identified with perma-  ;

(OP.6-2) nent and distinguishable labeling.

Recommendation The present labeling should be expanded to valves and components throughout the plant.

Response The recommended improvement will be implemented. Action is )

currently in progress.

e

l PILGRIM (1982)

Page 21 Finding The operation and material condition of radwaste facilities need (OP.6-3) significant improvement. A number of systems designed to process radioactive waste are not operational or are operating in a

_ degraded condition. These include the concentrator, reactor cleanup resin processing equipment, the condensate demineralizer  !

backflushing equipment, and the flat bed filters. Although a i radwaste improvement program'has been developed, the program has not yet been authorized, and responsibility for its implementa-l tion has not been assigned.

Recommendation Implement the radwaste facility improvement program with a high priority. Assign responsibility for this project to a designated manager with sufficient visibility and authority to ensure timely restoration of the radwaste systems to normal service. Since close coordination of refurbishment activities and normal operations will be required, consideration should be given to assigning the rad-waste coordinator to report to the manager responsible for the ,

radwaste improvement programs.

~

Response A comprehensive program to improve the radwaste function has been authorized. Different areas of this program are currently assigned to individual supervisors. BECO plans to assign overall responsibility for this project to a higher level manager in the near future.

._ Finding While significant improvement in plant cleanliness is evident, (OP.6-4) several areas of the plant require additional attention. These areas include the following:

a. high pressure coolant injection quadrant

b. traveling screen house

c. chemistry laboratory

d. Instrumentation and centrol workshop

_ e. some areas of the radwaste facilities Recommendation Continue to place emphasis on improving plant cleanliness. Parti-cular attention should be given to the areas identified above.

Response An ongoing program to upgrade station appearance and cleanliness will continue. The areas of concern above are those that have not yet been refurbished, but to which BECO plans to commit re-sources.

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PILGRIM (1982),

Page 22 MAINTENANCP PLANT MATERIAL CONDITION PERFORMANCE OBJECTIVE: 'the material condition of the plant should be main-tained to support safe and reliable plant operation. -

Finding The material condition of the screenhouse needs improvement.

(MA.2-1) Numerous salt water leaks exist, and corrosion of equipment and structures is extensive. Housekeeping needs improvement. Inade- '

quate lubrication appears to be contributing to frequent traveling screen failures.

Recommendation Initiate more aggressive action to identify and repair leaks and other material deficiencies in the screenhouse. Clean and preserve equipment and structures, and improve housekeeping. Review the screen lubrication program, and use periodic inspections to ensure proper housekeeping and material preservation.

Response The recommended improvements will be implemented. Action is  ;

currently in progress.

l I

1 6 i i

WORK CONTROL SYSTEM PERFORMANCE OBJECTIVE: '!he control of work should ensure that identified maintenance actions are properly completed in a safe, timely, and efficient manner.

Finding Numerous long-standing material deficiencies exist in the plant.

(MA.3-1) Significant contributing factors include lack of effective reporting of equipment deficiencies and inadequate response in correcting reported items.

Recommendation Emphasize the need to identify and repair material defleiencies in an expeditious manner. Implement a deficiency identification system to improve reporting of deficiencies for repair. INPO Good Practice MA-301, " Plant Material Deficiency Identification", could ,

be of assistance in this effort. Implement a more effective maintenance work priority system to ensure that important defi-ciencies are corrected first and less important defielencies are tracked until they can be repaired. Monitor and trend the maintenance backlog to aid in work and resource planning.

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i PILGRIM (1982) ,

_- Page 23 l

, Response The recommended imorovements will be implemented. Action is i currently in progress. A priority system associated with mainte-nance requests is an example of the specific improvements  ;

planned. l l

~

PREVENTIVE MAINTENANCE l l

PERFORMANCE OBJECTIVE: The preventive maintenance programs should contribute to optimum performance and reliability of plant equipment.

1

- 1 Finding Although some preventive maintenance activities are being per-

. (MA.5-1) formed, the program is not funy developed or implemented. The l present program identifies fewer than 150 activities, of which ,

about two-thirds are vibration readings. Authorization procedures  !

for performing scheduled preventive maintenance and methods for I recording completed work appear to be unnecessarily cumbersome. l

~

Recommendation Expand the preventive maintenance program to encompass all equipment important to plant operation. Ensure that the admini-strative portion of the program includes methods to efficiently authorize and document preventive maintenance.

Response The recommended improvements will be implemented. The pre-ventive maintenance program is currently under development.

MAINTENANCE PROCEDURES AND DOCUMENTATION PERFORMANCE OBJECTIVE: Maintenance procedures should provide appropriate di-rections for work and should be used to ensure that maintenance is performed safely and efficiently.

Finding 'Ihe content and usage of maintenance procedures need to be 1p-(MA.6-1) graded.

Recommendation Review present procedures and revise them as necessary to ensure that they provide adequate guidance to perform tasks effectively.

A checklist should be established and used to ensure uniformity du*ing the review. The following items should be considered:

I

a. the need for on-the-job verification that selected proce-l dural steps are properly completed de

- ___ _ _ _ , _ - .-c - - . _ . - , - m

PILGRIM (1982) i Page 24 '

b. adequacy of instructions to specify the degree of proce-dural adherence required

c. the need for pre-closure inspections and verifications

d. identification of appropriate sign-offs to ensure work is i

4 properly completed ,

Response The review plan for maintenance procedures is being developed and will be implemented in the near future. The examples identified in the recommendation will be addressed during the review. In addition, as procedures are used in the field, needed improvements are regularly being identified and completed.

MAINTENANCE FACILITIES AND EQUIPMENT PERFORMANCE OBJECTIVE: Facilities and equipment should effectively support the performance of maintenance activities.

Finding Improvement is needed in traceability rewn% shelf life controls, (M A.8-1) and availability of stock items and supplies. Plant activities and equipment reliability are sometimes affected because of ineffee-tive stockroom practices.

Recommendation Improve storeroom procurement and handling methods. Considera-tion should be given to the following specific improvements:

a. Establish controls to ensure that maintenance and envi-ronmental requirements for stored material and equip-ment are adequately addressed.

b. Ensure that issued Q-list materials can be traced to end-use in the plant.

c. Provide a system that permits the on-site stockroom to ,

more easily obtain standard items, e.g., consumables or )

" standard" vendor items.

d. Revise existing purchase authorization methods to elimi-nate redandant or unnecessary technical reviews wherever practicable. .

e. Establish a more convenient method of withdrawing items from the stockroom than the current purchase requisition.

l Consider using an issue / return ticket that includes mini-mum part identification information and fewer approval signatures.

t

' PILGRIM (1982)

. Page 25

_ f. Establish stock levels and automatic reorder procedures based on historical demand.

Response BECO has established a Spare Parts / Materials Management Task Force. This task force is comprised of members from the nuclear engineering department, nuclear operations support department, nuclear operations department, quality assurance department, stores department, and training department. Many of the recom-mendations that INPO has suggested are already being examined.

The others will also be addressed by the task force.

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l PILGRIM (1982) .

_ Page 26 TECHNICAL SUPPORT TECHNICAL SUPPORT ORGANIZATION AND ADMINISTRdTION PERFORMANCE OBJECTIVE: The technical support organization and administrative systems should ensure effective control and implementation of department activities.

4 Finding Completion of some station technical support tasks is adversely (TS.1-1) impacted by vacancies in the technical grog staff. Resolution of operational problems with reactor building drain systems has required inordinate personal involvement of the operations and maintenance chief engineers due to the lack of engineering person-nel in the technical group. Only six of seventeen authorized technical positions in the technical group are fuled, and five of those are assigned to perform reactor engineering tasks.

i

Recommendation Fill the vacant positions as soon as practicable. In the interim, consider the temporary reassignment of personnel from other company groups to the station technical group. The position of lead plant engineer should be filled on a priority basis.

Response -

BECO is attempting to ful the lead plant engineer and other technical staff vacancies on a priority basis. Additional temporary assignments of personnel are not needed until a clearer definition of technical support staff responsibilities is developed. Action is in progress to define appropriate technical support staff responsibili-ties.

OPERATING EXPERIENCE REVIEW PROGRAM ,

~

1 PERFORMANCE OBJECTIVE: Industrywide and irr-house operating experiences should l be evaluated and appropriate actions undertaken to improve plant safety and reliability. l

, SOER STATUS The status of Significant Operating Experience Report (SOER) recommendations is as follows: ,

Number of Recommen$ations Action Taken .

26 Satisfactory 45 Not applicable 80 Pending

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PILGRIM (1982)

. Page 27 The following recommendations are pending action:

SOER Number Recommendation Number 80-1 1,2 80-2 2 80-4 1,2,3 80-6 1,2,3,6,7,8,10 81-2 1,2,3,4,5,6 81-3 2 81-8 1,2,3,4 81-9 1,2a,b,e l 81-10 1 1 81-13 1,3,4,6,7,8,9,10,11,12,13,14,15 l 81-14 1,2,3,4 81-15 la,b,c,2a,3 1 81-16 1,2,3 l 82-2 1,2,3,4,5,6,7  ;

82-4 1,2,4,5,6 .

82-6 26,3,5 82-8 1,2,4 i 82-9 1,2,3,4,5,6,7,8 )

An update on the status of each recommendation listed in the "pending action" category shown above is requested in the six-month follow-on response to this report. In addition, the status of each immediate action (red tab) SOER recommendation received subsequent to this evaluation should be included in the six-month follow-on response. A tabular summary, similar to that above, is requested.

Finding Provisions for tracking corrective actions that result from operat-(TS.3-1) ing experience reviews need improvement. Tracking of commit-ments resulting from Pilgrim LERs began three months ago.

Corrective actions from industry SERs and SOERs and other in-house investigation reports are not tracked.

Recommendation Implement plans to track corrective actions on site. The existing program that tracks in-house commitments should be expanded to cover planned corrective actions resulting from review of SERs and SOERs as well.

Response The recommended improvements will be implemented. Action is currentiv in progress.

l l

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PILGRIM (1982)

Page 28 -

Finding ~ Distribution of operating experienee information is not effectively (TS.3-2) performed. A procedure has been developed for screening and l disseminating operating cxperience information, but it has not been '

fully implemented.

Recommendation Implement procedures to ensure applicable operating experience

, information is distributed to all affected personnel.

Response The recommendation will be implemented. Action is currently in progress.

l l

Finding '1he operating experience review program does not include timely (TS.3-3) notification to other utilities of signifleant PDgrim events with -

generie implications.

Recommendation Implement guidelines on the use of NOTEPAD to inform other utilities of possible generic events at Pilgrim.

Response 'lhe recommendation will be implemented. Action is currently 'in progress.

i l

l Finding Plant participation in the NPRDS program has not been adequate (TS.3-4) to ensure the timely reporting of component faDures and to ensure the engineering data base is current. Failure reports have not been submitted since the third quarter of 1981.

Recommendation Enter the backlog of failure information and engineering base data into NPRDS, and resume routine NPRDS participation.

Response BECO will resume NPRDS participation in the near future.

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PILGRIM (1982)

Page 29

~

PLANT MODIFICATIONS PERPORMANCE OBJECTIVE: Plant modifleation programs should ensure proper re-view, control, implementation, and completion of plant design changes in a safe and timely manner.

1 Finding '!he following Good Practice was noted: Training programs, proce-I

( 7 15. 4 - 1 ) dure revisions, and critical drawing gdates are planned, scheduled, and completed concurrently with the physicalinstaBation of plant

. modifications. Tasks associated with these items are tracked effectively with the same scheduling system used for outage planning.

I

• t REACTOR ENGINEERING PERFORMANCE OBJECTIVE: On-site reactor engineering activities should ensure optimum nuclear reactor operation without compromising design or safety limita.

Finding Reactor coolant chemistry parameters do not appear to be ade-(TS.5-1) quately considered when men ===ing nuelaar fuel performance.

Reactor engineering personnel were not aware of chemistry trends indicating the potential existence of pinhole fuelleaks.

Recommendation Train reactor engineering personnel on the use of chemistry parameters to monitor fuelperformance. Strengthen the review of

. chemistry conditions as a part of routine fuel performance assess-ment. Improve working communications between the reactor engi-neering and chemistry groups.

1 I

~

i Response BECO agrees that better communications should be established between the chemistry and reactor engineering groups and feels that both groups should be cognizant of off-gas isotopic relation-ships. Action will be taken to ensure that reactor engineering personnel understand the use of relevant chemistry parameters to monitor fuel performance and to ensure that chemistry parameters

_ are carefully considered during regular fuel performance analyses.

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PILGR8M,(1982)

Page 30 TECHNICAL SUPPORT PROCEDURES AND DOCUMENTATION ,

PERFORMANCE OBJECTIVE: Technical mapport procedures and documents should provide appropriate direction and should be effectively used to apport safe operation l of the plant. i Finding Technical apport activities are sometimes not effectively coordi-(TS.7-1) nated between the several station and corporate grogs involved.

Redundant, and sometimes conflicting, procedures for processing safety evaluations, plant design change requests, drawings, and field revision notices have been issued by the station staff, the nuclear engineering department, and the startup management groups. .The lack of unifying procedural guidance for the nuclear organization has been recognized as a problem, and corrective action has been initiated as part of the PIP.

Recommendation Complete the action plan development scheduled under item II 8.A of the PIP. The four activities discussed above should be speci-fically addressed in this plan. Ensure that changes to individual implementing procedures in interface areas are coordinated with

, all involved groups.

Response The recommended improvements will be implemented. Action is in progress in the PIP.

l I

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l PILGRIM (1982)-

4 -

Page 31

~

) TRAINING AND QUAIRICATION l TRAINING ORGANIZATION AND ADMINISTRATION PERFORMANCE OBJECTIVE: The training organization and administrative systems shouki ensure effective control and implementation of trrining activities.

^

l f

2 Finding Instructor technical knowledge and elassroom teaching techniques (TQ.1-1) need improvement. Weaknesses were noted in instructor knowl-edge of Pilgrim events. In addition, instances were noted in which previously developed lesson guides were not used, advance prepara-tion was minimal, and classroom time was not used constructively.

