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Interoffice Correspondence ia
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l M. S. Hobby To:
F. D. Williame f April ag, FROM:
In response to your questions in your letter o 1ses, I have the following reply.-
for operation Mr. R. P. Mcdonald reports to A. W. Dahlberg d Hatch.
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and support activities of Plante Vogtle anattach i h d organization i
l chart showing the reporting.
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GeorgiaPower A / ff Corporate Guidelines NO. 1.1.2 i k SUBBCT flEVISION 5-19-89 i POSITIVE DISCIPLINE 8 RNIE 1 of 9 l* i 1 It is Company policy to enhance employee performance, i l POLICY to stimulate individual accountability and to foster self-discipline through the Positive Discipline J Program by recognizing exemplary performance and by oorrecting performance problems through non punitive means. t I GUIDELINE: i I. GENERAL A well. disciplined work force is necessary to accomplish i the Company's mission. Often times, however, traditional ' punitive discipline -- usually called " progressive i discipline" -- does not work. It sometimes achieves l employees' short-term compliance -- but not their long-term commitment. l Positive Discipline is a system in which the responsi-i l bility for good performance is properly placed on employees themselves. If their performance is good, it [ is recognized and applauded. If it is not, they are reminded of the need to meet job expectations and are asked to commit to improving their performance. Punitive measures such as reprimands and disciplinary suspensions are rep?.sced by non-punishing steps which avoid embarrassment and resentment, and are more consistent M th e.reating employees as adults. Additionally, diociplinary steps remain active for a .specified time, giving employees a strong incentive to improve. Under Positive Discipline, supervisors must still ensure i that Georgia Power's expectations of safety and efficiency are met. By working with employees in a non-threatening way, supervisors can ensure our standards are 1 met by gaining their employees' commitment to the 1 Company's mission. II. TEE POSITIVE DISCIPLINE SYSTEM A. Recognition j Recognizing good performance'is one of the best ways j 1 j to manage performance. The supervisor should either talk informally with the employee or document his j recognition with a memo that would go both to the employee ano the personnel file. An employee is to be recognized for any of the following achievements: { i // /,/ ^
Corporate Guidelines GeorgiaHower A No. . 1. 2 summer POSITIVE DISCIPLINEe REVISION 0-19-89 R40E 2 of 9 p 1. Doing something above and beyond expectations. 2. Performing competently and diligently over an extended period of time. 3. Taking effective action in a crisis or emergency. 4. Developing an idea that enhances safety or productivity.
- 5. *Providing special training or assistance to other employees.
6. Maintaining an excellent attendance record over a significant period of time. 7. Exhibiting a high spirit of teamwork that is demonstrated through specific actions. B. Coaching Coaching is an effective method for the immediate supervisor to enhance performance or correct an emerging performance problem. Coaching is not a formal level of discipline. The purpose of coaching is to make the employee aware of a deficiency and jointly develop offactive solutions. Documentation To help supervisors organize their thoughts for this and other corrective discussions, use of the Employee i i Discussion Guide (Fora 705795) is recommended as l preparation for the coaching discussion. The discussion guide may be kept by the supervisor but not placed in the employee's personnel file. More than one coaching session may be appropriate before initiating formal discipline. Bowever, coaching is not required prior to formal discipline. C. Formal Levels of Discipline 1. Level One -- Oral Reminder a. Application The Oral Reminder l's the first level of I formal discipline in the Positive Discipline l process. It is used either when an employee em [.-
i l' Corporato Guidelines GeorgiaPowei... NO. 1.1.2 l SMENET REVIBeON 5-19-89 POSITIVE DISCIPLINE
- RMME 3 of 9 i
t f does not respond to coaching or when the seriousness of the behavior warrants this level of attention. In an oral Reminder, the immediate super-visor describes how the employee is not l meeting the supervisor's expectations. The supervisor explains those expectations and f j the good business reasons for their j existence. The employee is told that this is the first formal level of the disci-plinary process and is asked for a cameitsent to correct the problem. At the conclusion of the discussion, the supervisor expresses confidence in the employee's i ability to improve. 1 I b. Approvals l Immediate supervisors have the authority to issue Oral Reminders without prior review by ] higher management. c. Documentation An Oral Reminder is documented by placing .r the Employee Discussion Guide in the j employee's personnel file. The employee will be given a copy as well. i l If the employee corrects the problem, the Employee Discussion Guide will be removed l from the employee's personnel file and given i to the employee six months later, with verbal recognition for the improvement. If .i - the employee does not correct the problem, 1 or another similar infraction occurs within i the six months, discipline should be escalated to the next level. 2. Level Two -- Written Reminder a. Application A Written Reminder is the second level of 4 formal discipline in the Positive Discipline process. It is-administered when either the employee does not-seet a commitment to l improve following an Oral Reminder, or when 4 a single infraction is serious enough to warrant that level of discipline. em
GeorgaPower A [' Ceapeaste GuidaHnes NO. 1.1.2 summet ArnWON 5-19-89~ POSITIVE DISCIPLINEe PAGE 4 of 9 ' i r i i i A Written Reminder is a formal meno to an employee from the immediate supervisor. It documents a discussion about unacceptable behavior or a performance problem, the i supervisor's expectations, and what the employee intends to do to correct the 1 problem. Supervisors should use the l Employee Discussion Guide to prepare for and i document this interview. The meno is 3 written after the formal disciplinary interview and a copy given to the employee. j b. Approvals Supervisors should obtain the prior review l of at least their own immediate supervisors before administering this level of discipline. i Documentation c. A Written Reminder is documented by placing l the formal meno and the 2mployee Discussion Guide in the employee's personnel file. The employee will be given a copy of both the A j. meno and the Employee Discussion Guide. copy of the meno and the Employee Discussion { Guide must be forwarded to Vice President, Human Resources for use only in' legal proceedings. If the employee corrects the problem, the j meno and Employee Discussion Guide will be removed from the employee's personnel file twelve months later and given to the employee with verbal recognition for i If the employee does not correct j improving. the problem, discipline should be escalated i j to the next level. } Level Three -- Decision Making Leave (DML) 3. a. Application ] i A Decision Making Leave is the third and final level of formal discipline in the { Positive Discipline system. It is given to an employee when the employee does not meet a commitment to improve following a Written Reminder, or when a single infraction is i 4 4
.I Corporate Guidslines GeorgiaPower A NO. 1.1.2 l' SULECT REVSON 5-19-39 POSITIVE DISCIPLINge PaOE 5 of g ll-i I serious enough to warrant this level of f i i discipline. i The DNL consists of a discussion between the employee and his immediate supervisor, during which the supervisor, using the Employee Discussion Guide, makes clear the extreme seriousness of the employee's problem and the requirement for a total j j performance ccanitment. The employee is told to make a conscious decision whether to seet Georgia Power's expectations in all areas or to resign from the company. ) The employ.ee is given the following workday i off with gay to think about the matter, and is toI3 to report back to the supervisor the i next workday with a decision. If possible, avoid giving a DML the day before an off day. When the employee returns, the l, supervisor reinforces the seriousness of the situation and receives either the employee's i commitment to improve or a notice of i resignation. If the employee elects to keep f the job, specific notice should be given that any performance problem requiring disciplinary action is likely to result in i the employee's dismissal during the time the l DML remains actively in the employee's file. i b. Approvals Supervisors should obtain the prior review of at least their own and the next higher level of supervision before administering a I DML. L c. Documentation h After an employee returns from a DML, the supervisor will write a formal memo to the i employee outlining the employee's decision This memo and l and commitment to improve. in the Employee Ciscussion Guide will be put the employee's personnel file. The employee will be given a copy of both the memo and the Employee Discussion Guide. A copy of i the meno and Employee Discussion Guide must be forwarded to the Vice President,:Busan Resources for use only in legal proceedings. l L . u. I