Recommendation Develop and implement measures to improve the instructional and technical capabilities of instructors. Involve training managers and

- plant department managers in monitoring training for lesson con- .

tent and quality of instruction.

j Response A trainer certification program willbe developed. As each course is conducted, the training manager, appropriate training group leader, and appilcable discipline chief will monitor the course at least once to evaluate instructional methods and course content.

1 -

~

i, i Finding Operations personnel do not receive effective training on industry -1 operating experiences. Applicable industry operating experience

~ '

i (TQ.1-2) reports are neither provided to the training department nor incor- i porated into regular training sessions, j Recommendation Establish a system to provide the training department with infor-mation on industry experience reports such as SOERs, LERs, SERs, and O&MRs. Provide training on industry operating experiences to operations personnel during regularly scheduled operator training each shift cycle.

l _

Response The station technical advisors have recently been assigned the task l

of receiving and reviewing applicable industry operation experience reports. A Plant Operations Experience Assessment Committee

, . (POEAC) has been appointed to screen significant events and select I those to be transmitted to other BECO personnel for action. The

- training department will provide POEAC with a list of written criteria to be used to determine if SOERs, LERs, SERs, and O&MRs have a potential training application at Pilgrim Nuclear Power Station. Appilcable mater:a1 will be incorporated into training programs.

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PILGRIM (1982) ,

Page 32 NON-LICENSED OPERATOR TRADENG AND QUALIFICATION PERFORMANCE OBJECTIVE: The non-licensed operator training -and qualification program should develop and improve the knowledge and skills necessary to perform

, assigned job functions.

Finding The recently developed nuclear auxiliary operator (NAO) continu-(TQ.2-1) ing training program does not cover all aspects of the NAO job.

Recommendation Expand the NAO requalification program to include such informa-tion as applicable procedure revisions, modifications, operating experience, radwaste system problems, and job-specific radiation protection training.

4 Response The recommended improvement will be implemented. Action is currently in progress.

LICENSED OPERATOR TRAINING AND QUALIFICATION PERFORMANCE OBJECITVE: The licensed operator training and quellfleation program should develop and improve the knowledge and skills necessary to perform assigned job functions.

Finding The lleensed operator requalification program needs to be (TQ.3-1) strengthened. The portions of the current requalification program that pertain directly to operator duties are coverad in an annual simulator session, a presentation on major outage modifications, and in a short classroom series. A limited number of topics are covered, and the depth of coverage is not appropriate for a substantive requalification effort. Some weaknesses in operator knowledge have resulted. Requalification candidates have not attended a number of scheduled sessions, and delays in the requali-fication schedule have been necessary.

Recommendation Provide additional formal instruction in the licensed operator requalification program. INPO's guideline " Nuclear Power Plant Requalification Program for Licensed Personnel" (GPG-02) could be of assistance. Strengthen coordination between the training and operations organizations to ensure that training is completed as scheduled. -

Response The recommended improvement will be implemented. Action is currently in progress.

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PILGRIM (1982)

Page 33 MAD 4TENANCE PEBSONNEL TRADUNG AND QUALIF PERFORMANCE OBJECTIVE: The maintenance personnel t form trai program should develop and improve the knowledge and skDis nec -

i asagned job functions.

Findmg Improvements are needed in initial maintenance and training programa.

(TQ.5-1) components has not been conducted for mechanics, electricia nuclear technicians, and nuclear control technicians. In addition, on-the-job training (OJT) programs used to qualify these perso do not adequately define the training tasks to be accomplished.

! Training is required on some tasks that are not part of the employee's job. Measurable standards are not provided for su ful completion of OJT tasks.

Provide formal training on plantReview systemsOJTand programscomponents to for Recommendation maintenance crafts and technicians.climinate Program unnece ful requirements for achievement of necessar '

following:

a. listing of tasks to be performed, simulated, observed, or discussed

b. skill and knowledge standards

c. assurance that individuals have demonstrated competency in specified tasks prior to performing those tasks without:

supervision The following INPO documents could be of assistance in thi effort: " Guidelines for Mechanical Maintenance Pers cation" (GPG-05); " Guidelines for Elec Control Technician Qualification" (GPG-08).

Action is The recommended improvaments will be implemented.

Response currently in progress, i

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l PILGRIM (1982)

Page 34 l

TECHNICAL TRAINING FOR MANAGERS AND ENGINEERS PERFORMANCE OBJECTIVE: The technical training program for engineers and mana-  !

gets should broaden overall knowledge of plant processes and equipment as a supple-ment to positiorspecific education and training.

Finding Plant engineers and technical managers receive little classroom or

(TQ.6-1) on-the-job training in plant systems, integrated operations, and other subjects pertaining to their jobs. Weaknesses were noted in identification of codes and standards applicable at Pilgrim, under-standing. the importance of chemistry to fuel performance, and basic system knowledge.

Recommendation Provide structured training in plant systems and operations, and in job specifics for technical managers and new engineers. Review 1

I the knowledge and skills of current engineers and managers and, -

where appropriate, provide upgrading training to support current and anticipated assignments. INPO document ' Technical Depart-ment Programs for Technical Staff and Managers" (INPO 82-022)  !

could be of assistance in this effort. -

1 Response INPO 82-022 is being used to evaluate training of engineers and j

technical managers. Where deficiencies in engineer and technical manager knowledge are found, they will be corrected by appro-priate training. I

~

i GENERAL EMPLOYEE TRAINING f -

PERFORMANCE OBJECTIVE: The general employee training program should develop a

. broad understanding of employee responsibilities and safe work practices.

, Pinding The general employee training program does not provide workers

)

(TQ.7-1) with adequate knowledge and skills to comply with plant safety procedures and prescribed radiological procedures and practices.

Much of the material presented is out of date and does not agree with current plant procedures. Instructional techniques, course i

content, testing, and training aids need improvement. Necessary practical abilities are not demonstrated or evaluated in the course

! - of training. This situation is recognized by the training organiza-tion, and a revised program is under development.

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PILGRIM (1982)

Page 35 Recommhtion Continue with development and implementation of the proposed revision to the general employee training program. Identify and correct errors in training materials. INPO's " Guidelines for

~

General Employee Training" (INPO 82-004) could be of assistance in this effort.

Response The recommended improvements will be implemented. Action is currently in progress.

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Page 36 j j , RADIOLOGICAL PRCr!'ECTION l

• RADIOLOGICAL PROTECTION ORGANIZATION AND ADMINISTRATION l PERFORMANCE OBJECTIVE: The organization and administrative systems should '

ensure effective control and implementation of the radiological protection program.

l i Finding Measures prescribed for controlling spread of contamination and (RP.1-1) radiation exposwe are sometimes not applied in an affective and  :

consistent manner. Examples include the following: l

a. Control and use of step-off pads is not consistent through-out the station.

b. Postings are frequently not removed when conditions have l

changed and they are no longer required. I

c. Some postings do not adequately inform personnel of h

radiological hazards. ,

Recommendation Develop and enforce improved methods to ensure that step-off pads are controlled and used consistently. Health physics tech-l nicians and supervisors should regularly inspect all posted plant and I yard areas to ensure that radiological postings provide current i

information and adequate instructions for access. The condition of step-off pads and other access point materials should be checked routinely. Problems noted should be promptly corrected. I Response The recommended improvements will be implemented. Action is currently in progress.

l i

Finding Personnal contaminations and radiological incidents are not docu-(RP.1-2) mented and analyzed in a manner that ensures identifloation and

(

correction of basie causes. Although a reporting system exists, it is not often utilized.

~

Recommendation Revise the current radiological incident reporting system to sim-i pilfy reporting. Ensure that radiclogical incidents and personnel 1

contaminations are regularly reported and analyzed to identify needed corrective actions. All personnel should be informed of the i

appropriate reporting threshold levels established by supervision.

Response The recommended improvements will be implemented. Action is currently in progress.

l

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, PILGRIM (1992)

Page 37 Finding Lighting and housekeeping conditions in some radiologically con-(RP.1-3) trolled areas need to be improved to reduce radiological and industrial safety hazards. Areas of concern include the drywell, radwaste truck lock, reactor building corner rooms, and radwaste equipment rooms.

Recommendation Restore lighting in the affected areas. Complete current plans to repair drywelllighting during the next refueling outage. Continue with current plans to clean up these areas.

Response The recommended improvements will be implemented. Action is currently in progress.

1 Finding Personnel often do not adhere to prescribed radiological proce-(RP.1-4) <hm Fvernpin of practicas that need improvement include the folloWing:

a. Frisking is often ineffective; contamination detected dur-ing frisking is sometimes not removed.

b. Adherence to requirements of radiological area postings is sometimes inadequate.

c. Radiation Work Permit instructions are sometimes not followed.

d. Protective clothing used by personnel for work in con-taminated areas is sometimes inadequate.

Recommendation Improve general employee training to ensure that routine radio-logical control practices are adequately covered. Emphasize the importance of following procedures and posted instructions.

Strengthen the role of supervisors in monitoring and correcting improper radiological control practices.

Response The recommended improvements will be implemented. Action is currently in progress.

1 1

i PILGRIM (1982) ~

Page 38

~~

EXTERNAL RADIATION EXPOSURE PERFORMANCE OBJECTIVE: Erternal radiation exposure controls 'should minimize personnel radiation exposure.

Finding Radiation exposure reduction measures are needed for handling and (RP.4-1) processlag radioactive waste. A number of potential improvements to reduce exposure associated with waste handling operations involving resin and sludge have been identified, but not imple-mented.

Recommendation Analyze current radioactive waste handling methods and imple-ment improvements that have a potential for reducing dose to personnel.

Response The recommended improvements will be implemented. Action is currently in progress.

i Finding ,

(RP.4-2)

Radiation exposuras for routine plant work are not affectively l being minimized. Radiation exposure estimates and goals are not utilized for jobs where they would be appropriate. Pre-planning to reduce exposure by methods such as postings, shielding, and mini-mizing worker stay times is sometimes not performed or carried out effectively. Recent reassignment of ALARA duties appears to .

be a contributing factor to the lack of defined responsibilities in this area.

Recommendation Implement a structured program to ensure routine use of effective exposure reduction measures for plant maintenance and operations activities. Provide radiological engineering support for this effort as necessary.

Response

The recommended improvements will be implemented. Action is currently in progress.

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PILGRD1 (1982)

Page 39

- Finding ~ Radiation survey instruments are sometimes not available for use (RP.4-3) when needed. A number of instruments need repair, but repairs are not effectively pursued. Location of available instruments is often not known.

Recommendation Repair er replace defective radiation survey instruments to ensure that adequate numbers and types are available for required sur-veys. If needed, develop a means of accountability for instru-m ents.

. Response The recommended improvements will be implemented. Action is currently in progress.

INTERNAL RADIATION EXPOSURE

, PERFORMANCE OBJECTIVE: Internal radiation exposure controls should minimize internal exposures.

• Finding Whole-body counting equipment is sometimes not operated in a (RP.5-1) manner that ensures uptake of radioactive material will be de-tected and accurately measured. The following are examples:

a. Thyroid detectors are not being used.

b. Some technicians lack proficiency in equipment operation and do not use plant procedures.

c. Data indicates that methods for conducting source checks need improvement.

Recommendation Resume use of thyroid counters. Ensure that technicians who perform whole-body counts are proficient on the equipment and that procedures are used when needed. Investigate and implement appropriate changes to improve the accuracy of source checks.

Response The thyroid detectors for both whole-body counters were out for

~ repair during the INPO evaluation. Since that time, the thyroid detector for the primary whole-body counter has been repaired and ,

placed in service. The thyroid detector for the backup whole-body i counter will be placed in service following receipt and installation of ordered equipment. Additional training will be performed as

' necessary for those health physics technicians who perform whole-body counts. Prior to the INPO evaluation, a purchase order was

.. issued for a new whole-body counting phantom and calibration sources. This new equipment willimprove the method for perform-ing calibrations and source checks.

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1 PILGRIM (1982)

Page 40 ,

__ PERSONNEL DOSIMETRY PERFORMANCE OBJECT'IVE: The personnel dosimetry program sMuld ensure that radiation exposures are accurately determined and recorded.

l Finding Natural background radiation exposure is not subtreeted from all I (RP.8-1) thermoluminescent dosimeter (TLD) readings. As a result, the

' plant may be reporting higher occupational radiation exposures l than are actually being received.

l Recommendation Subtract the background exposure dose when determining the occupational dose received at the station.

Response The procedures for TLD readout will be reviewed to determine if natural background exposure to personnel TLD badges is significant and, if so, can be subtracted from personnel badge readings.

4 J .

Finding Extremity dosimeters are not used during radweste processing I

(RP.8-2) activities where there appears to be a significant potential for personnel to receive extremity doses.

! Recommendation Ensure adherence to existing plant requirements for wearing  ;

extremity dosimeters.

Response The recommended improvements will be implemented. Action is 1

currently in progress.

I

) RADIOACTIVE CONTAMINATION CONTROL i

PERFORMANCE OBJECTIVE: Radioactive contamination controls should minimize the j contamination of areas, equipment, and personnel.

! Finding Frisking facilities need improvement. Examples are as follows:

l (RP.9-1)

a. Some friskers are inoperative or overdue for calibration. 1 i

They are checked only weekly for proper operation. '

b. No frisker is available at the exit from the augmented offgas (AOG) building.

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PILGR1M (1982)

Page 41

~~

. c. Friskers near the drywell access are located in a high background area. Workers rely on these instruments for whole-body frisking. They routinely don street clothing before exiting the reactor building and frisking in low background areas.

Recommendation Check friskers for operability more frequently. Provide an effee-tively shielded frisking area reasonably close to the drywell en- ,

trance. Provide friskers at the AOG building exit.

Response During plant tours, the calibration and operability of friskers will be verified. Current plans are to relocate the drywell frisking booth to a lower background area. During plant operation, frisking in the AOG building is precluded due to high background. However, double sets of protective clothing are worn when inside the building, and the outer set is removed prior to leaving the building.

During non-operating periods with planned work in the AOG building, a frisker will be present at the building exit.