~ _ _ _ _ Corporate Guidslines GeorgiaPower A j NO. 1.1.2 l, ausmCT J POSITIVE DISCIPLINEe HEVISION 5-19-89 MkGE 6 of 9 j If the employee corrects the problem, the j meno and the Employee Discussion Guide will be removed from the employee's personnel file eighteen months later and given to the 4 l employee with verbal recognition for improving. i D. Termination l j An employee will be terminated when adequate improvement is not made after a DNL or when the employee commits another infraction which might j 3 i otherwise call for formal discipline while a DML j is actively in the file. l Employees may also be terminated for very serious infractions or violations of company policy. J Examples include theft, certain violations of the s1cohol and drug policy, and fighting. Approvals I Supervisors should obtain the prior review of at least their own and the next higher level of supervision before terminating an employee. 1 III. ADMINISTRATIVE GUIDELINES l A. Performance problems that require discipline are a divided into three general areas: Safety and conduct, Work Performance, and Attendance. Employees may have a maximum of three Oral Reminders at any time and these must all be in separate categories. l Should another performance problem occur in a i category where there is already an active Oral Reminder, the discipline must escalate to a higher j level, usually a Written Reminder. l Similarly, the maximum number of Written Reminders that may be active at one time is two; these also must be in separate categories. Should another r-performance problem occur in a category where there is already an active Written Reminder, the discipline step must escalate to a DNL. Likewise, if two written reminders are in effect and a problem develops in a third category, the disciplinary level j must also escalate to a DNL. Because the Decision Making Leave requires a total performance commitment by the employee, there may only be one active DML. If an employee is not StH I
Cwporate Guidelines GeorgiapowerA NO. 1.1.2 SUBJECT REVISION 5-19-89 POSITIVE DISCIPLINEe PAGE 7 of 9 i o terminated after committing a significant infraction while under an active DML, the decision not to terminate must be documented and approved by the supervisor who authorized the original DML, or another appropriate level of management. 2 B. Administrative Suspensions An administrative suspension is used to remove the l employee from the work site while the supervisor investigates certain infractions. Some examples t include theft, fighting, violation of the alcohol and i drug policy, or insubordination. Employees who are placed on administrative suspension will be paid i their regular straight time wage unless a decision is In those cases, the made to terminate the employee. termination will be made effective on the date the employee was suspended. In no case will an employee j be suspended without pay. l C. Deactivation i A very important feature of Positive Discipline is deactivation. When an employee satisfactorily corrects a problem that required discipline, the Employee Discussion Guide and disciplinary meno are i removed from the employee's personnel file and returned to the employee after the active period of that discipline. The steps remain active as follows: i Oral Reminder: 6 months Written Reminder: 12 months i Decision Making Leaves 18 months When an employee corrects a problem and maintains satisfactory performance in that category for the required period, his personnel file is purged of any { Employee Discussion Guides and/or disciplinary memos that pertain to that infraction. Other records such as accident investigations, positive drug test 4 results, and attendance rectros 5 main a part of the employee's personnel file. The employee's In the improvement should be verbally acknowledged. casesof dritten Reminders and DML's, copies are maintained by the Vice President, Human Resources for ] legal purposes o'nly. Supervisors may contact the Labor Relations D. Department or the Equal Opportunity Section for ~ assistance in administering this policy. 6
1 FRte Guidelines GeorgaPower A mo. 1.1.2 j, SMhECT REVISION 5-19 39 POSITIVE DISCIPLINEe i P&GE s of 9 9 4 This policy does not alter existing appeals E. procedures for both covered and non-covered a employees. This policy is not intended as a contract, either ~. { bargained nor implied, nor does.it alter any 4 contractual agreements already in effect. 4 Summer students, co-ops, temporary employees, and G. employees in their trial period are excluded from this policy. If coaching is not sufficient for these employees, and formal discipline is required, they 1 should be terminated. POSITIVE DISCIPLINE TRANSITION IV. -(This portion of the policy will become void after all areas of the Company implement positive discipline.) 4' employees must have any 2 As this policy takes effect, f previous discipline converted to the Positive Discipline system. The following guidelines are for use in making ~ i this conversion. During the implementation period, the levels of f A. progressive discipline should be roughly equated to the levels of Positive Discipline as follows: ar 4 l Progressive Discipline Positive Discipline Coaching Memorandum of Discussion = t Oral Reminder = Written Reprimand Written Reminder First Disciplinary Suspension = (Active 12 months) Second Disciplinary Suspension = Written Reminder (Active 18 months) i An employee given a final warning prior to Note: implementation is still subject to immediate termination for a similar infraction under Positive Discipline. Employees who recently have been disciplined should B. have their personnel files reviewed prior to implementation or when they transfer into a participating location after the implementation has At that time, management should convert their begun. k previous discipline to the corresponding level of Positive Discipline. Management should also apply h I
.e [, Corporate Guidelines GeorgaPower sh NO. 1,1,2 SUBJECT POSITIVE DISCIPLINE
- IIEVISION 5-19-89 l!
pnGE 9 of g i the time limits that go with each level of Positive i i Discipline. For example, if an employee received a Written Reprimand two months before implementation began, i that reprimand should be converted to an active Oral l Reminder with four months remaining before it is deactivated. The same would apply to an employee who transfers into this location from another organization not yet using the Positive Discipline System. i Employees who transfer out of a Positive Discipline area should not have any active Positive Discipline 1 converted to the corresponding step of progressive j discipline. While Positive Discipline is being implemented C. throughout the Company, documentation of deactivated discipline will not be destroyed. It will be j 4 i returned to the employee as stated in the policy, but ) a copy will be kept in the file with a note that it 1 has been deactivated.- When Positive Discipline is fully implemented, these notated records will be i returned to the employee. Similarly, records of discipline from earlier in the i employee's career which would have been deactivated under Positive Discipline, will be batched and marked l as inactive. It will not be used as a basis for i future discipline. When Positive Discipline is fully implemented,-it, too, will be returned to the j employee. d President and Chief Executive Officer l I I ) i $NO
\\ UNITE 3 STATES j NUCt. EAR RECULATGGY CGCMISlON &p CEGION 11 5 tot eAARIETTA ST., N.W. \\. ATLANTA. GEOAGtA 30323 JUN l a ing.. Docket Nos. 50-424 and 50-425 License Nos. NPF-68 and NPF-81 Georgia Power Company ATTN: Mr. W. G. Hairston, III Senior Vice President - Nuclear Operations P. U. Box 1295 31rminghar., A!, 35201 Gentlemer.:
SUBJECT:
NOTICF OF VIOLATION (NRC INSPECTION PEPORT NOS. 50-424/89-14 AND 50-425/89-15) This refers to the Nuclear Regulatory Connission (NRC) inspection conducted by Messrs. J. F. Rogge and R. F. Aiello, on March 18 - May 5,1989. The inspection included a review of activities authorized for your Vogtle facility.. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed Inspection Report. Areas examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress. The inspection findings indicate that certain activities appeared to violate NRC requirements. The violation, references to pertinent. requirements, and elements to be included in your response are presented in the enclosed Notice of Violation. The enclosed Inspection Report also identifies activities that appeared to violate NRC requirements but are not being cited; therefore, no response is required for these items. In accordance with Section 2.790 of the NRC's " Rules of Practice." Part 2 Title 10. Code of Federal Regulations, a copy of this letter and its enclosures will be placed in the NRC Public Document Room. The responses directed by this letter and its enclosures are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No. 96-511. Ik % q0 (p6HF91 & 9 PP ~
' Georgia P6 er Company 2 JUN 15 589 Should you have any questions concerning this letter, please contact us. Sincerely, H Alan R. Herdt, Chief Reactor Projects Branch 3 Division of Reactor Projects
Enclosures:
1. Notice of Violation 2. Inspection Report cc w/ enc 1s: R. P. Mcdonald, Executive Vice President - Nuclear Operations C. X. McCoy, Vice President - Nuclear G. R. Fredrick, Quality Assurance Site Manager G..Bockhold, Jr., General Manager Nuclear Plant J. A. Bailey, Manager - Licensing
- 8. W. Churchill, Esquire, Shaw, j
Pittman, Potts, and Trowbridge J. E.-Joiner, Esquire. Troutman, Sanders, Lockerman, and Ashmore D. Kirkland, III, Counsel. Office of the Consumer's Utility Council State of Georgia 4-4 i 4 2 9 5 i ,w ~ w