Finding There are many contaminated areas in the plant where use of full

] (RP.9-2) protective clothing and respiratory protection are required for routine activities such as periodic inspection. Extensive clean-up of contaminated areas is evident since the last refueling outage, but continued strong emphasis is needed to ensure progress con-tinues now that the clean-up work force has been reduced in size.

Recommendation Continue clean-up efforts to the point that routine access to plant equipment and systems is not substantially impeded by require-ments to wear extensive protective clothing and respiratory pro-tection.

Response The recommended improvements will be implemented. Action is currently in progress.

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Page 42

CHEMISTRY CHEMISTRY ORGANIZATION AND ADMINISTRATION PERFORMANCE OBJECTIVE: The organization and administrative systems should t

ensure effective implementation and control of the chemistry program.

Finding Additional personnel may be needed in the chemistry department (CY.1-1) to support and implement a comprehensive chemistry program.

Recommendation Evaluate'the projected workload of the plant chemistry organiza-tion to determine if additional supervisory and technical personnel or reassignment of responsibilities are needed.

Response

The recommendation will be implemented. Action is currently in progress.

t 4

Finding The chemistry department does not have adequate storage facill-(CY.1-2) ties. The chemistry laboratory contains such items as unused i

equipment, repair parts, design change components, calibration standards, and radioactive samples.

l

, Recommendation Provide storage facilities to support chemistry department needs.

Response

The recommendation will be implemented. Action is currently in progress.

Findmg The environmental controls in the chemistry and health physics l . (C Y.1-3) counting rooms are inadequate. Calibration and operation of l

' sensitive counting room equipment is adversely affected by high '

ambient temperatures.

Recommendation Evaluate and correct the environmental control problems in the counting rooms.

i Response The recommendation will be implemented. The required Engineer-ing Support Request has been submitted.

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PILGRIM (1980)

Page 43 Finding Housekeeping in the chemistry facilities needs improvement.

(CY.1-4) Accuracy and sensitivity of laboratory analyses could be affected.

Recommendation Increase supervisory attention to good housekeeping practices.

Response This recommendation has been implemented.

Finding Chemistry sampling procedures are needed to ensure safe and (C Y.1-5) proper sampling of plant systems and tanks. Presently, samples are being collected without formal procedural guidance.

Recommendation Complete planned development and implementation of chemistry sampling procedures.

Response The recommended action will be completed. Action is currently in l progress. .

Finding Chemistry data are not routinely trended or evaluated by the plant (C Y.1-6) staff to aid in correcting or identifying out-of-specification condi-tions, problems with plant systema, and analytical problema.

a. Oxygen concentrations in the condensate and feedwater are increasing. The day-to-day cata points are scattered, indicating a potential analytical problem.

b. Boron concentration in the reactor water is increasing.

Recommendation Initiate a formal program for trending of plant chemistry data.

Include comparison with applicable limits or expected ranges for each parameter. Trends should be reviewed routinely for potential

. . problems.

Response The recommended improvements will be implemented. Action is currently in progress.

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PILGRIM (1982)

Page 44 CHEMISTRY PERSONNEL QUALIFICATION PERFORMANCE OBJECTIVE: The chemistry qualifleation program should ensure that chemistry personnel have the knowledge and practical abilities necessary to implement chemistry practices effectively.

Finding The present method of training and qualifying chemistry personnel (CY.2-1) does not ensure adequate knowledge in the following aream

a. vendor specifications applicable to plant systems  ;

b. technical specifications l

c. plant procedures I

d. abnormal operations

e. analytical theory.

f. theory and operation of counting equipment (including l computer-based equipment)

g. data interpretation and evaluation i

h. chemistry quality control and preventive maintenance

1. laboratory safety Recommendation Develop and implement a training program for chemistry personnel

, that provides a working knowledge of the above areas. This program should contain documented exercises and written exami-nations that demonstrate knowledge of the above areas.

Response A training program will be implemented to ensure identified needs are adequately addressed.

l l

Finding A chemistry retraining program has not been formalized or imple-(CY.2-2) mented for ehemistry personnel. Retraining in the following areas should be included:

a. basic technical materials .

i b. plant equipment changes l c. use of laboratory equipment i

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PILGRIM (1982)

- Page 45 e, pertinent industry operating experiences f,

weaknesses in the plant chemistry program Implement a chemistry retraining program that covers, as a Recommendation minimum, the above areas.  ;

l The training department will expand the initial training program to l

Response

provide for the recommended retraining.

CHEMI!rrRY CONTROL Chemistry controls should ensure optimum chemistry PERFORMANCE OBJECTIVE:

4 4

conditions during all phases of plant operation. .

! Routine analysis for proper ehemical concentrations of acids and Finding caustics is not performed during the following:

t (CY.3-1)

' a. receipt inspections of bulk acids and caustics, i

b. long-term storage in plant acid and caustic tanks

c. resin regeneration of the make-up water system Implement a chemical analysis program for determining and m i

Recommendation taining the proper concentrations of acids and caustics under the above noted conditions.

J The recommended action will be completed.

Response

i Chemical parameters in some plant systems are permitted to j

Finding remain outside limits recommended by plant We ares for ex-(CY.3-2) tended periods of time. Examples of systems and parameters involved include the following:

a. plant heating boiler (nitrite) i

b. turbine building closed cooling system (nitrite)

~ c. reactor water (silica)

d. demineralized water (silica)

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PlLGRIM (l'982)

Page 46

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I Recommendation Identify and correct out-of-specification chemistry conditions in a '

timely manner. '

Response The recommended improvement will be implemented. Action is currently in progress.

Finding Improvements are needed in monitormg the performance of (CY.3-3) domineralizers in removing impurities from the flow stream. In some cases demineralizer performance degradation will only be detected by analysis of tanks that receive water from the demineralizer.

Recommendation Implement an improved program to periodically monitor and eval-unte plant demineralizer performance.

Response

The recommendation will be implemented. Action is currently in progress. -

LABORATORY ACTIVITES PERFORMANCE OBJECTIVE: Laboratory and counting room activities should ensure accurate measuring and reporting of chemistry parameters.

Finding The ehemistry quality control program needs to be improved to (CY.4-1) ensure that analyses are performed accurately.

Recommendation Develop and implement a chemistry quality control program that ensures analyses are performed with the required degree of accu-racy. The following areas should be addressed:

a. Increased use of split samples with concentrations com-parable to normal plant samples

b. use of spiked samples to test the performance of analysts

c. use of standards in conjunction with sample analyses

d. shelf life control of reagents, standards, and chemicals

e. trending of key quality control data and evaluation of quality control activities l

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PILGRIM (1982)

Page 47

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Response BECO agrees that the chemistry quality control program needs to be improved. Possible improvement actions are being evaluated.

The recommendations listed above will be addressed in the improved program.

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Finding A program for preventive maintenance on chemistry laboratory and (CY.4-2) on-line equipment is needed. Preventive maintenance specified in individual' instrument technical manuals is not consistently per-formed.

Recommendation Develop and implement a preventive maintenance program for chemistry laboratory and on-line instrumentation.

Respanse All chemistry equipment will be evaluated to determine appli-cability and possible extent of preventive maintenance. Appro-priate preventive maintenance will be established. .

Finding Some samples are collected and analyzed without assurance that (CY.4-3) the sample is representative of the contents of the system.

Examples where non-representative samples are suspected include the standby liquid control tank, waste neutralizing tank, and condenser tail pipe pits.

Recommendation Incorporate prov in sampling techniques into the plant sampling procedures to ensure representative sampling of the contents of systems.

Response The recommendation will be implemented. Action is currently in progress.

Finding Analytical methods for determining chemical ecaeentrations in (CY.4-4) plant systems should be examined and improved: Problem areas noted during the evaluation include the following:

a. Methods of accounting for irppurities in laboratory water used for preparing standards, reagents, and samples are not in place.

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PZLGRIM 6982)

Page 48 -

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b. Standards are not used to develop a working curve for the silica analysis.

c. Laboratory and on-line conductivity meters are not rou-tinely calibrated.

d. Calibration checks are not routinely performed on labora-tory balances and pipettes used to prepare reagents, l samples, and standards,

e. The method used for chloride analysis does not have the needed accuracy and precision.

f. The pH meters are routinely calibrated using only one buffer.

g. Gamma ray peaks with a data unreliability of greater than 60 percent are discarded without proper evaluation as to the validity of the peak.

h. The method used for silica analyses does not have the sensitivity to measure the 10-ppb procedural limit for demineralized water.

Recommendation Evaluate analytical methods currently used for sensitivity, accu-racy, precision, calibration, interferences, contaminants, and good laboratory practices. Upgrade or replace the present analytical methods as appropriate.

Response The recommended improvements will be implemented. Action is currently in progress.

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Finding The waste ooDeetion tank and waste sample tanks are not sampled j (CY.4-5) and analyzed for organics. In addition, controls are needed to ensure that oil is not pumped from turbine building sumps to the

- hotwell.

Recommendation Implement controls, including appropriate analyses, to prevent organic intrusions into the condensate, feedwater, and reactor water systems.

Response The major source of oil leaks into the turbine building sumps has been eliminated. Only small amounts of oil are now present in the sumps. BECO is evaluating available analytical equipment and ,

methods to prevent organic intrusions and will implement controls I

. as recommended.

PILGRIM (1982) !

. Page 49

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CHEMICAL AND LABORATORY SAFETY PERFORMANCE OBJECTIVE: Work practices associated with chemistry activities should ensure the safety of personnel.

Findmg Some relief valves have been removed from the condensate and (CY.5-1) feedwater sampling system. This could result in full system pressure at the point of sampling.

Recommendation Perform a safety evaluation on removal of relief valves from the condensate and feedwater sampling system, and take appropriate action to reinstall the relief valves or approve a design change.

Response The recommended action will be completed.

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APPENDIX !

-- Page1 APPENDIX I i Summarv of Outstanding Response Action from Previous Evaluation (1981) '

ENGINEERING SUPPORT  :

(INPO Procedure TS-702, Revision 2)

1. Finding (Reference Criterion A)

A plant performance improvement program has not been developed to i take advantage of the performance data currently being collected and monitored by the Shitt Technical Advisors (ETA).

Recommendation Develop a plant performance program. The program should include modeling, data analysis, mechanisms for improving efficiency and reli-ability, and responsibility assignments.

. Response We concur with the need for a more effective plant performance 1 improvement program. With STA training scheduled to be completed in July and the addition of two Performance Engineers by January 1,1982, this function will be re-emphasized and expanded to include the above.

Status

. One performance engineer position has been filled. Vacancies still exist for one performance engineer and one performance technician. It is estimated these positions will be filled by June 1983. The performance ,

monitoring effort has been expanded. A formal program is expected to l be in place by December 1983.  !

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3. Findmg (Reference Criterion D)  !

The facilities available for document control are not adequate to support I the necessary and expected effort.

Recommendation Review the long-term needs of the on-site Information Resources Management Group and provide additional work and storage space as required. Provide appropriate areas for use and protection of controlled drawing sets throughout the plant, especially in the I&C Shop area adjacent to the control room.

_ Response The planned administration building expansion add esses some of this issue. Appropriate areas for use and protection of controlled drawings in

~

the I&C shop area will be provided by January 1,1982.

Status Site preparation has started for the new administration building. The i building will be completed and adequate fe.cilities provided for document )

control by September 1983. Improvements for the use 'and protection of <

controlled drawings have been completed.

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l PILGRIM (1982)

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APPENDIX I Page 2 NON-LICENSED OPERATOR TRAINING (INPO Procedure TQ-242, Revision 2)

2. Finding (Reference Criterion C) I The training program for Nuclear Auxiliary Operators is not fully  ;

implemented. -

i Recommendation Implement a structured training program that includes appropriate fundamentals and system checkouts for Nuclear Auxiliary Operators.

NOTE: INPO guidelines referenced above address the development of this program.

Response

Boston Edison agrees and a course outline has been developed and materials are being prepared to implement the program. This program is scheduled to commence July 1,1981. '

Status A program outline has been developed and approved. The program has not yet been conducted, and lesson plans have not yet been prepared to support presentation of the program. It is expected that the first class will be presented in the first quarter of 1983.

LICENSED OPERATOR TRAINING (INPO Procedure TQ-243, Revision 2) .

Finding (Reference Criterion I)

A program of technical, supervisory, and administrative training to address the increased responsibilities of senior reactor operators has not been developed.

Recommendation Develop and implement a training program for senior reactor operators that addresses their increased duties and responsibilities.

NOTE: "INPO Guidelines For Qualification Programs at Operational Units for Nuclear Power Plant Licensed Operators" (Document Number GPG-03) could provide a basis for this program.

Response l Boston Edison agrees with the recommendation and the program will be developed and should commence during the next requalification training cycle.

Status The program has not been developed. It is scheduled for development and implementation in the first quarter of 1983.

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PILGRIM (1982)

APPENDIX I Page 3 MAINTENANCE PROCEDURES (INPO Procedure MA-403, Revision 2) -

Finding (Reference Criterion A)

Vendor instruction manuals used extensively for control of work on safety-related and important non-safety-related equipment are not for-many reviewed and approved.

Recommendation Prior to use in safety-related or important non-safety-related work, vendor instruction manuals should be reviewed and approved in a manner equivalent to that provided for plant procedures. This review should consider applicability of the manual to the work to be performed, accuracy and suitability for controlling work, and established quality check points.

Response

The Integrated Work Control System, utilizing the Erection Control Sheet concept, win implement the above recommendations by requiring an Operations Review Committee review of processess required by vendor manuals not previously reviewed. These reviews win be required by September 1,1982. .

Status The task was of a greater scope than expected. A revised implementa-tion plan is currently unde.r development.

MAINTENANCE HISTORY (1NPO Procedure MA-405, Revision 2)

Finding (Reference Criterion D)

Mechanical, electrical and I & C maintenance history records are maintained but are not reviewed on a systematic basis. Equipment failures and "as found" out-of-specification instrumentation are not routinely evaluated. The potential necessity for more frequent preven-tive maintenance or calibration is not being recognized.

Recommendation A program should be instituted for the systematic review of maintenance history records. Reviews should be used to identify equipment perform-ance trends, adjust preventive maintenance frequency, and improve equipment reliability.

Response

This recommendation has been incorporated as a requirement of the Preventive Maintenance Program.

Status The new PM program is stin incomplete. A new work request system that win include equipment identification and history for trending and tracking is planned. It is scheduled for implementation by June 1983.

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PILGRIM (1982) '

APPENDIX I I Page 4 l MAINTENANCE FACILITIES AND EQUIPMENT (INPO Procedure MA-408, Revision 1) -

3. Finding (Reference Criterion C)

I & C office and work areas do not adequately conform to the needs of the organization. Normal access to the control room through the I & C shop disrupts work and may be a safety hazard for technicians due to crowded conditions. Office space for the I & C supervisor is inadequate and hinders effective work.

~

Recommendation An alternate means of access to the control room should be established and utilized to prevent disruption of activities in the I & C shop.

Arrangement of the shop should also be reviewed and adjusted to provide suitable office space and areas for storing and using prints.

Response

The planned administrative building expansion should vacate offices in ~

the plant and allow for relocation of some of the facility. In the meantime, a temporary trailer facility has been established.

Status The planned administrative building is presently under construction. Its completion is tentatively scheduled for late 1983.

ALARA PROGRAM (INPO Procedure RC-502, Revision 1)

_ Findmg (Reference Criterion D)

The ALARA program does not include a system for establishing specific exposure goals for major tasks or a method for tracking exposure accumulation on such tasks to monitor progress against the goals.

Recommendation

_ Expand the existing ALARA program to include a system for establishing exposure goals and monitoring exposure during major tasks. The exposure goals and tracking system should also include provisions for evaluation and corrective action, when necessary, for exposure accumu-lation in excess of the goals.

Response

This aspect of the ALARA program is being developed and will be

. implemented during the 1981 refueling outage.

Status Plans have been made to acquire the software necessary to track

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accumulated task exposures. Implementation is expected by the end of 1983. Presently there is no formal ALARA program, nor are exposure goals for plant jobs being utilized. However, BECO now requires supervisors to consider ALARA factors in planning and executing work involving radiation exposure. Supervisors will be rated on their per-formance in this area.

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PILGRIM (1982) ,

APPENDIX H

_- Page1 APPENDIX H Performance Objectives Reviewed ORGANIZATION AND ADMINbiTRATION O A.1 Station Organization and Administration Station organization and administrative systems should ensure effective imple-mentation and control of station activities.

OA.2 Mission. Goals, and Objectives Station mission, goals, and objectives should be established and progress monitored through a formal program.

OA.3.1 Management Assessment .

Management should assess and monitor station activities to ensure effective performance of all aspects of nuclear plant operation.

OA.3.2 Quality Programs Quality programs should ensure the effective performance of activities im-portant to nuclear safety.

OA.4 Personnel Planning and Qualification Personnel programs should ensure that station positions are filled by individuals with proper job qualifications.

OA.5 Industrial Safety Station industrial safety programs should achieve a high degree of personnel safety.

OA.6 Document Control Document control systems should provide correct, readily accessible infor-mation to support station requirements.

OA.7 On-site Nuclear Safety Review Committee Review of station nuclear activities by a knowledgeable interdisciplinary group should ensure achievement of a high degree of nuclear safety.

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PILGRIM (1982)'

APPENDIX Il Page 2 OPERATIONS OP.1 Operations Organization and Administration The operations organization and administrative systems should ensure effective control and implementation of department activities.

OP.2 Conduct of Operations Operational activities should be conducted in a manner that achieves safe and l reliable plant operation.

OP.3 Plant Status Controls  !

Operational personnel should be cognizant of the status of plant systems and equipment under their control, and should ensure that systems and equipment are controlled in a manner that supports safe and reliable operation.

OP.4 Operations Knowledge and Performance ~

Operator knowledge and performance should support safe and reliable plant operation.

OP.5 Operations Procedures and Documentation Operational procedures and documents should provide appropriate direction and should be effectively used to support safe operation of the plant.

OP.6 Operations Facilities and Eculoment Operational facilities and equipment should effectively support plant operation.

-. MAINTENANCE MA.1 Maintenance Organization and Administration The maintenance organization and administrative systems should ensure effee-tive control and implementation of department activities.

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MA.2 Plant Material Condition The material condition of the plant should be maintained to, support safe and i reliable plant operation.

M A.3 Work Control System The control of work should ensure that identified maintenance actions are properly completed in a safe, timely, and efficient manner.

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- PILGRIM (1982)

, APPENDIX II Page 3 MA.4 Conduct of Maintenance

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i Maintenance should be conducted in a manner that ensures efficient and .

effective plant operation. l M A.5 Preventive Maintenance l

The preventive maintenance programs should contribute to optimum perform- '

ance and reliability of plant equipment.

MA.6 Maintenance Procedures and Documentation Maintenance procedures should provide appropriate directions for work and should be used to ensure that maintenance is performed safely and efficiently.

MA.7 Maintenance History The maintenance history should be used to support maintenance activities and optimize equipment performance.

M A.8 Maintenance Facilities and Eauipment heilities and equipment should effectively support the performance of mainte nance activities.

TECHNICAL SUPPORT TS.1 Technical Support Organization and Administration

_ The technical support organization and administrative systems should ensure effective control and implementation of department activities.

TS.2 Surveillance Testing Program Surveillance inspection and testing activities should provide assurance that equipment important to safe and reliable plant operation will perform within

. required limits.

TS.3 Operations Experience Review Program Industrywide and in-house operating experiences should be evaluated and appro-priate actions undertaken to improve plant safety and reliability.

TS.4 Plant Modifications -

Plant modification programs should ensure proper review, control, implementa-tion, and completion of plant design changes in a safe and timely manner.

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PILGRIM (1982)

APPENDIX II Page 4 TS.5 Reactor Engineering On-site reactor engineering activities should ensure optimum nuclear reactor operation without compromising design or safety limits.

TS.6 Plant Efficienev and Reliability Monitoring Performance monitoring activities should optimize plant thermal performance and reliability.

TS.7 Technical Suooort Procedures and Documentation Technical support procedures and documents should provide appropriate direc-tion and should be effectively used to support safe operation of the plant.

l TRAINING AND QUALIFICATION '

TQ.1 Training Organization and Administration The training organization and administrative systems should ensure effective control and implementation of training activities.

j TQ.2 Non-Licensed Operator Training and Qualification The non-licensed operator training and qualification program should develop and improve the knowledge and skills necessary to perform assigned job functions.

TQ.3 Licensed Operator Training and Qualification The licensed operator training ud qualification program should develop and improve the knowledge and skills necessary to perform assigned job functions.

_ TQ.4 Shif t Technical Advisor Training and Qualification 1

The shift technical advisor training program should develop and improve the .

knowledge and skills to perform assigned job functions. I

~ TQ.5 Maintenance Personnel Training and Qualification The maintenance personnel training and qualification program should develop and improve the knowledge and skills necessary to perform assigned job functions.

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TQ.6 Technical Training for Managers and Engineers

• The technical training program for engineers and managers should broaden overall knowledge of plant processes and equipment as a supplement to I positien-specific education and training.

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- APPENDIX II

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Page5 TQ.7 General Emolovee Training The general employee training program should develop a broad understanding of l i

employee responsibilities and safe work practices.

TQ.8 Training Facilities and Ecuioment The trahing facilities, equipment, and materials should effectively support training activities. I RADIOLOGICAL PROTECTION  !

RP.1 Radiological Protection Organization and Administration The organization and administrative systems should ensure effective control and implementation of the radiological protection program.

RP.2 Radiological Protection Personnel Qualification -

I The radiological protection qualification program should ensure that radiolog-ical protection personnel have the knowledge and practical abilities necessary to effectively implement radiological protection practices.

RP.3 General Emolovee Training In Radiological Protection General employee training should ensure that plant personnel, contractors, and visitors have the knowledge and practical abilities necessary to effectively implement radiological protection practices associated with their work.

RP.4 External Radiation Exposure External radiation exposure controls should minimize personnel radiation ex-

_ posure.

RP.5 Internal Radiation Exposure Internal radiation exposure controls should minimize internal exposures.

RP.6 Radioactive Efiluents Radioactive effluent controls should minimize radioactive materials released to the environment.

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RP.7 Solid Radioactive Waste Solid radioactive waste controls should minimize the volume of radioactive waste and ensure safe transportation of radioactive material.

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PILGRIM (1982)

APPENDIX II  !

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Phge 6 RP.8 Personnel Dosimetry )

The personnel dosimetry program should ensure that radiatio'n exposures are accurately determined and recorded.

RP.9 Radioactive Contamination Control .

Radioactive contamination controls should minimize the contamination of areas, equipment, and personnel CHEMISTRY CY.1 Chemistry Organization and Administration The organization and administrative systems should ensure effective imple- )

mentation and control of the chemistry program.  ;

CY.2 Chemistry Personnel Qualification The chemistry qualification program should ensure that chemistry personnel have the knowledge and practical abilities necessary to implement chemistry practices effectively.

CY.3 Chemistry Control Chemistry controls should ensure optimum chemistry conditions during all phases of plant operation.

C Y.4 Laboratory Activities Laboratory and counting room activities should ensure accurate measuring and reporting of chemistry parameters, l

1 CY.5 Chemical and Laboratory Safety Work practices associated with chemistry activities should ensure the safety of )

personnel. I

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t CCSTON EUIC3N COMPANY CSD Cevtston Cverrt mosTow. MassacwussTTs c21ss PU!LIC INFORMATioN DePARTMsNT Septe=ber 10, 1981 Mr. Ronald Haynes Director, Region i U.S. Nuclear Regulatory Cor:nission 631 Park Avenue King of Prussia, Pennsylvania 19406

Dear Mr. Haynes:

! Attached is a copy of a report on Pilgrim Station prepared by ,

the Institute for Nuclear Power Operations, along with an F.Y.I.

advisory to local news media.

Copies have also been sent to Karl Abraham, Office of Public Affairs, Region 1. Nuclear Regulatory Cc= mission and Richard Starostecki, Director, Division of Resident and Project Inspection, Region 1.

This infor=ation will be released to the public on Wednesday, September 16.

If I can be of any help, please don't hesitate to call.

Sincerely, .

V f

Walter E. Salvi Manager, Infor=ation Services

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WES/cd Enclosure 4

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% J Attached is a copy of a report on Pilgri= Station prepared by the Institute for Nuclear Pever Operations (INFO) . 1 l

As you can see, this group of nuclear professionals found Pilgri= Station being

" operated and =aintained in a safe' =anner by competent personnel."

INFO conducts these evaluations at all its me=ber companies, every ce==ercially-operated nuclear reactor in the United States.

As the organization states in its preface to the report, its purposes is to "=ake an overall determination of plant operating safety, to evaluate management syste=s and controls and to identify areas needing i= prove =ent." -

By its =e=bership in INF0, Boston Edison supports those purposes. So=e of the area coming under praise fro: INFO vere:

o deter =ined =anage=ent planning and actions to improve conditions in such key areas as outage planning, housekeeping, =arking and identification of syste=s, centrol of spare parts and warehousing, control of plant ccdifications, and individual accountability o an effective fire brigade training progra=

o well-developed operating and emergency procedures in the areas of format, content, and usability o an aggressive ALGA progra including pre-job planning o a =ini=al nu=ber of alar =s in the control rec =

hbongopportunitiesfori= prove =entwere: ,

o For=al progra=s should be established to ensure that tasks assigned to specific individuals are acco=plished.

o M.anage=ent of the solid waste progra= should be i=croved to. decrease the volu=e of waste produced.

o ""here is inadequate work space for the health phys'es iroup, the instru=ent and control group, and the technical support group.

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o Controlled drawings should be updated in a ti=ely manner. So=e are not readable. -

o Operator training on the purpose, scope and operational requirements of plant modifications should be provided before the system is restored to service.

In the vast majority of " opportunities for i= prove =ent", Boston Edison had already identified areas and was either working or had established plans to correct existing situation.

It is important to note that in no case was there any compromise on safety-related issues. .

L70 was for=ed in 1979 by the nuclear power industry to establish bench = arks of excellence for the operation of the nation's nuclear power plants.

Sincerely, Robert J. ..s District Manager, Plymouth Area Tel: Area Code (617) 746-0912 R.!!/cd Attach =ent

t 4 Evaluation Report August 1981 I

Pilgrim Nuclear Power Station l Bos':on Ecison Comoany l

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1 EVALUATION .  !

of PILGRIM NUCLEAR POWER FTATION Boston Edison Company August 1981 I

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- PILGRIM (1981)

Page1 e

SUMMARY

J INTRODUCTION The Institute of Nuclear Power Operations (INPO) conducted its first evaluation of Boston Edison Company's Pilgrim Nuclear Power Station (PNPS) during the weeks of April 13 and 20,1981. PNPS consists of a 655 megawatt (electrical)

General Electric boiling water reactor plant. The station is located on Cape Cod Bay near Plymouth, Massachusetts. The unit was placed in commercial operation in December 1972.

PURPOSE AND SCOPE INPO conducted an evaluation of site activities to make an overall determination of plant operating safety, to evaluate management systems and controls and to identify areas needing improvement. Information was assembled from dis-cussions, interviews, observations and reviews of station documents.

The team examined station organization, training, operations, maintenance, radiological and chemistry activities, and on-site technical support. Emergency preparedness was not included in the scope of the evaluation, nor were corporate activities, except as an incidental part of the station evaluation. As a basis for the evaluation, INPO used its own experience on best practices within the industry and written evaluation criteria which were furnished to the plant in advance. The evaluation standards are high, and the findings and recom-mendations are not limited to minimum safety concerns.

DETERMINATION Within the scope of this evaluation the team concluded the station is being operated and maintained in a safe manner by competent personnel. We noted a positive attitude among station and corporate management personnel toward improvements in station operation and management. The following beneficial practices and accomplishments were noted:

o determined management planning and actions to improve conditions in such key areas as outage planning, housekeeping, marking and identifi-cation of systems, control of spare parts and warehousing, control of plant modifications, and individual accountability I o an effective fire brigade training program ,

o well-developed operating and emergency procedures in the areas of format, content, and usability o an aggressive ALARA program including pre-job planning o a minimal number of alarms in the control room.