4 o ENCLOSURE 1 i ~ NOTICE OF VIOLATION ) l Georgia Power Company Docket Nos. 50 424 and 50-425 j Vogtle, Units 1 and 2 License Nos. NPF-68 and NPF-81 1 1 i During the Nuclear Regulatory Commission (NRC) inspection conducted on March 18 - May 5,1989.. a violation of NRC ' requirements was identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2. Appendix C (1988), the violation is listed below. l 10 CFR Part 50 Appendix B, Criterion V, states that activities affecting quality shall be prescribed by documented instructions, procedures, or i drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or . drawings. Technical Specification 6.7.1.a requires that written procedures be established, implemented, and maintained covering activities delineated in i j Appendix A of Regulatory Guide 1.33. Revision 2 February 1978. t i-Contrary to the above, six examples were identified where the licensee j failed to appropriately establish or implement procedures as follows: 1. On April 28, 1989, following an NRC inspection of a major portion of the control rooms and TSC drawings, the inspector identified that I administrative procedure 00101-C, " Drawing Control," Step 3.4.4, and engineering procedure 50009-C, "As-Built Notices," Step 4.6.3, were j not implemented in that the primary safety-related drawing's as-built j notices were not ensured of drawing legibility prior to distribution. I j 2. On April 2,1989, the inspector identified that operations procedure 12004-C, " Power Operation," Steps 4.1.3.g and 4.1.4, were not i implemented in that the licensee failed to open all four Unit 2 Generator level prior to placing the bypass feed regulation bypass feed isolation valves and failed to stabilize #3 Steam l valve in automatic. l 3. On April 3,1989, following a feedwater isolation, the licensee identified that startup test procedure 2-6A8-01, " Dynamic Automatic Steam Dump Control " ' was not adequately established in that attachment 10.5 incorrectly specified the wrong polarity for a test i input signal which resulted in six steam dumps opening fully. This procedure error was identical to an error discovered during the Unit 1 startup test program. l
Vogtfe Units 1 and 2Gegr ia Power Company 2 Docket Nos. 50-424 and 50-425 .j. License Nos. NPF-68 and NPF-81 4 On April 7,1989, following a feedwater isolation on Unit 2, the 3 licensee identified that a failure to implement procedure 12004-C, i " Power Operation," Step 4.1.3, had occurred in that long-cycle i. feedwater recirculation cleanup was not secured which resulted in all j four steam generators being cross connected. This condition lasted j until a level imbalance resulted in a feedwater isolation. 4 { 5. On March 26, 1989, the licensee identified a failure to adequately establish procedures 13105-1 and 13105-2, " Safety Injection System," in that the procedure for filling accumulators resulted in the inoperability of the safety injection flow path during Mode 3 j operation. This procedure was utilized on nine occasions on Unit 1 and one occasion on Unit 2. 6. On December 8,1988, with Unit 1 at 100% power, the inspector 4 identified that the licensee had failed to establish an adequate procedure 12004-C, " Power Operation," Step 4.1.37, for placing AMSAC equipment in operation in that the procedure specified the equipment i-in service at 60% when the design basis specifies 40%. AMSAC equipment is required by 10 CFR 50.62 to automatically initiate the auxiliary feedwater system and initiate a turbine trip under j conditions indicative of an anticipated transient without scram. This is a Severity Level !Y violation (Supplement !) Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company is hereby I required to submit a written statement or explanation to the Nuclear Regulatory i Connission, ATTN: Document Control Desk Washington, D.C. 20555, with a copy to the Regional Administrator, Region !!, and a copy to the NRC Resident l Inspector, Vogtle, within 30 days of the date of the letter transmitting this Notice. This reply should be clearly markeJ is a " Reply to a Motice of Violation" and should include: (1) admission or denial of the violation. (2) the reason for the violation if admitted. (3) the corrective steps which have been taken and the results achieved.-(4) the corrective steps which will be taken to avoid further violations, and (5) the date when full compliance will be achieved. Where good cause is shown, consideration will be given to extending the response time. If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked or why such other actior 1 as may be proper should not be taken. 1 FOR THE NUCLEAR REGULATORY COMMISSION i h + Alan R. Herdt, Chief Reactor Projects Branch 3 Division of Reactor Projects Dated at Atlanta, Georgia this 15 day of June 1989 t' h t
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uwss..=. arms 3 NUCLEAR C:ESULAi/CQY CC48881SSICN / n e m o se n y ,/ S m isanwna sr n.w. ATLANTA. GeORGaA 30333 3 ~ Report Nos.:- 50-424/89-14 and 50-425/89-15 Licensee:' Georgia Power Company P.O. Box 1295 l Birmingham, AL 35201 4 i Docket Nos.: 50-424 and 50-425 License Nos.: NPF-68 and NPF-81 j Facility Name: Vogtle 1 and 2 Inspection Conducted: March 18 - May 5, 1989 Inspectors: / / ' ~.' / m J. h "Wogge, Senior Resident Inspector Date Signed i A/ C.. e A-r/.ry? R. PT Aiello, Resident Inspector Date 51gned /-% /~/[~?? n-, C. A. Patterson, Project Rfigineer (April 3-6) Date Signed j . c )- !~/J ~ ' / ~ / J..ErManning, Hatch 5enfor Resident (April 1-Z) Date Signed /. /L l~/! ~ " ' R. t. Prevatte, Sumer Senior Resident (April 1-Z) Date Signed d [ -/. ~ / l P. C..ffUpkins, Susmer Resident IApril 1-Z) Date Signed Accompanied By: Rick Mc her r (March 27-30) Approved By: [ <, r__ di 4 [- '/S T / M. V.'/51nkule, Secti6n Chief Date Signed / Divis4on of Reactor Projects I i
SUMMARY
Scope: l This routine inspection entailed resident inspection in the following areas: plant operations, radiological controls / chemistry, maintenance, surveillance, -security, startup testing (Unit 2), engineering technical support, and quality programs and administrative controls affecting quality. l I
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2 Results: In the areas inspected, fourteen violations were identified. Of these, one violation was cited, and thirteen violations were non-cited pursuant to the discretionary provisions of the NRC Enforcement Policy. The cited violation was identified in the area of operations, and it involved six examples of failure to establish or implement procedures. One of the six examples pertained to Unit 1 only (paragraph 5.f), three pertained to Unit 2 only (paragraphs 4.b(3)(q). a.b(3)(r), and 4.b(3)(s)), and two pertain to both units (paragraphs 2.b(1) and 3). Of the thirteen non-cited violations, five pertained to Unit 1: one in the area of radiological controls / chemistry . (paragraph 4.b(2)(d)). two in the area of surveillance (paragraphs 4.b(2)(a) and 4.b(2)(b)), and two in the area of emergency technical supoort (para-graphs 4.b(2)(c) and 4.b(3)(h)). The remaining eight non-cited violations pertained to ' Unit 2. Three were identified in the area of plant operations (paragraphs 4.b(2)(f), 4.b(3)(m), and 4.b(3)(p)), three were identified in the area of radiological controls / chemistry (paragraphs 4.b(2)(h), 4.b(2)(1), and - 4.b(2)(j)), one was identified in the area of maintenance (paragraph 4.b(2) (k)), and one was identified in the area of engineering technical support (paragraph 4.b(2)(e)). Two inspector fallowup items were also identified involving (the adjustment o the P-9 setpoint when steam dumps are removed from service paragraph 3) and the resolution of restoring the safety system monitor panel to a condition to correctly indicate the operability status (paragraph 5.d). Two strengths and one weakness was noted within the report. The areas of maintenance and startup testing (Unit 2) were noted as strengths with the area of operations noted as a weakness. f Maintenance (paragraph 2.b(7)) was considered a strength primarily due to j the planning and execution of the work schedule. Short system outages on L Unit 1 and short plant outages on Unit 2 were effectively conducted. Most t l noteworthy was the elimination of a 10-day scheduled outage during the j Unit 2 test program due to this proficiency. i Startup Testing on Unit 2 (paragraph 3) was a second strength even though one procedure error resulted in a preventable transient. The transient l was preventable because the identical error was identified during Unit 1 test program. More significant was the proficient and efficient conduct of the Remote Shutdown Test and the Loss of Offsite Power Test. Operations evidenced weakness in the area of procedure establishment and implementation of the basic operating procedure 12004-C " Power Operation." Examples included in the cited violation are failure to open bypass isolation valves (paragraph 3), to secure from long-cycle cleanup (paragraphs 3 and 4.b(3)(s)), and to perform the transfer from auxiliary to main - feedwater (paragraph 3). Other operations errors were noted in L the LERs (paragraphs 4.b(2) and 4.b(3)). This concern has been verbally -expressed to licensee management. i e I 4
REPORT DETAILS 1. Persons' Contacted 3 Licensee Employees 1
- G. Bockhold, Jr., General Manager Nuclear Plant
- A. L. Mosbaugh, Plant Support Manager 4
- R. M. Odom, Nuclear Safety & Compliance Manager / Plant Engineering j
Supervisor
- J. E. Swartzwelder, Manager Operations W. F. Kitchens, Assistant.eneral Manager Plant Operations R. L. Legrand, Manager f. emistry and Health Physics
- H. M. Handfinger, Manager Maintenance i
G. A. McCarley, ISEG Supervisor j
- G. R. Frederick, SAER Supervisor j
W. E. Mundy, Quality Assurance Audit Supervisor C. L. Coursey, Maintenance Superintendent Other licensee employees contacted included craftsmen, technicians, supervision, engineers, operations, maintenance, chemistry, quality f control inspectors, and office personnel. j-
- Attended Exit Interview An alphabetical list of acronyms and initialisms used throughout this report are listed in the last paragraph.