. PILGRIM (1981)

Pqo2

• Opportunities for improvement were identified as follows: I o--pormal programs should be established to ensure that tasks assigned to specific individuals are accomplished.

o Management of the solid waste program should be improved to decrease the volume of waste produced.

o There is inadequate work space for the health physics group, the instrument and control group, and the technical support group.

j o Controlled drawings should be updated in a timely manner. Some are not  ;

readable.

o Operator training on the purpose, scope, and operational requirements of plant modifications should be provided before the system is restored to service.

Recommendations are intended to augment the Boston Edison Company's efforts to achieve high standards in its nuclear operations. In taking corrective action, -

the company should consider the underlying significance of findings and recom-mendations. Boston Edison Company's responses to the report are considered appropriate to the findings presented. To follow the completion of these responses, INPO requests written notification of status at six month intervals,

, until the next INPO evaluation.

Specific evaluation findings are in the accompanying Details, and information of an administrative nature is in the Administrative Appendix. These findings were presented at an exit meeting in Plymouth, Massachusetts, on April 24,1981, and were further discussed along with the company responses on July 8,1981, in a meeting with corporate and station management.

The cooperation received from all levels of the Boston Edison Company is appreciated.

E. P. Wilkinson President I

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Paga 3 BOSTON EDISON COMPANY

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Response Summary The management of Boston Edison Company was not surprised by the conclusion of the INPO team that the station is being operated and maintained in a safe manner by competent personnel nor by the note that there is a positive attitude among station and corporate management personnel toward improvements in station operation and management. We were also pleased that the team took I notice of a number of beneficial practices and accomplishments and that it did not identify any items that we had not previously noted for action.

One reason for this is that for a little more than three years we have had an oversight committee of outside experts reviewing our operations from a cor-porate point of view. This committee, known as the Nuclear Review Group, visits Pilgrim and our headquarters on about a quarterly basis. It has free access to personnel and documents and reports its findings with recommendations to top corporate management. It has made substantial contributions in this area of identifying items for improvement in the operation.

Our responses to the specific recommendations are attached in the format requested. Updates will be provided at six-month intervals. The first update I will be submitted by February 1,1982. l 6

PILGRiivi (1931)

Pg34 DETAILS This portion of the report includes the detailed findings. It is composed of six sections, one for each of the major evaluation areas. Each section is headed by a summary describing the scope of the evaluation and the overall finding in that area. The summary is followed by the specific findings, recommendations and utility responses related to each of INPO's evaluation procedures. The evalua-tion procedures that were used are listed in the ADMINISTRATIVE APPENDIX.

i ORGANIZATION AND ADMINISTRATION Station objectives, organizational structures, administrative controls, industrial safety, programs for quality assurance, and surveillance inspections and tests were reviewed.

Several areas were evaluated that indicate strengths within the Pilgrim Station organization. A well-qualified support staff is available, a sound quality control program exists and comprehensive overall surveillance echeduling and computer-based outage planning programs are being developed. -

Areas for improvement are as noted in the following performance areas:

OBJECTIVES (INPO Procedure OA-101, Revision 1)

Evaluation was performed to determine how effectively goals and objectives are disseminated throughout alllevels of the station and how effectively they convey intended operational and maintenance directives. Areas reviewed included the station mission statement, supervisor accountability, availability of station mission documents, assessment programs and measurement of goals and objec-tives attainment. Determinations were made as follows:

The criteria of OA-101 were met.

ORGANIZATION STRUCTURE (INPO Procedure OA-102, Revision 2)

Evaluation was performed to determine how effectively the organization manages the station to ensure safe, efficient operation. Areas reviewed included applicability of the organizational structure diagram, position descriptions for all station personnel, personnel performance evaluation, supervisor's span of author-ity, assignment of backup personnel for each plant management position and individual work load assignments. Determinations were made as follows:

The criteria of OA-102 were met.

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ADMINISTRATIVE CONTROLS (INPO Procedure OA-103, Revision 1)

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Evaluation was performed to determine the effectiveness of the controls for administrative functions. Areas reviewed addressed the program of administra-tive controls for purpose, scope, responsibility, flexibility, level of administra-tive actions and program dissemination. Determinations were made as follows:

Finding (Reference Criterion E)

No clearly defined methods are established to ensure responsibilities and accountabilities assigned by station procedures are performed.

Recommendation Develop and implement programs or procedures that require periodic review for completion of those tasks assigned to individual positions or personnel classifications by station procedures.

Response

Boston Edison concurs with both the finding and recommendation and has recently formalized and computerized the Operations Review Commit-tee Follow List addressing safety-related concerns. The Integrated Work Management System when implemented, in 1982, will address the re-maining concerns.

QUALITY PROGRAMS (INPO Procedure OA-104, Revision 4)

Evaluation was performed to determine how effectively quality programs moni-tor and audit plant activities to promote accomplishment of the station mission.

Areas reviewed included management controls, accountability programs, pro-gram cross checks, program effectiveness, programs for corrective actions and manning. Determinations were made as follows:

Finding (Reference Criterion A)

Management controls are not in effect to require regular evaluation of some aspects of plant operations. Specifically, the areas not being evaluated include the following:

o control room operations o plant chemistry and laboratory practices o security systems o procedures j l

o safety, fire and emergency systems '

o effectiveness of the program for review of in-house and industry events.

Recommendation Develop and implement periodic administrative or quality control review of the activities listed above to ensure quality performance in these areas.

PILGRIM (1981)

Paga 6 In addition to the existing scheduled audits of these areas by the Quality r

-" Assurance Department to meet the requirements of the station Tech-

' nical Specifications and Section 18 of the Boston Edison Quality Assur-ance Manual, a surveillance inspection program will be implemented by the Operational Quality Assurance Group by March 1982. In addition, 2 the Integrated Work Management System will also provide the manage-ment with an ongoing overview of the quality aspects of each task.

1 INDUSTRIAL SAFETY (INPO Procedure OA-106, Revision 1)

Evaluation was performed to determine the effectiveness of the station's safety program in providing a safe, orderly working environment. Areas reviewed included the station's general and site-specific policy, management support for the safety program, and employee and management interface in safety matters.

Determinations were made as follows:

1. Finding (Reference Criteria A, B, and C)

Commitment, support, and involvement in the safety program are not effectively achieved by management, the supervisory staff, or the employees. Specifically, safety meetings and plant fire drill exercises required by company procedures are not being performed.

Recommendation Comply with the published instructions and policies of both the Boston Edison Company and the Pilgrim Nuclear Power Station (PNPS) regarding safety committees and meetings and general employee fire drill exer-cises, specifically:

o Boston Edison Safety Manual (BESM) Safety Policy / Procedures (SP-2) -

Safety Committees o PNPS Nuclear Operating Department Procedure 1.4.17 - Safety Com-4 mittee and Meetings o BESM SP Fire Drill Exercise Response i While the program is not formally documented, the incident ratio at PNPS indicates the safety consciousness of employees. A policy l

statement will be issued and procedures revised to ensure compliance.

This effort will be completed by September 1981. l

2. Finding (Reference Criterion D)

Plant-specific work practices and safety considerations that affect employee safety are not always published and made av,ailable to every employee.

Recommendation Comply with the requirements of the Boston Edison Safety Manual

• regarding new employee safety training and job safety standards. Speci-fically, ensure each new employee is given a copy of the accident l

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• prevention manual and ensure compliance with the requirements of BESM SP-6 (Job Safety Standards).

REBPonse Boston Edison agrees that an accident prevention manual should be distributed or made available to all employees and Boston Edison will review the existing manual and reorder for distribution. This action will be completed prior to September 1981.

3. Finding (General Criterion)

Industrial safety responsibility is a collateral duty of the Senior Nuclear Training Specialist. The demands of his primary duties do not permit him to devote the attention necessary to effective'y administer the industrial safety program.

Recommendation Reassign responsibility for the industrial safety program to an individual trained in the subject and available to give it the necessary attention.

Response

Boston Edison agrees that the duties of the Industrial Safety Officer have evolved into a full-time requirement in view of the increasing modifications activity. A position description is being developed and a target date of September 1981 has been established for filling the position. .

v SURVEILLANCE PROGRAM (INPO Procedure OA-107, Revision 1) 4 Evaluation was performed to determine if an effective program exists to accomplish surveillance inspection and testing. Areas reviewed in the surveil-lance program included completeness, depth, acceptance criteria, results review, notification and control of off-standard conditions, suitable scheduling and training in proper use of surveillance procedures. Determinations were made as fonows:

The criteria of OA-107 were met.

PERSONNEL QUALIFICATIONS (INPO Procedure OA-106, Revision 1)

Evaluation was performed to determine if a program exists for providing qualified personnel to operate and maintain the station. Areas reviewed included the applicability of job descriptions for station positions, the programs for l

personnel promotion and selection, and the program for periodic review of all job descriptions. Determinations were made as follows:

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l The criteria of O A-108 were met.

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- PILGRIM (1981)

Paga 8 TRAINING AND QUALIF_ICATIONS The fo lowing areas were evaluated: training organization and administration, training programs for licensed and non-licensed operators, shift technical advisors and other station personnel, training resources, and training program effectiveness. There were positive features noted in most areas. Of special note were the conscientious and capable training staff, management's support of ' '

training activities, and the structured annual oral examination administered to all licensed personnel. Improvements can be made in the areas discussed in detail below.

TRAINING ORGANIZATION AND ADMINISTRATION (INPO Procedure TQ-211, Revision 2)

Evaluation was performed to ensure that the station has a clearly defin'ed training organization that provides for assignment of responsibilities ' and delegates authority to accomplish those tasks assigned to the training group.

Areas reviewed included the organizational structure and practices, training staff size, ability and authority to schedule and provide required training, and the existence of and adherence to written training plans.

1. Finding (Reference Criterion A)

A formal organizational structure which agrees with actual reporting requirements has not been published.

Recommendation Develop and publish an organizational structure that describes the functional and administrative relationships within the training group.

Response

The Training Manager's position, which was under development during the assessment, has been approved and candidates are being solicited.

To avoid confusion during the development, the anticipated organization change was not published. It will now be made formal prior to July 1, 1981.

2. Finding (Reference Criterion D)

Training programs, as described in.the training manual, have not been effectively implemented in the following areas: s o operations group training o maintenance group training o technical group training.

A new training plan for licensed operator training has been developed and is being implemented. The training manual has not been revised to reflect the new training plan. .

Recommendation Idantify the training programs and records described in the Training Manual that are not being implemented. Review these programs for applicability. This review should include, but not be limited to, weaknesses noted in TQ-243, Criterion A; TQ-244, Criterion E; and TS-701, Criterion D. Implement the training programs that result from this review.

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, . Response Boston Edison agrees with the recommendation. The Training Manual

--will be reviewed to determine applicability of non-implemented training programs and records. Those programs and records identified as applicable will be implemented by May 1,1982.

l TRAINING RESOURCES (INPO Procedure TQ-221, Revision 2)

Evaluation was performed to determine whether sufficient and adequate facil-ities, equipment, and materials are provided to support the training programs.

Areas reviewed included facilities, laboratories, workshops, office space, train-ing materials, aids and equipment, lesson development, and accommodations to support the trainers and trainees. Determinations were made as follows:

Finding (Reference Criterion F)

Lesson plans, reference materials and training aids do not exist for the complete implementation of the licensed operator training, licensed operator requalification training, and shift technical advisor training programs. A plan to produce these materials on an "as needed" sch,edule is being implemented.

Recommendation Prepare the required training program materials in sufficient time to allow for review and practice use. In developing these training materials consider similar weaknesses in TQ-243, Criterion C; TQ-244, Criterion B; and TQ-245, Criterion D. Management should establish goals and priorities to ensure that necessary materials are developed, reviewed and made available for use in all scheduled training sessions.

Response

Boston Edison agrees with the recommendation and will complete all actions by May 1,1982.

TRAINING EPPECTIVENESS (INPO Procedure TQ-231, Revision 2)

Evaluation was performed to determine what measurements are made of the effectiveness of training programs in meeting training objectives and improving operational performance. Areas evaluated included programs for management evaluation of training effectiveness, measurement of trainee and instructor performance, and audits of training activities. Determinations were made as follows:

The criteria of TQ-231 were met.

PILGRIM (1981)

Paga 10 NON-LICENSED OPERATOR TRAINING (1NPO Procedure TQ-242, Revision 2)

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Evaluation was performed to determine whether a training program has been established for non-licensed operators. Areas reviewed included the programs for initial and continued training of non-licensed operators who are not scheduled to become licensed operators. In addition, programs for initial training of non-licensed operators scheduled for eventual licensing were reviewed. De termi-nations were made as follows: .

1. Finding (Reference Criterion A)

An initial training program for non-licensed Nuclear Plant Operators has not been developed. The on-the-job training provided to prepare operators to become " tour-qualified" is unstructured and not effectively implemented.

Recommendation Develop and implement a training program that will prepare the non-licensed Nuclear Plant Operators for their assignments.

NOTE: "INPO Guidelines for Qualification Programs for Nuclear Power Plant Non-licensed Operators" (Document Number G PG-04) could provide a basis for the development of this program. Modifications of the INPO guidelines could be made to correctly address the duties and responsibilities of Pilgrim's " tour-qualified" watch stander during normal, off-normel or emergency operations.

i

Response

The course outline has been developed and is presently being imple-mented by the Training Department for the present class of non-licensed opera tors.

2. Finding (Reference Criterion C)

The training program for Nuclear Auxiliary Operators is not fully implemented.

Recommendation Implement a structured training program that includes appropriate  ;

fundamentals and system checkouts for Nuclear Auxiliary. Operators. I NOTE: INPO guidelines referenced above address the development of this program.

Response

Boston Edison agrees and a course outline has been developed and materials are being prepared to implement the program. This program is scheduled to commence July 1,1981. ,

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Paga 11 LICENSED OPERATOR TRAINING

- (INPO Procedura TQ-243, Rsvisicn 2)

Evaluation was performed to determine the effectiveness of the training

- program that prepares candidates for reactor operator and senior reactor operator (SRO) licenses. Areas reviewed included program content; base level of ,

knowledge; training materials and source inputs; training in systems, plant )

t fundamentals and operating practices; SRO training; and evaluation of trainees and the training program. Determinations were made as follows:

Finding (Reference Criterion I)

A program of technical, supervisory, and administrative training to address the increased responsibilities of senior reactor operators has not been developed. .

j Recommendation L Develop and implement a training program for senior reactor operators that addresses their increased duties and responsibilities.

NOTE: "INPO Guidelines For Qualification Programs at Operational Units for Nuclear Power Plant Licensed Operators" (Document Number GPG-03) could provide a basis for this program.

Response

Boston Edison agrees with the recommendation and the program will be developed and should commence during the next requalification training cycle. .

LICENSED OPERATOR REQUALIFICATION PROGRAM (INPO Procedure TQ-244, Revision 2)

Evaluation was performed to determine the effectiveness of the requalification program in maintaining a high level of skill and knowledge for each Reactor Operator and Senior Reactor Operator. Areas reviewed included development and use of training materials to upgrade licensed operators in fundamentals and to inform them of procedure changes, licensee event reports, plant modifica-tions, changes in station license requirements and changes in vendor information affecting operations. In addition, the policy on use of a . training simulator, periodic program evaluation and provisions for inactive operator identification and requalification were reviewed. Determinations were made as follows:

Finding (General Criterion)

A system to prevent the potential compromise of the annual written examination has not been implemented. The same examination is given five separate times, once to each operating shift.

Recommendation Implement a system to reduce the probability of the e,ompromise of the annual examination.

Response

Boston Edison does not believe the examination content is being compro-mised. However, a system using multiple examinations, variations of the same question or variation of question types will be implemented to i

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PILGRIM (1981)

Pags 12 reduc 3 th3 probibility of potintial compromise cf th3 annual writtsn examination. The anticipated date for initiating this examination policy

_Js ' January 1,1982.

SHIFT TECHNICAL ADVISOR TRAINING (INPO Procudure TQ-245, Revision 1) -

Evaluation was performed to determine if a suitable training policy has been developed and implemented for shift technical advisor (STA) training and education. Areas of interest included a review of the STA program for college-level and site 1pecific instruction, simulator training, retraining provisions, and documentation of all training. Determinations were made as follows:

The criteria of TQ-245 were met except as noted in TQ-221, Criterion F in regard to requalification training.

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, Page 13 l OPERATIONS Organization and administration, conduct of shift operations, tagout practices, use and content of procedures, plant status controls, facilities and equipment, and shift turnover were reviewed. Several good practices were noted, including well developed operating and emergency procedures, a dedicated control room paging system, and the availability of alarm response procedures at each control panel.

Improvements could be made in the areas of tagdut practices, conduct of shift operations, plant status controls, and shift turnover. These improvements are discussed in detail below.

ORGANIZATION AND ADMINISTRATION (INPO Procedure OP-301, Revision 3)

Evaluation was performed to determine the existence of a clearly defined operations organization that provides for the assignment of responsibility and delegation of adequate authority for accomplishment of required tasks. Areas -

reviewed included organizational structure, job descriptions, shift administrative assignments, written and oral instructions and orders, and miscellaneous adminis-trative programs. Determinations were made as follows: - l The criteria of OP-301 were met.

TAGOUT PRACTICES (INPO Procedure OP-302, Revision 2)

Evaluation was performed to determine if established tagout practices ensure protection for personnel and station equipment. Areas reviewed included senior reactor operator approval of safety-related tagouts, double verification of tagged equipment for personnel safety, double verification of important safety-related components, tag coloring and numbering, and clearance log review.

Determinations were made as follows:

1. Finding (Reference Criterion C)

A second verification is not performed for safety-related components and critical balance-of-plant equipment that are repositioned during maintenance, testing or change in operating mode. Use of OPER-38, Shif t Turnover Sheet, as verification of system status, does not meet the intent of this criterion.  !

Recommendation Develop and implement a station policy of second verification for safety-related components and critical balance-of-plant equipment that 1 do not have control room position indication. Modify existing procedures i

as necessary to define the systems and plant conditions requiring independent verification.

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• Pag 214

Response

This recommencation was being evaluated at the time of the INPO

_ assessment as part of the TMI issues. The requirements for second verification have been developed and will be implemented by August 1,1981.

2. Finding (Reference Criterion G)

Although audits of active clearances placed for the watch engineer are done, audits of active clearances covered by maintenance requests are not being performed.

Recommendation Implement periodic audits of clearances covered by active maintenance requests similar to the audits currently in use for red tags issued by the watch engineer. These audits should includa a check for adequacy of the tagouts, verification that tags are in place and equipment properly positioned, and status of the equipment or system covered by the tagout.

Results should be reviewed by appropriate supervisors within the opera-tions group.

Response

This recommendation is incorporated in the Integrated Work Manage- ,

ment System and although not scheduled to be implemented until after the 1981 refueling outage, this particular portion will be implemented prior to startup. .

CONDUCT OF SHIFT OPERATIONS (INPO Procedure OP-303, Revision 3)

Evaluation of the conduct of shift operations was performed to determine if operator activities and the aids for these activities support safe and efficient operation of the station. Areas reviewed included observation of operations, station cleanliness and order, response to abnormal conditions, logkeeping practices, reliability of control room instrumentation, and operator awareness of plant conditions. Determinations were made as follows:

The criteria of OP-303 were met except as noted in TS-703, Criterion C and TS-704, Criterion I.

USE OF PROCEDURES (INPO Procedure OP-304, Revision 2)

Evaluation was performed to determine if procedure content and use are appropriate for conducting operations safely and reliably. Areas reviewed i

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Paga 15 included managamint policies for use of procedures and changes to proceduras

- (short and long term). In addition, procedures were reviewed for clarity, continuity, identification of " sequence required" actions, and suitable advisory information. Determinations were made as follows:

The criteria of OP-304 were met.

PLANT STATUS CONTROLS (INPO Procedure OP-305, Revision 2)

Evaluation was performed to determine if plant status controls are provided to ensure adequate equipment and system availability. Areas reviewed included ,

management programs and policies that provide guidance for status control, actual practices in status control, responsibilities of senior licensed operators assigned to monitor and review status control, and provisions for status control i

under special conditions (e.g., outages, accident recovery or refueling). Deter-minations were made as follows: ,

Finding (Reference Criterion A)

A policy statement that includes several elements of status control was recently formalized. However, it does not cover many elements necessary to ensure that all affected watch stations are kept current.

Recommendation According to the policy statement, it is understood that the associated guidelines will be formally incorporated into procedures by July 1981.

The new procedures should be expandeed to include the following:

o equipment checksheets, status boards or other means to define requirements for each mode or plant condition o documentation at each affected shift level when status changes o formal assignment of an SRO for status change review and control i

o timely communication of status changes to all affected shift levels o periodic status monitoring and evaluation by management o provisions for status control during special situations, such as extended outages, refueling and post-accident recovery.

Response

The recommendations have been incorporated and will be in place by July 1,1981.

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Paga 16

. OPERATIONS FACILITIES AND EQUIPMENT (INPO Procedure OP-306, Revision 2)

Evalidtion was performed to determine if plant facilities and equipment are operated and maintained in a manner that ensures safe and efficient operation.

Areas reviewed included equipment service needs, effect of the working environ-ment on safe and efficient station operation, and adequacy of communications equipment. Determinations were made as follows:

The criteria of OP-306 were met. -

SHIFT TURNOVER (INPO Procedure OP-307, Revision 1)

Evaluation was performed to determine if continuous, correct understanding of station conditions is inaintained at all shift positions. Areas reviewed included programs and policies controlling shift turnover practices for individual shift positions, checklists, operating panel reviews and review of station activities in progress or planned. Determinations were made as follows:

Finding (Reference Criterion B)

Some operating shift positions do not have specific checksheets, or a similar mechanism, to guide the turnover process. A common check-sheet exists for several shift positions, but is limited in scope and does not include many items.

Recommendation Develop turnover checksheets, or similar mechanism, to guide the turnover process for the Watch Engineers, Nuclear Auxiliary Operators and Nuclear Plant Operators (tour men). Broaden the scope of the check-sheets currently used by the Nuclear Operations Supervisors and Nuclear Plant Operators (control room operator). These shift turnover systems should include, but not be limited to, information pertinent to the watch station such as balance-of-plant equipment, jumper log review, testing in progress, and equipment out-of-service; and should provide a method for ensuring that plant status is understood.

Response

Boston Edison has begun to incorporate these parameters and will have the revision in place by September 1981.

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- Paga 17 MAINTENANCE I

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Organ 12&tlon, corrective and preventive maintenance, administrative programs, procedures, maintenance history, special processes, and maintenance facilities were reviewed.

The knowledge and experience of group personnel are a strength to the maintenance and instrument and control (I & C) organizations. Additionally, there is a progressive approach by management -which should contribute to performance of the maintenance function.

Areas where improvements are recommended included preventive maintenance, maintenance procedures, maintenance history, control of test equipment, and maintenance facilities.

MAINTENANCE ORGANIZATION AND ADMINISTRATION (INPO Procedure MA-401, Revision 2)

Evaluation was performed to determine how effectively the maintenance and .

I & C organizations and administrative programs function to enhance perform-ance of maintenance tasks. Areas reviewed included organizational structure,

reporting requirements and practices, staff size, training and retraining, use of position descriptions and span of control for supervisors. Determinations were made as follows

The criteria of MA-401 were met.

1 PREVENTIVE MAINTENANCE (INPO Procedure MA-402, Revision 1)

Evaluation was performed to determine the effectiveness of the maintenance effort in optimizing equipment reliability and performance. Areas of review included governing procedures, equipment included in the program, type and frequency of preventive maintenance (PM), and effectiveness of program coordi-nation and control. Determinations were made as follows:

Finding (Reference Criteria A,B,D,E, and G)

Although some preventive maintenance activities are performed by various groups at the plant, a formal, comprehensive preventive mainte-nance program is needed.

Recommendation Develop and implement a formal, management-approved preventive maintenance program for mechanical, electrical, and I & C equipment.

l l The program should include the following:

o specific criteria for determining what equipment and instrumen-tation will be included

PILGRIM (1981)

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Paga 18 o assignment of responsibilities for program development, imple-mentation, and review o development of individual preventive maintenance procedures for safety-related equipment and instrumentation, and inspection guidelines for other equipment and instruments o establishment of realistic inspection or maintenance frequencies and appropriate types of PM activities.

Response

A plan and schedule to develop a program encompassing but not limited to the above recommendations is presently being developed. Implemen-tation of the plan is scheduled to commence in September 1981.

MAINTENANCE PROCEDURES (INPO Procedure MA-403, Revision 2)

Evaluation was performed to determine if existing maintenance procedures provide for quality and effectiveness of maintenance activities. Areas of review included an assessment of activities governed by procedures, methods of procedure development and revision, and content of procedures. Determinations were made as follows:

Finding (Reference Criterion A)

Vendor instruction manuals used extensively for control of work on safety-related and important non-safety-related equipment are not formally reviewed and approved.

Recommendation Prior to use in safety-related or important non-safety-related work, vendor instruction manuals should be reviewed and approved in a manner equivalent to that provided for plant procedures. This review should consider applicability of the manual to the work to be ' performed, accuracy and suitability for controlling work, and established quality check points.

Response

The Integrated Work Control System, utilizing the Erection Control Sheet concept, will implement the above recommendations by requiring an Operations Review Committee review of processess required by vendor manuals not previously reviewed. These reviews will be required by September 1,1982.

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WORK CONTROL SYSTEM (INP_O Procedure M A-404, Revision 1)

Evaluation was performed to determine the effectiveness of the work control system in use at the plant. The system functions were checked to see if they define and authorize work to be performed by maintenance groups; provide for planning, scheduling and control of actual work; and provide a suitable record of work performed for future reference. Determinations were made as follows:

The criteria of MA-404 were met.

MAINTENANCE HISTORY (INPO Procedure M A-405, Revision 2) l Evaluation was performed to determine if maintenance history records are retained and used to improve equipment reliability and performance. Areas of review included assessment of equipment included in the program, content and accessibility of records, history review and evaluation methods, and procedures for program implementation. Determinations were made as follows: .

Finding (Reference Criterion D)

Mechanical, electrical and I & C maintenance history records are maintained but are not reviewed on a systematic basis. Equipment failures and "as found" out-of-specification instrumentation are not routinely evaluated. The potential necessity for more frequent preven-tive maintenance or calibration is not being recognized.

Recommendation A program should be instituted for the systematic review of maintenance history records. Reviews should be used to identify equipment perform-ance trends, adjust preventive maintenance frequency, and improve equipment reliability.

Response

This recommendation has been incorporated as a requirement of the l 1

Preventive Maintenance Program.

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I CONTROL AND CALIBRATION OF TEST EQUIPMENT AND INSTRUMENTATION (INPO Procedure M A-406, Revision 1)

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Evaluation was performed to ensure that available facilities and procedures provide for accurate test equipment and instrumentation. Areas reviewed included identification, calibration, storage, issuance, usage, shipment and documentation. Determinations were made as follows:

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Finding (Reference Criterion F)

.J!easuring and test equipment -that is damaged or for which the calibration has expired is stored in the same location as operable, ready-for-issue equipment. Lack of segregated storage could lead to inadvertent use of inaccurate equipment.

Recommendation Damaged or uncalibrated measuring and test equipment should be separated from equipment that is ready for issue.

Response .

This recommendation is currently being implemented.

CONTROL OF SPECIAL PROCESSES (INPO Procedure M A-407, Revision 1)

Evaluation was performed to determine if adequate controls exist for perform-ance of special processes. Areas of review included training and qualification of personnel, administrative controls, and control of equipment and materials.

Determinations were made as follows:

The criteria of M A-407 were met.

MAINTENANCE FACILITIES AND EQUIPMENT (INPO Procedure M A-408, Revision 1)

I Evaluation was performed to determine if available facilities ano equipment contribute to the performance of maintenance activities. Areas reviewed l

l Included number, type and condition of tools and equipment; size and location of tool storage areas; adequacy of office and work areas; and the cleanliness and orderliness of maintenance facilities. Determinations were made as follows:

1. Finding (General Criterion)

Spare parts for I & C work are not readily available. Recent efforts to relocate all 1 & C spare parts under control of the central warehouse system has contributed to this problem.