2. Operational Safety Verification - (71707)(93702)(71715) Unit 1 operated this inspection period in Power Operations (Mode 1) at 100t reactor power. 4 i Unit 2 began this inspection period in Mode 4 (Hot shutdown). On l March 18, 1989 Unit 2 entered into Mode 3 (Hot Standby). Later that same day (night shift), Unit 2 experienced an inadvertent SI due to personnel error followed by an NUE declaration. On March 19. following the SI, Unit 2 experienced a CVI due to 2RE-2565 radiation monitor. Additionally, on March 19, (night shift), Unit 2 experienced a FWI due to P-14 on SG e4 caused by personnel error. On March 28 Unit 2 entered Mode 2 (Startuo), went critical, and commenced low power physics testing. On April 5, MFP "A" tripped resulting in a MDAFW pump actuation. On April 7, Unit 2 entered Mode 1. Leter that same day, a FWI occurred as a result of a Hi Hi ~ SG 1evel. The unit later entered Mode 2. The unit reentered Mode 1 on April 8. On April 9 MFp "A" tripped resulting in a M0AFW pump actuation and subsequent Mode 2 entry. The unit reentered Mode 1 on April 10. The main turbine was tied to the grid on April 11. Later that same day, the reactor was tripped from the remote shutdown panel and placed in Mode 3 as i part of a required test. While recovering, the unit received an AFW actuation during transfer of controls from remote shutdown panel with both MFW pumps tripped. On April 12 the unit entered Mode 2 and went critical -~ = -
d 2 i. ~ j with subsequent entry into Mode 1. On April 14, the unit conducted a LOSP l test with subsequent entry into Mode 3. Following the LOSP test, the unit j went into a three day maintenance outage. On April 15, the unit entered Mode 2, went critical, and entered Mode 1. On April 16, the unit was tied j to the grid. On April 18, the main turbine was removed from the grid and tripped to conduct secondary system repairs. On April 19, the main i turbine.was returned to service and tied to the grid. On April 22 a unit 1 turbine trip occurred due to a loss of stator cooling. This was followed i by a FWI on SG #3 Hi Hi level and subsequent AFW start. The unit then entered Mode 2. Later the same day, the unit reentered Mode 1. On j April 23, the main generator was tied to the grid. On April 24 with all of the 30% plateau. testing complete, the unit comunenced power ascension to 50% for 50% power plateau testing. On May 2,. the unit was increasing power to 75% for 75% power plateau testing when a reactor trip occurred i with the plant at 63% from a turbine trip following a test of the L electrical overspeed trip circuit. On May 3, the unit reentered Mode 2, achieved Mode 1, and was operating at 75% at the end of the inspection q period. f a. . Control Room Activities 6 \\ Control Room tours and observations were performed to verify that i facility operations were being safely conducted within regulatory requirements. 'These inspections consisted of one or more of the j following attributes as appropriate at the time of the inspection. 1 Proper Control Room staffing j Control Room access and operator behavior 1 Adherence to approved procedures for activities in progress L Adherence to technical specification limitin'g conditions for operation j Observance of instruments and recorder traces of safety-related i l and important-to-safety systems for abnormalities Review of annunciators alarmed and action in progress to correct i Control Board walkdowns i j Safety parameter display and the plant safety monitoring system operability status ) Discussions and interviews with the On-Shift Operations Supervisor, Shift Supervisor, Reactor Operators, and the Shift Technical Advisor (when stationed) to determine the plant status, plans, and to assess operator knowledge Review of the operator logs, unit logs and shift turnover sheets 7 i No violations or deviations were identified. b. Facility Activities Facility tours and observations were performed to assess the effectiveness of the' administrative controls established by direct observation of plant activities, interviews and discussions with j. licensee personnel, indeperdent verification of safety system status l - ~... -
3 j and LCOs, licensee meetings and facility records. During these inspections, the following objectives were achieveo: j (1) Safety System Status (71710) Confirmation of system l operability was obtained by verification that flowpath valve j alignment, control and power supply alignments, component conditions, and support systems for the accessible portions of i the ESF trains were proper. The inaccessible portions are confirmed as availability permits. An additional indepth j inspection of the Unit 1 SI system was performed to revicw the i i system lineup procedure with the plant drawings and as-built i~ configurations and to compare valve remote and local 1 indications. Walkdowns were expanded to include hangers and j i supports and electrical equipment interiors. The inspector observed that the lineup was not in accordance with license requirements in that the SI RCDT pump discharge to RWST l. isolation (1-1204-U4-002), SI RWST INL FI-0928A and F1-09286 isolation valves were found open. DCs were properly issued by 1 the 55 to correct these deficiencies. These valve misalignments did not render the SI system inoperable. Several valves were noted to have missing label' plates. Rooms A9 and A10 need a great deal of attention from a Health Physics and cleanliness i point of view. The licensee's program for maintaining control room drawings was reviewed. On April 28 and May 4,1989, the unit control rooms i and TSC drawings were inspected. This inspection included a detailed walkdown of the SI system (discussed above) and a i review of the following drawings to determine legibility, current revision verification and verification that procedure valve lineups were appropriate: i 1X4D8119 Rev 20 1X408130 Rev 22 1X408129 Rev 23 1X408133-1 Rev 23 1X408136 Rev 22 IX408161-1 Rev 22 l 1X408170-1 Rev 23 1X408120 Rev 14 1X408138-2 Rev 15 1X408136 Rev 22 1X408121 Rev 24 1X408131 Rev 19 1X40813g Rev 18 1X408138-1 Rev 16 1X408122 Rev 26 1X4D8132 Rev 14 1X408133-2 Rev 26 1X408135-1 Rev 21 1X408137 Rev 15 1X408161-2 Rev 22 1X408161-3 Rev 20 1X408170-2 Rev 22 1X408116-2 Rev 15 1X408117 Rev 18 1X408118 Rev 20 CX408173-557 Rev 1 CX408173-558 Rev 1 CX408173-553 Rev 1 The inspector determined that the procedures for controlling the distribution of drawings were satisfactory. The drawings adequately represent the plart's current configuration. Three drawings 1X408133-1 Rev 23,1X408122 Rev 24, and 1X408122 Rev. 26, (NSCW, SI, and RHR respectively) are too congested and [ therefore, difficult to read. It was also determined that most of the safety-related drawing ABNs were not legible. Three in particular. which are examples of the worst case are 1X408161 4 4 + r -- --~
1-4 i 1 Rev. 22,1X408121 Rev. 24, and IX408122 Rev. 26 (AFW, SI, and RHR respectively). Administrative procedure 00101-C. " Drawing Control," Step 3.4.4 requires that drawing legibility be ensured prior to distribution and engineering procedure 50009-C, "AS-Built Notices " Step 4.6.3, requires ABNs to be legible and ) reproducible. This constitutes a violation of administrative procedure 00101-C and engineering procedure 50009-C. 1 This violation is one example of violation 50-424/89-14-01 and } 50-425/89-15-01, " Failure To Implement Procedures 00101-C and 50009-C Resulting In TS 6.7.1.a Violation." ) (2) Plant Housekeeping Conditions - Storage of material and j components and cleanliness conditions of various areas 1 throughout the facility were observed to determine whether safety and/or fire hazards existed. i (3) Fire Protection - Fire protection activities, staffing, and equipment were observed to verify that fire brigade staffing was j appropriate and that fire alams, extinguishing equipment, actuating controls, fire fighting equipment, emergency i equipment, and fire barriers were operable. Radiation protection activities. (4) Radiation Protection staffing, and equirment were observed to verify proper program implementation. The inspection included review of the plant l program effectiveness. Radiation work permits and personnel compliance were reviewed during the daily plant tours. Radiation Control Areas were observed to verify proper identification and implementation. (5) Security - Security controls were obser.ad to verify that 1 security barriers were intact, guard forces were on duty, and access to the Protected Area was controlled in accordance with i i the facility security plan. Personnel were observed to verify proper display of badges and that personnel requiring escort were properly escorted. Personnel within Vital Areas were observed to ensure proper authorization for the area. Equipment operability or proper compensatory activities were verified on a periodic basis. (6) Surveillance (61726)(61700) - Survei.11ance tests were observed 4 to verify that approved procedures were being used. ' qualified personnel were conducting the tests, tests were adequate to 1' verify equipment operability, calibrated equipment was utilized, and TS requirements were followed. The inspectors observed i portions of the following surveillances and reviewed completed data against acceptance criteria: h
^ 1 ] i 5 i. Surveillance No. Title 14000-1 Rev. 17 Operations Shift And Daily Surveillance J Logs j 14000-2 Rev. 2 Operations Shift And Daily Surveillance 2 Logs 1 14220-1 Rev. 3 Main Turbine Valves Weekly Stroke Test 14228-2 Rev. 1 Operations Monthly Surveillance Logs 14230-1 Rev. 4 Weekly Train A & B Verification Offsite To Onsite Class 1E A.C. Distribution i System Circuit Breaker Alignmeni.;; While In Modes 1-4 14235-2 Rev. 1 Onsite Power Distribution Operability Verification j 14450-2 Rev. 1 RCS Pressure Isolation Valve Leakage Test 14495-1 Rev. 3 TDAFW System Flow Path Verification 1 14551-2 Rev. 1 CCW Flow Path Verification j 14808-2 Rev. 2 CCP And Check Valve Inservice Test i 14825-2 Rev. 1 RCS Quartsrly Inservice Valve Test j i-14905-1 Rev. 21 RCS Leakage Calculation ] Surveillance procedure 14825-2 was conducted during the night shift on March 22, 1989. The resident inspector conducted a review of the data on the following morning. It was noted that data sheet 1 (test section 5.3.1) requiring independent verification was not documented for PORY block valves 2-HV-8000A and B. 'The inspector promptly brought this to the attention of l the Operations Superintendent. 0505, and unit $5. The SS took the nece sary corrective action to complete these steps of the j procedure on. the following shift. It is apparent that an inadequata operator and supervisory review was conducted on the l l previous shift. (7) Maintenance Activities (62703) - The inspector observed maintenance activities to verify that correct equipment clearances were in effect; work requests and fire prevention work pemits, as required, were issued and being followed; quality control personnel were available for inspection activities as required; retesting and return of systems to I service was prompt and correct; and TS requirements were being followed. Maintenance Work Order backlog was reviewed. Maintenance was-observed and work packages were reviewed for the i following maintenance activities: MWO No. Work Description i 18901524 Replace NSCW Torque Switch Limiter Plate Due To Valve INV-1668A Not Stroking Properly 28902508 Stroke Steam Dump Valves 28902598 Main Feed Isolation Valve Repair j 4
6 l i l 28902715 Investigate / Rework / Replace Cards As Required To Restore MFP Slave Relay K-620 To Proper I Operation l 28903135 Raset Power Range Detector Current Per Start Up Test Procedure 2-65E-01 & 03 During this inspection, the inspectors noted that maintenance planning and execution was effectively conducted during short system outages (Unit 1) and plant outages (Unit 2). Most noteworthy was the elimination of a 10-day scheduled outage during the Unit 2 test program due to this proficiency. i, One example of one violation was identified (paragraph 2.b(1)). Unit 2 l 3. Startup Test Program Implementation / Verification (72302)(724008)(71715) 4 The inspector reviewed the present implementation of the Startup Test i Program. Inspected Test Program attributes including review of l administrative requirements, document control, documentation of major test events and deviations to procedures, operating practices, instrumentation l calibrations, and correction of problems revealed by testing. Periodic facility tours were made to observe Startup Test activities in progress. The inspector verified that procedural prerequisites and j initial conditions were met. Verification was performed by the inspector's review of records (valve lineup sheets, test equipment calibration status, system status checklists, or appropriate sign-offs listed in procedure were maintained current) or by direct observation (monitoring instrumentation indications, valve positions, equipment position. switches, or personnel actions). Discussions were held with responsible personnel, as they were available, to determine their knowledge of the Startup Test Program. Schedules for Startup Test Program completion and progress reports were routinely monitored. Specific l inspections conducted are listed below: I Initial Criticality and Low Power Test Sequence The initial criticality and low power test sequence directing the test activities as contained in procedure 2-600-04 was reviewed during testing. The following specific tests were partially witnessed: l fa) Step 6.2, Initial Criticality per Procedure 2-600-02 (b) Step 6.3, Detemination of Low Power Physics Testing Power Range (c) Step 6.4. Soron Endpoint. Isothermal Temperature Coefficient 1 Measurement (d) Step 6.4.11. Flux Map 2-6SE-02 (e) Step 6.11. Control Bank A Worth 4
. = _ -.-.. I l I 7 ) i Power Ascension Test Seouence (72509)(72582)(72583) 1 1 l' The power ascension test sequence directing the test activities as j contained in procedure 2-600-13 was reviewed during testing. The following specific tests were partially witnessed. i j (a) Step 6.1.1 Adjustment of Nuclear Instruments to 50% Trip Level (b) Step 6.1.7, Main Feedpump Operation per 12004-C l (c) Step 6.1.8, Perfonn 12004-C (d) Step 6.1.10, 2-6AB-01, Dynamic Auto Steam Dump Control j (e) Step 6.1.11, 2-6AE-01, Automatic Steam Generator Level Control 1 Position Indication Test (f) Step 6.1.20, 2-600-08, Remote Shutdown Test l (g) Step 6.1.23, 2-600-09, Loss of Offsite Power Test (h) Step 6.4.5, 2-6SE-02, Flux Map At 30% Power l (i) Step 6.4.7, 2-6SE-03, Operational Alignment Of The Nuclear Instruments (j) Step 6.5.3.1, 2-65C-02 Load Swing Test j l (k) Step 6.10.2, 2-6AE-01, Automatic Steam Generator Level Control (1) 2-600-06, MFW Dynamic Response Test On April 2, 1989, during performance of Step 6.1.8 which directed operation of the plant to proceed per procedure 12004-C, the inspector i i observed the unit perform the transfer from auxiliary feedwater to main feedwater for the #3 Steam Generator. Procedure 12004-C Step 4.1.4 l specifies that the transfer is to be completed as follows: l 4.1.4 TRANSFER Auxiliary Feedwater to Main Feedwater one Steam f Generator at a time by perfonning the following: j. l a. STA81LIZE the SG NR level between 45% and 55%, b. Slowly CLOSE the Auxiliary Feedwater Supply Valve and OPEN the BFRV while maintaining SG level in program i
- band, When the Auxiliary Feedwater Supply Valve is fully l
c. closed, stabilize SG 1evel and then PLACE the 8FRV in j automatic, d. Repeat valve transfer for remaining Steam Generators, l Prior to the start of the transfer, the inspector noted that the i Salance-of-Plant Operator discussed the transfer with the operator controlling Steam Generator level. The operators decided that the best way to make the transfer was for the 80P operator to close the Auxiliary Feedwater Supply Valve and the other operator would "pund." the 8FRV into automatic. The operators then connenced the transfer without discussion with the Shift Supervisor. The 80P operator did however involve the shift supervisor in the transfer by directing him to display narrow range and wide range computer trends of 83 Steam Generator on the ERF computer. l Upon closing the Auxiliary Feedwater Supply Valve, the SG Water level initially lowered. The second operator placed the 8FRV into Automatic as previously planned. The BFRV au:omatic control began to slowly open in
i j. 4 8 J order to restore steam generator levels. the controller and valve were slow and resulted in eventual overshoot ofT SG level to approximately 64t. The ERF computer displays were valuable in i monitoring the inventory of water in the steam generator during the transient. A second effect was observed in the #1 SG involving lowering I level. The 81 SG had been transferred to its 8FRV on the prior shift. i The 80P operator directed a plant equipment operator to fail the feedoump miniflow valve open. The inspector questioned the Operations Manager on i why the procedure had not been followed for the transfer and why the miniflow valve had to be failed open. The inspector also noted that the prior Step 4.1.3g had been signed off complete when in fact, only the el ] and #3 8FIVs were open. Procedure 12004-C, Step 4.1.3.g. states: 1 1 4.1.3.g OPEN the Bypass Feed Isolation Valve and VERIFY the ( Feedwater Isolation Valve is closed for each SG. J j The Operation Manager counseled the operators on not going in automatic control too soon. The failing of the miniflow valve was explained as a necessary evolution in that the flow from one feedpump feeding two steam generators is at the peint when the miniflow valve closes (500 gpm) which affects the output pressure of the feedpump and hence flow to the steam j By failing the miniflow valve open the feedpump performs in a generators. smoother manner. Later, the inspector learned that had all four BFIVs been open, that normal leakage. through the BFRVs would account for about 500 gpm and the miniflow valve would have closed prior to or during the swapover on the first steam generator. 4 i The fact that procedure 12004-C was not followed in Steps 4.1.3.g and 4.1.4 constitutes a violation of TS 6.1.7 requirements and is one example of violation 50-424/89-14-01 and 50-425/8g-15-01, " Failure to Implement i l Procedure 12004-C Steps 4.1.3.g and 4.1.4, For Performing Transfer From Auxiliary Feedwater To Main Feedwater." I l The inspector observed the subsequent transfer to the #4 Steam Generator which proceeded in an orderly fashion except for the use of the ERF j computer. When the Shift Supervisor called up the display, he obtained the el SG trend instead of the #4 SG. The transfer had already connenced and was essentially complete by the time the proper display was achieved. The following of procedure 12004-C, Step 4.1.4, by the operators resulted in a smooth transfer. 4 On April 3,1989, during the perfonnance of 2-6A8-01, " Dynamic Auto Steam i Dump Control." the plant experienced a SG level tres.sient when a test L signal specified by procedure was incorrect. Procedure 2-6AB-01, Step 6.3.3, directed that a test signal be inserted equivalent to the signal generated at a T-ref of 553"F by using Attachment 10.5. , 0.5 called for connection of a Ronan calibrator Model X85 (2.3 volt signal) (pins 26-and 27+). The reversal in polarity resulted in the steam dumps being connanded to full open when the controller was placed in the T-avg control mode per Procedure Step 6.3.5. At the time of the transient, six of the twelve dumps were isolated. The resultant swell in SG levels resulted in a feedwater isolation. Further details of tne i i I
4 k i I event 'is contained in LE? 50-425/89-15. This same error occurred on ' Unit 1 during the startup pr g sm; however, an LER did not result. Unit 2 procedure development did not incorporr,ce the Unit 1 procedure change. Failure' to establish an appropr'tte precedure is an example of a violation i of 10 CFR Part 50 Appendix B,, 'iterion V, and of TS 6.7.1.a. l ) This item is one of the examples of violation 50-424/89-14-01 and 50-425/89-15-01 " Failure To Establish An Adequate Procedure For The Testing Of Steam Dumps." (Refer a the discussion on LER 50-425/89-14 in 1 paragraph 4.t(3)(r) for additional information.) 4 The inspector questioned why the identical error on Unit 1 did not result I in a more severe transient. While no specific answers are known, I speculation was made regarding the number of steam dumps that 1 are inservice. On Unit 2 six of the twelve were inservice, and the test procedure called ' for verification that three valves be unisolated and ready for testing (PV-507A 8, and C). If Unit I had only three unisolated dumph then the transient would not have resulted in as severe l) a level swell. A review by the inspector on procedure 12004-C noted that no guidance or control regarding steam dumps existed. Inspection of Unit l 1 revealed that one steam dump was not inservice. 1 i The above events regarding establishment and adherence to procedures was i discussed with the General Manager on April 6,198g. The inspector addressed observations regarding: l i ftilures to follow procedure 12004-C. f ailure of the Shif t Supervisor to closely control the operator 4 l
- actions, failurv to have appropriate procedures in place for control of i
steam dumps and feedwater pump miniflow valves, l-excessive eating of food in the control room, and telephone distractions to the operators. l i In response to the above, the General Manager took action to address these j concerns by having by operations manager review and discuss these events with operators and supervisors. I i On April 7, 1989, a feedwater isolation occurred which illustrated another l failure of the cperators to implement procedure 12004-C. On April 6, with the unit in Mode 3 on long-cycle cleanup, the shift supervisor directed i that in order to support another surveillance that long-cycle cleanup be secured from the control room. Following the surveillance, the cleanup l was not restored. The following shift decided to replace the existing copy of 12004-C due to the number of items which had been signed off and however _ no longer represented the plant configuration. Since the action i to secure long-cycle cleanup had been accomplished in the control room. the shift supervisor assumed that all of Step 4.1.3 directing the stopping 4 l 'of feedwater recirculation in long-cycle cleanup were not applicable. This error resulted in the failure of the plant to close six manual isolation valves _ and produced a situation wherein all four steam generators were cross connected. On April 7, with reactor power at t
10 approximately 7% operators noticed that the #1 SG 8FRV was at 60% demand. 'j v2 and #3 SGs were at 30% demand, and e4 SG was at 05 demand. Even though two steam generators gave the indication that only one BFRV was maintaining level, the operators notified I&C to investigate the 2 indication problem. Since SGs 1 and 4 are on the same side of i containment, the physical piping layout rasults in these two SGs being i related. While resolving the problem, the operators decided to stroke the
- 2 MFIV as part of a maintenance functional test.