Recommendation Review existing spare parts support and take action to improve avail-ability of I & C spare parts. The following actions should be considered:

o expediting inventory of spare parts and assignment of Boston Edison Company stock numbers i

o issuing updated computer printouts of spare parts inventory on a more frequent basis o developing crar:.ference information for locating identical parts in different plant systems.

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Paga 21

Response

~ Boston Edison believes that the recent relocation of I&C spare parts to the warehouse caused this finding. The first two items are being expedited while the capability to implement the third is in place.

2. Finding (Reference Criterion B)

Adequate tool storage is not available at suitable areas in the plant.

. Recommendation Continue with present plans to stock and man tool issue stations within the plant.

Response

This effort is being supported and should be in place by September 1981.

3. Finding (Reference Criterion C)

I & C office and work areas do not adequately conform to the needs of the organization. Normal access to the control room through the I & C shop disrupts work and may be a safety hazard for technicians due to

crowded conditions. Office space for the I & C supervisor is inadequate and hinders effective work.

Recommendation An alternate means of access to the control roem should be established and utilized to prevent disruption of activities in the I & C shop.

Arrangement of the shop should also be reviewed and adjusted to provide suitable office space and areas for storing and using prints.

Response

The planned administrative building expansion should vacate offices in the plant and allow for relocation of some of the facility. In the meantime, a temporary trailer facility has been established.

1 f

i J

- , - - , - e .-,%--,-- - .- , - - -----v------ -- - - - - *-- - - , -------,----- - - - - - - - - - - - + -w-- - -------s,-,+,

PILGRIM (1981) 1 .

Paga 22 1 -

RADIATION PROTECTION AND CHEMISTRY Organization, administration, radiological protection, radioactive waste manage-ment and process water chemistry were reviewed. This portion of the evaluat';,a was primarily an examination of plant programs and facilities as they function under normal operating conditions. It was concluded that the station's radiation protection and chemistry programs are being conducted in a manner that provides for sufficient controls to protect the public, plant workers and the environment. ,

A number of strengths were noted, including an aggressive, management-sup-ported ALARA program, well-organized contamination control points and the active pursuit of program and facility improvements by station health physics and chemistry . personnel. However, improvements could be made in the management of solid radioactive wastes, the adequacy and efficiency of facil-ities and the methods used for calibration and testing of radiological protection

> instrumentation as discussed below.

RADIATION PROTECTION AND CHEMISTRY ORGANIZATION AND ADMINISTRATION (INPO Procedure RC-501, Revision 1)

Evaluation was performed to determine the effectiveness of. the radiation protection and chemistry organizations and associated administrative control mechanisms in providing the level of services required at the station under normal operating conditions. Areas reviewed included the formal organizational structure, procedures for conduct of operations, staffing levels, training and retraining programs, position descriptions, and management authority. The radiation protection and chemistry groups are organized and administered in an l effective manner. Both organizations are taking steps to increase technician i

staffing to support increased workload and, in the case of radiation protection, to reduce the reliance upon contractor personnel. Planning for future needs appears adequate, and the staff is aggressively pursuing improvements in existing l

i programs. Determinations were made as follows:

l The criteria of RC-501 were met.

l l ALARA PROGRAM (INPO Procedure RC-502, Revision 1)

Evaluation was performed to determine the effectiveness of efforts toward maintaining personnel occupational radiation exposure as low as is reasonably achievable (ALARA) at the station. Areas of interest included the company's ALARA policy, responsibilities for ALARA, level of review for the ALARA program, systems for setting ALARA goals and measuring progress, and the overall scope of ALARA activities.

P!LGRIM (1981)

Paga 23 A formal ALARA program is in place at the station and is managed on a day-to-day bas _is by a dedicated ALARA group consisting of two ALARA engineers and one ALARA technician. A well documented, effective decision-making system

is in use to perform cost-benefits analyses on ALARA efforts for major tasks as l a part of pre-job evaluation and planning. The ALARA group is effectively pre-planning all radiological work on a task basis; however, improvements are possible for job tracking and trend analysis. Determinations were made as follows:

, P Finding (Reference Criterion D) y The ALARA program does not include a system for establishing specific exposure goals for major tasks or a method for tracking exposure accumulation on such tasks to monitor progress against the goals.

Recommendation Expand the existing ALARA program to include a system for establishing exposure goals and monitoring exposure during major tasks. The exposure goals and tracking system should also include provisions for evaluation and corrective action, when necessary, for exposure accumu-lation in excess of the goals.

Response _

This aspect of the ALARA program is being developed and will be implemented during the 1981 refueling outage.

PERSONNEL DOSIMETRY (INPO Procedure RC-503, Revision 1)

Evaluation was performed to determine the effectiveness of the station's dosimetry program in measuring, evaluating and recording occupational radiation exposures. Areas examined included the scope of the dosimetry program, procedural controls, dosimetry selection and use, system operation, and exposure records.

The station's external dosimetry program is efficiently organized and tightly controlled. Clerical support is used effectively to minimize the paperwork burden on technicians and supervisors and to make the system easy to use from the perspective of station radiation workers. Exposure accumulation reports are being provided to plant personnel and supervisors on a daily basis. The dosimetry records group is in the process of converting paper exposure records files to a microfiche system with duplicate off-site storage for permanent records. Deter-l minations were made as follows:

The criteria of RC-503 were met.

l

• PILGRIM (1981)

Paga 24 i

~

RADIATION SURVEILLANCE AND CONTROL (INPO Procedure RC-504, Revision 1)

! Evaluation was performed to determine the effectiveness of the station's radiological surveinance program and radiological work and material control mechanisms in identifying radiological conditions to workers and management.

Areas of interest included surveulance program procedures, surveillance program scope, radiological conditions in the plant, surveillance methodology, manage-ment reviews, work and access controls and solid radioactive waste management.

Determinations were made as follows:

i Finding (General Criterion)

' The station is not as effective as possible in mini.nizing the amounts of

/

/ solid radioactive waste generated and the volume of waste shipped offsite, specifically:

o No pre-collection or post-collection segregation or sorting of com-pactable waste is performed.

o Unnecessary .non-radioactive waste materials are not effectively ~

restricted from entry into radiological controlled areas.

1 o The waste compacting method in use is inferior to that used at other nuclear stations, resulting in lower than normal densities for com-pacted radioactive waste shipments.

l Recommendation

! Develop and implement a program to reduce the amount and volume of compacted radioactive waste. Further, include information and tech-niques in station training programs, such as General Employee Training, i to increase station personnel awareness of the problem.

Items which should be considered include, but are not limited to, the following:

o provision of clean waste receptacles in radiological controlled areas and at the entrances to these areas o removal of all packing materials and protective covering from items

! before they enter a radiological controlled area i

o post-collection sorting of non-contaminated materials.

l l

- Additionally, the station should expedite placing in service the high l density drum compactor recently purchased.

j Response A program to minimize the generation of potential radioactive waste has i been initiated, and installation of the high density drum compactor is anticipated to be completed prior to the refueling outage. General i

l Employee Training programs will include information for the control of i

potential radioactive waste.

l I

f .

PILGRIM (1981)

) Pag 3 25

~

i WASTE AND DI5 CHARGE CONTROL (9 )

(INEO Procedure RC-505, Revision 2) ,

Evaluation was performed to determine the effectiveness of the station's liquid waste control programs in minimizing the generation of liquid radioactive waste  ;

and limiting releases to levels as low as is reasonably achievable. The program elements reviewed included procedures, effluent monitoring system design and function, clean systems sampling, and training. The station is effectively

' controlling the generation, processing and release of liquid radioactive waste.

Determinations were made as follows:

> The criteria of RC-505 were met.

l RADIOLOGICAL SURVEY EQUIPMENT CONTROL AND CALIBRATION

! (INPO Procedure RC-506, Revision 2)

! Evaluation was performed to determine the effectiveness of the station's radiological survey equipment control and calibration program in maintaining a sufficient inventory of instruments and a high degree of accuracy for the radiological measurements made with these instruments. The evaluation covired l

' procedures, storage conditions, reference standard traceability, operational response checks, and calibration methods. Determinations were made as follows:

i, Pinding (General Criterion) f f j The methods employed for calibration and operational response testing l of radiation protection instruments are not adequate to ensure that the instruments will perform accurately over their full useful ranges. Survey instruments and rate meters are calibrated at only one point within the l

effective range of each calibration control and are not checked for j linearity at additional points on each scale or decade of readout.

2 Pancake GM probes used on friskers are not efficiency-checked, and friskers are source-checked with radioactive standards which do not represent radioactivity levels near the station's contamination limit.

Survey instruments are not source-checked prior to use or on a routine schedule.

Recommendation The methods and procedures employed for calibration cf portable radia-

- tion protection instruments should be revised to incorporate the guidance given in Sections 4.1 and 4.2.2 of ANSI N323-1978," Radiation Protection Instrumentation Test and Calibration." As a part of calibration, each frisker equipped with a pancake GM probe should be efficiency-checked with an appropriate radioactive standard. In addition, all replacement i probes should be similarly checked immediately after installation on a calibrated frisker. Scurce checks performed on friskers should utilize a planchet source with activity levels at or near the plant's surface contamination limit.

! Instri' ment operational response checks should be performed prior to use i of instruments or on a routine schadule. The response checks should i include quantitative performance tests such as those described in Section i

- . - . , , , . . . . _ _ . - - . .._--.--,.,_,.._.,__...-,_,-,,..v-n-,-- , _ - - .

PILGRIM (1981)

Paga 26 4.6 of ANSI N323, except that checking each scale or decade of readout l

_Jhould be based on the availability of sources, planned instrument use and consideration of ALARA principles. Instruments should be checked on those ranges which are of the most importance to the user.

Response

Procedures are being changed to reflect linearity response during call-bration. A program for efficiency response determination of pancake probes will be implemented. Source checks performed on friskers will include use of a source with activity le.vels at or near the station's surface contamination limit. Quantitative performance checks will be l performed based on planned instrument use and consideration of ALARA principles. This effort should be completed by September 1,1981.

l I

i PERSONNEL HEALTH PHYSICS INDOCTRIN ATION (INPO Procedure RC-507, Revision 2)

Evaluation was performed to determine the effectiveness of the station's health physics indoctrination program in informing personnel of the risks associated with radiation exposure and the available methods for minimizing exposure.

Areas reviewed included management policy, scope and depth of the indoctri-nation, the training environment, and training documentation.

The health physics indoctrination program is presented as a part of general employee training and consists of videotape presentations supported by live instruction. Overall, the indoctrination program is structured and conducted in a manner that achieves the objective of preparing personnel to work in radiological controlled areas. Determinations were made as follows:

The criteria of RC-507 were met.

PROCESS WATER CONTROLS (INPO Procedure RC-508, Revision 2)

Evaluation 'vas performed to determine the effectiveness of process water controls in maintaining the integrity of plant systems. Areas reviewed included procedures; laboratory quality control; bulk chemical, cleaning agent and reagent control; training; and systems chemistry. The station's chemistry control program is well managed and appears effective in minimizing corrosion. Deter-minations were made as follows:

The criteria of RC-508 were met.

i

• PILGRIM (1981)

Paga 27

~

HEALTH PHYSICS FACILITIES AND EQUIPMENT (INPO Procedure RC-509, Revision 2)

Evaluation was performed to determine the effectiveness of the station's health physics and chemistry facilities and equipment in satisfying station needs and in i

contributing to safe and efficient plant operation. Areas of interest included the number and types of instruments and equipment, the protective clothing inven-tory, the design and working environment of facilities and the ease of access to l and physical conditions of radiological controlled areas. The radiological condition and cleanliness of controlled areas were good. Contamination control i points were well organized to enhance the ease of access and egress for workers to and from contaminated areas. Determinations were made as follows: .

' Finding (Reference Criterion C)

An inadequacy exists in the design and working environment of some

.d-j 4 health physics and chemistry facilities, specifically:

o The health physics and chemistry counting rooms lack adequate air

~

conditioning to support the computer-based counting equipment in -

i these spaces.

o Respirator cleaning, monitoring, storage, and issue facilities are

widely separated, contributing significantly to problems in conducting a respiratory program, particularly during outages.

o The health physics instrument calibration facility and instrument ready room are overcrowded and inadequately equipped for instrument storage.

i l o Background radiation levels in the whole body counting facility are

! variable, and at times are too high for optimum operation of the in-vivo counting equipment.

Recommendation Upgrade the ventilation supply and air conditioning equipment as neces-sdry to ensure adequate temperature control of the counting rooms.

In addition, pursue the completion of the planned modifications of available space to accommodate the respirator handling facilities .and the instrumentation calibration and storage spaces. Consideration should i be given to a similar weakness that exists in RC-506, Criterion B.

Further, pursue the station plan for relocating the whole body counting facility.

Note: At the time of the evaluation, the station had purchased addi-l 1

tionalin-vivo counting equipment and is planning to move the whole body counting facility to a building outside of the protected area where background is expected to be lower and more stable. The move and the installation of the improved equipment should improv'e the counting j performance of the facility.

' Response Modification to the heating, ventilation and air conditioning equipment i

for the health physics and chemistry counting rooms will be performed i

_ , _ - _ _ , _ _ , _ _ . . . _ - _ _ . . _ _ . .-__.____._.___,_._..-._-~.--..-.__m-_-__. -

, _ , - - - - - - _ _ - - _ _ . - . . . ~

4 .

PILGRIM (1981)

Paga 28 4

expeditiously. Facility modifications for respirator handling and instru-d ent calibration are being pursued and should be iri place by September 1,1981. Relocation of the whole body counting equipment to an area outside the restricted area is continuing as planned.

i 1

1 l

j RESPIRATORY PROTECTION PROGRAM l

(INPO Procedure RC-511, Revision 2) l Evaluation was performed to determine the effectiveness of the station's j respiratory protection program in protecting personnel from inhalation of l particulate matter, noxious gases and vapors, and from oxygen deficiency. Areas i reviewed included policy and procedures, identification and control of airborne  ;

materials, selection and use of respirators, respirator maintenance and emer- l gency capabilities.

The station is in the process of developing and implementing a comprehensive respiratory protection program. As an interim measure, respiratory protection equipment is being used wherever warranted by conditions, but credit is not j being taken for protection factors when calculating MPC-hrs of exposur.e to i

airborne radioactivity. Both the existing program and the draft plans for the new respiratory protection program were reviewed during the evaluation. Deter-minations were made as follows:

O Finding (Reference Criterion B) h The station does not have a formal program in effect to control entry to s and work in confined spaces. Additionally, systems that supply breathing ,

! air for use in supplied-air respirators are not sampled to verify the air l meets breathing air quality specifications.

i Note: It is recognized that the station plans to incorporate breathing air

' quality sampling in the new respiratory protection program.

l Recommendation l

Develop and implement a program for entry into confined spaces. The program should include identification of confined spaces, pre-entry testing, ventilation, respiratory protection, worker safety and routine l

monitoring of occupied spaces.

Service air systems should be sampled prior to use as breathing air and i periodically thereafter. The output of the self-contained breathing apparatus bottle charging station should be sampled as an item of routine maintenance.

Response

l

' Implementation of the respiratory protection program will include both confined space and breathing air quality sampling and is scheduled for completion by September 1981.

f

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PILGRIM (1981)

Paga 29

^

. TECHNICAL SUPPORT On-site engineering support was evaluated in the areas of organization and administration, engineering functions performed, nuclear operating experience evaluation, plant modifications, and reactor engineering.

A good effort is being made by the Technical Group to implement plant management goals through specific tasks assigned in the areas of reactor engineering, I&C engineering, and chemistry. The document control system being implemented by the on-site Information Resources Management Group is comprehensive and well organized. Improvements can be made in the following performance areas:

TECHNICAL SUPPORT ORGANIZATION AND ADMINISTRATION (INPO Procedure TS-701, Revision 1)

Evaluation was performed to determine if the technical group is capable of performing all assigned responsibilities, personnel are knowledgeable of their duties, a training program exists to enhance and develop the skills and knowledge of personnel, and non-technical personnel are utilized for non-technical tasks.

The criteria of TS-701 were met except as noted in TQ-211, Criterion D.

ENGINEERING SUPPORT

! (INPO Procedure TS-702, Revision 2)

Evaluation of the engineering support functions was performed. These functions included plant performance monitoring, communication with other support j groups, control of important documents, and adequacy of engineering support facilities. Determinations were made as follows:

i

1. Finding (Reference Criterion A)

A plant performance improvement program has not been developed to take advantage of the performance data currently being collected and monitored by the Shift Technical Advisors (STA).

. Recommendation I

Develop a plant performance program. The program should include modeling, data analysis, mechanisms for improving efficiency and rell-ability, and responsibility assignments.

! Response We concur with the need for a more effective plant performance improvement program. With STA training scheduled to be completed in 1 July and the addition of two Performance Engineers by January 1,1982, this function will be re-emphasized and expanded to include the above.

PILGRIM (1981)

Paga 30

• 2. Finding (Reference Criterion C)

--Drawings are not revised in a timely manner to incorporate as-built information. In addition, legibuity is not good on laminated copies of some controlled drawings and temporary as-built drawings.

Recommendation Develop a system to ensure that drawings are issued and revised in a timely manner. Efforts snould also be made to improve the readability of drawings.

Response

We concur with the finding regarding timely updates of drawings and will address the issue as part of our efforts in the development of a post-work test plan. Drawing legibility is a chronic problem for which corrective action was initiated about two years ago. Efforts will i continue in this area.

3. Finding (Reference Criterion D)

The facilities available for document control are not adequate to support the necessary and expected effort.

Recommendation Review the long-term needs of the on-site Information Resources Management Group and provide additional work and storage space as required. Provide appropriate areas for use and protection of cont. rolled drawing sets throughout the plant, especially in the I&C Shop area adjacent to the control room.

Response

The planned administration building expansion addresses some of this 1

issue. Appropriate areas for use and protection of controlled drawings in the I&C shop area will be provided by January 1,1982.

I i

l NUCLEAR OPERATING EXPERIENCE EVALUATION PROGRAM (INPO Procedure TS-703, Revision 1)

Evaluation was made of the programs in place for analyzing in-house and industrywide operating events. The reporting, review, and follow-up corrective actions for in-house events were examined, along with the method of dissemi-nating the information to appropriate personnel and the industry. For industry events, examination was made of the sources of information reviewed, the screening process employed in surveying events, and the disposition of events relevant to the plant. Determinations were made as follows:

1. Finding (Reference Criterion B)

The program for review of industry events is not fully implemented at the plant. Two new procedures, Nuclear Operations Support Department (NOSD) Procedure 22.01 and Pilgrim Procedure 1.3.33, have been dis-tributed. However, these procedures do not assign specific responsi-bilities to determine information distribution and action at working levels and do not provide for a follow-up system on action items.

. P!LGRIM (1981)

' Paga 31

. Recommendation 1

Revise NOSD Procedure 22.01 and Pilgrim Procedure 1.3.33 to include 4

responsibility assignments and a follow-up system to ensure that action

' items are completed. Provide training to effected personnel.

Response

We concur with the recommendations and will implement procedure l

i changes and provide the necessary training for effected personnel. This action will be completed by January 1,1982.

(

! 2. Finding (Reference Criterion C) j The program for review of in-house and industry events does not include a provision for periodically evaluating its effectiveness. The present scope of quality assurance review does not address effectiveness.

! Recommendation j Modify the existing program for review of in-house and industry expe-j riences to include periodic evaluations for effectiveness. These periodic evaluations should determine the depth of understanding by the group (s) 1 receiving the information, i.e., operations, mechanical maintenance, electrical maintenance, instrument and control, etc. The program should

{

< be independently reviewed by knowledgeable individuals to ascertain that information is provided to the right people in a timely manner and corrective actions are being implemented. .

Responsa j

We concur with the need to evaluate the effectiveness of the operating

experience feedback system. Since an independent review is essential to

! an objective review, we will assign the responsibility of performing these i periodic reviews to an off-site group.

s l

PLANT MODIFICATIONS i

(INPO Procedure TS-704, Revision 1) i Evaluation of the program for processing plant design changes was performed to j determine if changes are implemented in a timely manner while maintaining the

! quality of plant systems, structures, and components. Review of proposed

modifications, prioritization, tracking, testing, verification of installation, and closecut of the design change package were examined. Determinations were j made, as follows

I j 1. Finding (Reference Criterion B)

Effective coordination for design, installation, and testing of plant design changes is not evident.

i Recommendation Establish more effective communications among all groups, on-site and l

{

offsite, involved in the Plant Design Change Request (PDCR) process.

l Designating an individual in each group to act as contact point for

PDCRs can aid in establishing improved communications and coordina-tion.

s

. _ _ . _ _ .._ ,__ _ _. . ~ , _

PILGRIM (1981)

, Paga 32

Response

We concur with the finding regarding more effective coordination among

, ~'the on-site and off-site groups. We have addressed this issue as part of our overall effort to upgrade our Integrated Work Management System and its primary components: Site Work Control System, Inter-departmental Work Request and Authorization Control System, and Plant Design Change Control System.

2. Finding (Reference Criterion C)

PDCRs are not adequately tracked. PDCR status cannot be readily determined from the time an approved request leaves the plant until it is installed and the design change is being closed out by the Management Services Group (MSG).

Recommendation Provide a method furnishing information to the MSG tracker at each stage in the PDCR package so current status of the PDCR can be determined.

Response

We concur with the finding of inadequate tracking. We have addressed '

this issue as part of the overall upgrade of our Integrated Work Management System.

3. Finding (Reference Criterion F)

Entries in the Lifted Wire and Temporary Jumper Log reflect the use of a temporary plant change mechanism to effect permanent plant modifi-cations. These changes are not reflected in plant drawings and other documents and the effect on subsequent plant design changes may be overlooked.

Recommendation Establish a review schedule of suitable frequency for evaluating entries in the Lifted Wire and Temporary Jumper Log. The review should be conducted by an individual or group independent of operations and knowledgeable of subsequent plant modifications. Entries exceeding a specified length of time in the log should be considered for processing as PDC Rs.

Response

We concur with the findings and plan to factor the potential for temporary modifications into our design input and review phases of the Plant Design Change Control System. We also plan to conduct a review of the jumper / lifted lead process to determine if adequate management controls are in place. A periodic assessment of the entries will be considered as part of the review process.

4. Finding (Reference Criterion I)

Effective operator training, drawings, revisions and procedure revisions that result from plant modifications may not be completed prior to placing modified systems in service. Posted Operations Review Com-mittee minutes do not effectively convey modification purpose, scope, or operating philosophy for most plant modifications.

. . PILGRIM (1981)

Paga 33 )

The backlog of PDCR packages in the close-out stage creates the potential for systems being placed in service with inadequate infor-

~iation r available for the operators.

Recommendation Provide operators with training, revised 'as-built drawings, updated procedures, and surveillance requirements regarding installed PDCRs on a formal basis prior to placing modified systems in service. Operator i

understanding of plant and procedure modifications should be periodi-cally evaluated. Iaitiate action to relieve,the backlog of PDCR packages currently awaiting closeout by the MSG.

Response

We concur with the finding regarding a need to improve in various phases of our Plant Design Changes Control System. We have initiated efforts i

to establish a more cicarly defined and regimented post-work test plan which will address at least those elements alluded to in the finding. It is planned to have this effort completed prior to startup from the 1981 outage.

ON-SITE REACTOR ENGINEERING -

(INPO Procedure TS-705, Revision 2)

Evaluation of reactor engineering was performed to assess the use of appropriate procedures, computer programs and control of changes to them, and the support functions provided by the on-site reactor engineers during all modes of plant operation. Additional areas evaluated included communication with other groups that coordinate with the site reactor engineers, the dedication to the mainte-nance of fuel cladding integrity, and the involvement in refueling activities.

Determinations were made as follows:

The criteria of TS-705 were met.

1 I

i.

1 1

filAJnadlLAJ04/

' ' APPENDIX Pago1 ADMINISTRATIVE APPENDIX I. LISTING OF AREAS EVALUATED ORGANIZATION AND ADMINISTRATION OA-101 Objectives .

OA-102 Organization Structure OA-103 Administrative Controls OA-104 Quality Programs OA-106 Industrial Safety OA-107 Surveillance Program OA-108 Personnel Qualifications TRAINING AND QUALIFICATIONS TQ-211 Training Organization and Administration TQ-221 Training Resources TQ-231 Training Effectiveness TQ-242 Non-Licensed Operator Training -

TQ-243 Licensed Operator Training TQ-244 Licensed Operator Requalification Program TQ-245 Shift Technical Advisor Training OPERATIONS OP-301 Organization and Administration OP-302 Tagout Practices OP-303 Conduct of Shift Operations O P-304 Use of Procedures OP-305 Plant Status Controls OP-306 Operations Facilities and Equipment 1 OP-307 Shif t Turnover l MAINTENANCE MA-401 Maintenance Organization and Administration  !

MA-402 Preventive Maintenance MA-403 Maintenance Procedures M A-404 Work Contro1 System M A-405 Maintenance History MA-406 Control and Calibration of Test Equipment and Instrumentation .

M A-107 Control of Special Processes MA-408 Maintenance Facilities and Equipment

PILGRIM (1981)

APPENDIX

.. Pg32 a

__- RADIATION PROTECTION AND CHEMISTRY RC-501 Radiation Protection and Chemistry Organization and Administration RC-502 ALARA Program RC-503 Personnel Dosimetry RC-504 Radiation Surveillance and Control RC-505 Waste and Discharge Control (Liquid)

RC-506 Radiological Survey Equipment Control and Calibration RC-507 Personnel Health Physics Indoctrination RC-508 Process Water Controls RC-509 Health Physics Facilities and Equipment RC-511 Respiratory Protection Program TECHNIC AL SUPPORT TS-701 Technical Support Organization and Administration TS-702 Engineering Support TS-703 Nuclear Operating Experience Evaluation Program -

TS-704 Plant Modifications TS-705 On-Site Reactor Engineering 1

e i

e l

g

- P!LGRIM (1981)

• APPENDIX

! Page 3

e

' s II. BOSTON EDISON COMPANY PERSONNEL CONTACTED ,

j Manager of Nuclear Operations j Staff Assistant ~

! Staff Assistant - Nuclear Safety " '

Chief - Management Service Group '

Chief - Maintenance Group .

V Chief - Technical Group _  ;

Chief - Radiological Group ,

Senior Plant Engineers 4 s Senior Compliance Engineer j Senior Planning Engineer .

! Senior Fire Protection Engineer i Senior Reactor Engineer Senior Chemical Engineer s

' Senior Instrument and Control Engineer Senior Maintenance Engineer ,

Senior Nuclear Training Specialist ,,

r

• l Senior Quality Assurance Engineer -

! Senior Quality Control Engineer ,

! Senior Reliability Engineer  ; l Senior ALARA Engineer

' Nuclear Watch Engineer Nuclear Operations Supervisors Nuclear Plant Operators l

Nuclear Maintenance Supervisors Instrument and Control Supervisors

! Operational Quality Control Group Supervisor

> Acting Supervisor, On-Site Information Resources Management Group Stores Supervisor Health Physics Records Supervisor -

l '

Health Physics Supervisor i

Reactor Engineer .,

! Chemical Engineer l

Plant Engineers '

Quality Control Engineer j

ALARA Engineer 1 (,

Radiological Engineer i Shif t Technical Advisors i Nuclear Control Technicians >

Nuclear Auxiliary Operator

! Manager - Stores Department Quality Contro1 Inspector Physician's Assistant i Nuclear Training Specialist Maintenance Skills Instructor ,

Waste Management Coordinator Health Physics Technicians l

Health Physics Clerk i Training Group Clerk l Instrument and Control Clerk l

j x , I

- - - . , _ _ . ~ _ . . , . . . . . _ , _ _ . , - . _ _ ._,____,_ _ _ _