As soon as the MFIV was j j opened, flow from the other SGs was diverted to the #2 SG until a feedwater isolation occurred due to Hi. Hi #2 SG water level. The root I cause is related to the first shift supervisor failing to implement j procedure 12004-C. Step 4.1.3, in securing from long-cycle recirculation. 4 l This item is an additional example of violation 50-424/89-14-01 and j i 50-425/89-15-01, " Failure To implement Procedure 12004-C To Secure From i l Long-Cycle Recirculation." (Refer to the discussion of LER 50-425/89-15 in paragraph 4.b(3)(s) for additional infomation.) The proper control of the steam dumps was addressed by the inspector as a j concern in that the basis for the P-9 reactor protection interlock assumes' that all dumps are available with nomal pressurizer pressure control. l TS 2.2.1, Table 2.2-1, item 18.d. specifies a trip setpoint of 50% where i 3 the reactor trip on turbine trip can be blocked. The inspector asked for a review by the licensee to detemine if the actual setpoint should be l adjusted downward when dumps were not available. Followup of this item e [ will be tracked as IFI 50-424/89-14-02 and 50-425/89-15-02, " Review j Licensee Evaluation Regarding Adjustment Of The P-9 Setpcint When Steam Dumps Are Removed From Service." The above sections represent a weakness in the area of operations to implement and adhere to the basic'" Power Operation" procedure 12004-C. It f i becomes apparent when combined with other operations procedure /imple-i mentation as documented in LERs 50-424/89-07, 50-425/89-02, 50 425/89-03, 50-425/89-04, 50-425/89-06, 50-425/89-08, 50-425/89-11, and 50-425/89-16 l (see paragraph 4) that additional management attention and oversight are i j needed. Response by licensee management has been noted; however, effectiveness of this effort will require more time to evaluate. The startup test program has been relatively successful with only one noted failure discussed above regarding the steam dump testing. More noteworthy was the proficient and efficient conduct of the Remote Shutdown Test and the Loss of Offsite Power Test. Key in - the successful accomplishment was the decision by management to perform the test only during the day shift at specific times. This decision affected the i appropriate personnel the ability to be well rested and prepared for the testing. i Three examples of one violation and one inspection followup item were identified. I
-- : = x: 11 4. Review of Licensee Reports (90712)(90713)(92700) a. In-Office Review of Periodic and Special Reports This inspection consisted of reviewing the below listed reports to 1 determine whether the information reported by the licensee was i technically adequate and consistent with the inspector knowledge of j' the material contained within the report. Selected material within the report was questioned randomly to verify accuracy and to provide j l a reasonable assurance that other NRC personnel have an appropriate document for their activities. '4 l Monthly Operating Report - The inspector reviewed the Unit 1 and 2 monthly operating reports dated March 15, 1989. This review included 1 j the data revision for an earlier Unit i report. The inspector had no coments. j No violations or deviations'were identified. b. Licensee Event Reports and Deficiency Cards e i Licensee Event Reports and Deficiency Cards were reviewed for l potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate. Events which were reported f j pursuant to 10 CFR 50.72, were reviewed as they occurred to determine if the technical specifications and other regulatory requirements i were satisfied. In-office review of LERs may result in further followup to verify that the stated corrective actions have been l completed or to identify violations in addition to those described in the LER. Each LER is reviewed for enforcement action in accordance l with 10 CFR Part 2, Appendix C, and if the violation is not being i cited, the criteria specified in Section V.6 of the Enforcement l Policy was satisfied. Review of DCs was perfomed to maintain a l realtime status of deficiencies, determine regulatory compliance, follow the licensee corrective actions, and assist as a basis for clnsure of the LER when reviewed. Due to the numerous DCs processed only those DCs which result in enforcement action or further inspector followup with the licensee at the end of the inspection are listed below. The LERs and DCs denoted with an asterisk indicates j that reactive inspection occurred at the time of the event prior to receipt of the written report. (1) Deficiency Card Review (a) DC 1-89-831 " Inadvertent Addition Of Radioactive Gas To Decay Tank Number 10." 'On April 18, 1989, the licensee discovered that radioactive gas was apparently added to waste gas decay tank number 10 without the lab being notified for determining the quantity of gas contained in the tank. This deficiency will te followed up on when submitted as an LER. i i ) r
)' 12 r ~ l (b) *DC 2-89-585, " Unit 2 Turbine Trip Following Standby Stator Cooling Pump Trip." j On April 22, 1989, a turbine trip occurred as a result of a loss of stator cooling during a routine swapping of stator j cooling pumps. When the standby pump was started, both pumps tripped, causing the turbine to trip. While attempting to stabilize the plant, a feedwater isolation j occurred due to Hi-Hi SG 1evel on SG #3, leading to an AFW l actuation when the running MFP tripped. The reactor was stabilized at 2% with the SG being fed from AFW. This deficiency will be followed up when submitted as an LER. i 1 (c) W 2-89-1027 " Reactor Trip From 60% power On A Turbine To r. " 4 May 2, 1989, the unit received a reactor trip from 60% weer on a turbine trip. AFW actuated on Lo to SG 1evel following the trip. All systems functioned as required. The turbine trip occurred while Engineering and a GE Vendor representative were investigating a test malfunction alarm which was received during the weekly turbine trip device operability test. The cause of the turbine trip is still under investigation. This deficiency will be followed up when submitted as an LER. (2) The following LERs were reviewed and are ready for closure pending verification that the licensee's stated corrective actions have been completed. L l' (a) 50-424/89-06, Rev. O, " Inadequate Functional Test Leads To Improper Termination Of Limiting Condition For Operation." j S l On January 30, 1989, the Gaseous Waste Processing System's j Outlet Analyzer, 1 ARC-1119, failed to pass the surveillance requirements of Technical Specification 4.3.3.10. The TS ] required grab samples to be taken and analyzed at least once per 24 hours. A micro fuel cell in the analyzer was j replaced and tested on February 7,1989. On February 23, 1989, a' review of the work order discovered that the i j equipment was placed in service, even though a complete surveillance test of the analyzer had not been performed to verify that the surveillance requirements were met. The surveillance test was then performed satisfactorily. This event was caused by personnel error. Procedural inadequacies contributed to this event. The appropriate procedure was revised. The appropriate personnel have been counseled. Proper checks now exist to ensure all required testing is performed prior to exiting a LCO. This item i represents a violation of NRC requirements which meets the L 4 e.
a 13 i t criteria for non-citation. In order to track this item,. the following licensee-identified item is established. NCY 50-424/89-14-03, " Failure To Perform Raouired Testing Per Surveillance Requirements Results in TS 4.3.3.10 Violations - LER 50-424/89-06." 1 I j (b) 50-424/89-07, Rev. O, " Failure To Take Required Temperatures Results In Inadequately Performed i Surveillance." l On February 16, 1989, while performing Procedure 14001-1, " Shift Area Temperature Log," the plant operator noted that there was no entry for Fuel Handling Suilding Room 8008 for the two previous shifts. The Shift Supervisor was notified of the missed readings, which are required per Technical Specification 3.7.10. The current temperature was taken for Room 8008 (76*F), and as it was well within the normal maximum technical specification limit (104'F), no compensatory action was required. The cause of this event was personnel error. Two plant operators failed to take the required reading and their respective shift supervisors j failed to note the missing temperatures when the data sheets were reviewed. Corrective actipns included counseling of the operators and shift supervisors on the importance of ensuring that all required technical i specification surveillance temperatures are obtained and data sheets thoroughly reviewed. This item represents a violation of NRC requirements which meets the criteria for non-citation. In order to track this item, the following licensee-identified item is established. i j NCV 50-424/89-14-04, " Failure To Take Required Temperatures Results In Inadequately Performed Surveillance Resulting In J i A TS Violation - LER 50-424/89-07." i ) (c) 50-424/89-08 Rev. O, " Inadequate Review Of Drawing Change ~ Results In Use Of Improper Breakers." 1 On February 23, 1989, it was discovered that 125V DC breakers for motor-operated valves in the Turbine Driven Auxiliary Feedwater pump system were not the proper size. 3 The breakers, as installed and as shown on design drawings, were 15 amp thermal magnetic but should have been j sized as 30 amp thermal magnetic per the design criteria. Therefore, the plant has operated in a condition prohibited .by Technical Specifications. Technical Specifica-tion 3.7.1.2 requires at least three independent steam generator auxiliary feedwater pumps and flowpaths to be operable. The undersized breakers were discovered as a result of an investigation of the same problem in Unit 2. I
14 J' LCO 1-89-121 was entered. The breakers were replaced. 4 j successfully tested, and the LCO was exited. The cause of this event'was due to inadequate review by the responsible t engineer when a drawing change notice corrected the MOV 3 horsepower rating form 0.66 hp to 1.0 hp. Corrective actions included a review of all 125V DC MOV breaker protection. This review indicated this incident to be an isolated case. This item represents a violation of NRC requirements which meets the criteria for non-citation. 1.n j order to track this item, the following licensee-identified i item is established. NCY 50-424/89-14-05 " Failure To Conduct An Adequate Engineering Review Of The AFW Electrical System Which Led 2 To AFW Inoperability Resulting in a TS 3.7.1.2 Violation - LER 50-424/89-08." 1 l (d) 50-424/89-10, Rev. O, " Valved Out Radiation Monitor Leads 4 To Unmonitored Liquid Waste Release." l On March 14, 1989, a plant operator was preparing to i perform a liquid waste release per procedure 13216-1, i: " Liquid Waste Release." The operator verified that radiation. monitor 1-RE-0018 was registering normal i i background levels and that isolation release valve 1-RE-0018 would close on a high radiation signal. The release began and the operator checked the signal from i i 1-RE-0018 and found it wai, not registering above background i levels. A brief search found that the inlet valve to 1-RE-0018 was closed. This valve, 1-1901-X4-144, was l opened; 1-RE-0018 registered the proper activity level; and the liquid waste release continued. The release was j completed and the closure of the inlet valve resulted in liquid waste being released unmonitored which is a i condition prohibited by Technical Specification 3.3.3.9. The operator omitted the performance of a pre-release line l flush which would have ensured that the inlet valve was opened. Corrective actions included counseling the operator and changing procedure 13216-1 to require independent verification of the inlet valve being open. This item represents a violation of NRC requirements which meets the criteria for non-citation. In order to track j this ites, the following licensee-identified item is established. NCV 50-424/89-14-06, "Failurs To Follow Procedures While Conducting A Liquid Waste Release Resulting In A TS 3.3.3.9 4 Violation - LER 50-424/89-10." 1 l 3
15 l l (e) 50-425/89-05, Rev. 0, " Inadequate Review Of A Modification [ Results In A Technical Specification Violation." l On March 17, 1989, while investigating a problem with the t 4 Automatic Surveillance Technical system, field vol tage measurements were taken that revealed an electrical short on valve 2HV-19051, the Reactor Coolant Pump *1 thermal barrier isolation valve. The valve was required to be operable upon entry into Mode 4, which had occurred on March 4 i A Surveillance had been performed on February a, 1989, to prove operability of 2HV-19051; however, a change i to the ASTEC system wiring on February 10 resulted in valve i 2HV-19051 being inoperable. The cause of this event was i the issuance of an incorrect As-Built Notice. Corrective i actions included counseling the appropriate engineering personne! involved, training for all engineering personnel j recently transferred from the Unit 2 test organization on use of the A8N, and issuing a second A8N to restore the i system to its original configuration. This item represents l a violation of NRC requirements which meets the criteria ' i for non-citation. In order to track this item, the l following licensee-identified item is established. i NCY 50-425/89-15 04, " Failure To Meet A Mode Change l Prerequisite Resulting In A TS 3.7.12 Violation Requiricq Valve 2HV-19051 To Be Operable Prior To Entering Mode 4 - i LER 50-425/89-05." (f) *50-425/89-06, Rev. O, " Operation of Incorrect Handswitch Results In Safety Injection." { On March 18, 1989, while warning main steam lines as part of procedure 12002-2, " Unit Heatup To Normal Operating Temperature And Pressure," automatic Engineered Safety Features actuation. A step of the procedure called for i handswitches HS 40047/48 to be operated to reset' the main i steam isolation signal. However, handswitches HS 40068/69 were operated. These switches reset the low steamline i pressure safety injection and steamline isolation logic, removing the blocking signal. Since the main steam line pressure was below the safety injection setpoint pressure, i the SI ' occurred. Appropriate ECCS pumps and valves ) actuated resulting in approximately 2900 gallons being injected into the Reactor Coolant System. The SI was manually reset and injection into the RCS was terminated. The cause of this event was personnel error. The operator i failed to ensure that the proper switch was being operated. Corrective actions will include counseling the operator on the importance of verifying that the proper device is being operated, changing the color of SI handswitches, adding cautions-to the handswitches, and incorporating details of 4 8
16 4!* 4. f' i this event into training. This ites was formally i discussed following the Enforcement Conference on March 22, 4 1989. This item represents a violation of NRC requirements 1 which meets the criteria for non-citation. In order to l track this item, the following licensee-identified item is j established. NCV 50-425/89-15-05, " Failure To Follow Procedures Resulting In Inadvertent SI Actuation - LER 50-425/89-06." (g)' 50-425/89-07 Rev. O, " Lockup Of A Computer Comunications 4 Device Results In Containment Ventilation Isolation." On March 19, 1989, while restoring the Plant Effluent 1 Radiation Monitoring System to service the plant i experienced an automatic Engineered Safety Features i j actuation which resulted in a Containment Ventilation ! solation. Appropriate valves and dampers actuated to isolate containment ventilation. Control room operators 1 verified that no abnormal radiological conditions existed j using 2RE-0002/0003. The monitor that actuated the CVI, { 2RE-2565, was placed in bypass. The CVI was reset and equipment that actuated was returned to normal operating position. Due to an earlier SI, power was lost to most of the PERMS system. On restoration of power, the computer i parameter files are initialized with a -9.99E-20 value, The computer replaces this value with parameters received i from each monitor. Due to a communication failure of a l multiplexer, communication with the monitors was lost and no value was rece*ved for 2RE-2565. When the mutiplexer was reset the computer detected the original power failure for 2RE-2565. On a power failure, the computer gives the monitor the current parameter on file and assigned the monitor -9.99E-20 value. This resulted in a high alarm, i i causing the CVI actuation. Corrective action is a procedure revision to require 2RE-2565 to be placed in bypass when the computer is initialized to receive parameters. i (h) 50-425/89-09, Rev. O, " Procedure Misinterpretation Leads To Late Surveillance Testing." 4 On March 20, 1989, a diesel fuel oil shipment arrived onsite for offloading into the ' Diesel Fuel 011 Storage 4 tanks. A technician obtained and analyzed a sample. The technician and his foreman interpreted a note in the analyses scheduling procedure to mean that the neutralization number and mercaptan were not required to be performed. In fact, only the mercaptan was exempt from the i analysis and neutralization number was required to be performed. After the analysis found the: other fuel properties to be satisfactory, the shipment was unloaded
I l 17 i l' i into the DF05 tanks. Meanwhile, a second diesel fuel oil i i shipment arrived onsite, a sample was obtained and analyzed as before and unloading into the DF05 tanks began. A i j laboratory supervisor reviewed the data sheets and question j the omission of the neutralization number from the data j sheets. After the requirement was clarified, the i technician obtained the original samples from each shipment i and determined that the neutralization numoer of each was j within technical specification requirements. The cause of this event was the misleading nature.of the procedure note. ~ The procedure note was rewritten and clarified. This item i represents a violation of NRC requirements which meets the criteria for non-citation. In order to track this item, j' the following licensee-identified item is established. I. NCY 50-425/89-15-06, " Failure To Establish An Adequate j Sampling Procedure For Diesel Fuel Oil Per TS 6.7.1.a - LER 50-425/89-09." 4 l (i) 50-425/89-10. Rev. 0, " Radioactive Discharge Without Permit j Leads To Technical Specification Violation." 4 Technical Specification 3/4.11.1 requires that releases of l radioactive materials to unrestricted areas be sampled and analyzed for appropriate 41pha, beta, and gasuna emitters. J On March 8,1989, the contents of the Unit 2 Turbine building drain tank, 2-2412-T4-002, were sampled for gamma emitters to determine if a release pemit was required. On i March 9, a plant operator released the tank contents to the Unit 2 Waste Water Retention Basin without a pemit. On i' March 14. during a review of releases, it was found that no permit had been issued for the March 9, release. The pemit ensures that required samples have been taken, j analyzed and are within allowable limits for releases. Procedure 13211-2, " Turbine Building Drain System," i required that sample analysis be used to determine how i drain tank contents are to be processed but did not specify ?- that a release pemit may be required. The cause of this 1 event was that the operator did not obtain a radioactive release permit prior to releasing. Procedure 13211-2 has been revised to provhie specific instructions that a i radioactive release permit may be required for releasing j the contents of a turbine building drain tank. Also, at shift briefings, operators were reminded that waste permits j are required prior to release of radioactively contaminated l i tank contents. This item represents a violation of NRC requirements which meets the criteria for non-citation. In order to track this item, the following licensee-identified i item is established. i NCY 50-425/29-15-07, " Failure To obtain A Radioactive Release Pemit Prior To Releasing Radioactive Materials Tc i
18 Unrestricted Areas Resulting in A T5 3/a.11.1 Violation - ~ LER 50-425/89-10." (j) 50-425/89-12, Rev. O " Operating Incorrect Switch Results In Inoperable Monitor Requiring Entry Into T5 3.0.3." On March 30, 1989, while perfoming maintenance on 2RE-2562A, an Instrument and Controls Technical inadvertently placed 2RE-2562A and 2RE-2562C in purge instead of activating the paper drive' on 2RE-2562A. This caused 2RE-2562C to be inoperable. Later the same day, a chemistry foreman discovered 2RE-2562C to be inoperable and notified the control room. An entry into TS 3.0.3 was made due to an existing limiting condition for operation for the Reactor Coolant System Leakage Detection System and 2RE-2562C being inoperable. With 2RE-2562C inoperable the LCO for Technical Specification 3.4.6.1 could not be met. 2RE-2562C was restored to service and TS 3.0.3 exited. The cause of this event was personnel error. The IEC technician failed to pay attention to detail when activating plant equipment. The purge switch was activated instead of the paper drive. Corrective actions included counseling the individual and issuing a memo to all I&C personnel concerning attention to detail when performing maintenance / trouble shooting on plant equipment. This item represents a violation of NRC requirements which meets the criteria for non-citation. In order to track this item, the following licensee-identified item is established. 8 NCV 50-425/89-15-08, " Failure To Follow Procedures While Perfoming Maintenance On 2RE-2562A Resulting In The Plant l Operating In A Condition Prohibited 8y TS Thus Requiring Entry Into TS 3.0.3 - LER 50-425/89-12." (k) 50-425/89-13 Rev. O, " Flood Barrier Removal Leads To i-Auri11ary Feedwater Inoperability." l Technical Specification 3.7.1.2 requires that three i independent steam generator AFW pumps and associated flow paths be operable in Modes 1, 2, and 3. On March 30, 1989, L plant personnel were conducting a routine walkdown. They found a flood protection barrier removed from the wall I between the AFW discharge piping room (room 105) and the Turbine Driven AFW pump room (room 106). The barrier was replaced and the TS action statement was exited. Ine cause of this event is an apparent personnel error by removing the barrier without the proper review and approval. Work had been performed on a check valve in room 105. When a functional test was performed on March 23, the existence of a flood barrier and precautions to be observed were cet addressed by those requesting the test or by those f 6
19 impleinenting the work order. A sign will be installed near ~ the flood barrier and information will be added to the equipment file advising of the flood barrier's existence. This item represents a violation of NRC requirements which meets the criteria for non-citation. In order to track this item, the following licensee-identified item is established. NCV 50-425/89-15-09, " Failure To Maintain The Auxiliary - Feedwater System Operable Resulting In A Condition Prohibited By TS 3.7.1.2. - 1.ER 50-425/89-13." (1) *50-425/89-16, Rev. O, " Unplanned Auxiliary Feedwater Actuation On Recovery From Remote Shutdown Test." On April 11, 1989, while recovering from a Remote Shutdown Test, an automatic Engineered Safety Features actuation (auto start signal to motor driven Auxiliary Feedwater pumps) occurred. During the Remote Shutdown test, both Main Feedwater Pumps were manually tripped and AFW was in service. With both MFPs tripped an AFW actuation signal was generated; however, while control was at the Remote Shutdown Panel, the signal is interrupted. When control was returned to the control room, the signal was reinstated. As the AFW pumps were already in operation - the AFW actuation signal caused the discharge valves of the Train A to stroke full open. Control room operators imediately throttled AFW flow to prevent overfilling of the steam generators. MFP "A" was reset to allow return of the remaining trains to the control room. All AFW systems were restored to readiness. The cause of this event was a situation that was not anticipated by the procedure. Procedure 18038-2, " Operation From Remote Shutdown Panels," i 3 will be revised to caution operators of a possible actuation of transfer of control to the control room. I (3) The following 1.ERs were reviewed and closed. (a) 50-424/87-81, Rev. O, " Excessive Valve Weight Could Have Prevented Fulfillment Of Safety System Function." On May 5, 1987, two valves supplied by Anchor Darling valve on the sludge mixing recirculation line of the Refueiing Water Storage Tank were found to weigh significantly more ~ than shown on the A/DV drawings. The initial analysis from an employee of Bechtel Power Corporation indicated that the valves weighed in excess of the seismic design capacity of their associated pipe supports and that if a line failure had occurred in the non-safety related portion of the sludge mixing line during a seismic event, the valves could have been closed and allowed the RWST water volume to be i
i, 20 i i { available for plant shutdown. On March 6, 1989, the Project Field Engineering-office advised plant personnel that there was an error in the application of potential failure point and that the potential failure point was 1 actually between the. valves and the RWST. Thus, if a 3 seismic event caused a line failure to occur, the broken { line could have potentially drained the RWST to a level below minimum requirements for plant shutdown. The cause l of this condition was determined to be the failure of A/DV to advise Bechtel of a change in valve weights from those originally shown on the valve drawings and an error by a Bechtel Power employee in the initial review of this j condition. Corrective actions included adding an additional pipe support and reviewing other safety related i valves for weight discrogancies. The inspector has no j further questions. (b) *50-424/88-16, Rev. 0, " Water Leakage Into Control i Room / Potential Exists For A Sefety System Failure." On June 3, 1988, smoke from an electric duct heater actuated smoke detection alarms. Although sprinkler heads i did not actuate, water from the proaction valve leakoff lines ran into the upper cable spreading room and seeped into the control room from the ceiling. Water entered some process panels and led to spurious equipment actuations in 4 the Reactor Coolant System which were promptly addressed and-corrected by control room personnel. On June 5, 1988, it was concluded that a condition existed which alone could l i have prevented the fulfillment of the safety function of a i system needed to mitigate the consequences of an accident. l The cause of this event is an inadequate design of the control room ceiling penetrations which are supposed to be i watertight. Corrective actions were verified complete. l This item resulted in a NRC violation 50-424/88-24-01. j (c) 50-424/88-19 Rev. O, "!nadequate Installation Leads To Containment Ventilation isolations." On June 10, 1988, a CVI occurred due to an apparent power supply failure in radiation monitor 1RE-2565C. The appropriate dampers and valves actuated as designed. Control room personnel verified that no abnormal condition existed. 1RE-2565C was bypassed and the CV! signal was . reset. Later, the same day, another CVI occurred, when plant personnel removed 1RE-2565C from bypass in order to reenter monitor setpoints. Again the proper dampers and 4 ' valves' actuated and control rwe personnel verified that no abnormal radiation condition existed. 1RE-2565C was again placed in bypass and the CVI signal was reset. An l investigation deconstrated that the cause of the CVI was an 4 = v.
b 21 1 i' i b inadequate installation which left a flow transmitter shield. wire exposed that electrically grounded, simulating l a loss of power. Corrective action included insulating the shield wire and new default values were installed. l (d) 50-424/88-20, Rev. 1 " Inadequate Breaker Leads To Condition Prohibited By Technical Specification." 1 I, i On June 29 1988, it was determined that ten containment i penetrations may not have adequate redundant overload j protection, as required by Regulatory Guide 1.63. The redundant protection was not provided because in each of j the ten penetration circuits one of the two breakers used was magnetic-only, which did not provide adequate overload j protection for the penetration. The other breaker provided was a thermal-magnetic and provided adequate overload i protection for the penetration. Since the magnetic-only breakers did not provide the redundant overload protection, the requirements of Technical Specification 3.8.4.1 for i i operability was not satisfied. When it was determined that l redundant overload protection may not have been adequate over the entire range, the identified containment penetrations were declared inoperable and the requirements i i of Technical Specification 3.8.4.1 were satisfied while the l breakers were being replaced. Prior to the operation of Vogtle Unit 1, a construction test was performed for each l breaker to verify its tripping function. All tests were performed satisfactorily and the breakers declared operable. The inspector has reviewed documentation which indicated that the. corrective action was complete. The l magnetic-only breakers were replaced with themal-magnetic i. breakers. f l (e) *50-424/88-22, Rev.1. " Failed Potential Transformer t.eads To Turbine / Reactor Trip." t [ On July 14, 1988, a generator / turbine / reactor trip occurred as a result of an overexcitation condition on the generator field. Control rods inserted. The Main Feedwater system i 1solated and the Auxiliary Feedwater system actuated. Control room operators responded properly to assist in i i plant stabilization. An investigation revealed that the failure of a potential transfomer caused the primary fuse to blow. The resultant transient caused the GENERREX L voltage regulator to malfunction, increasing generator voltage to the volts / Hertz relay setpoint, which subsequently initiated a generator / turbine / reactor trip. Corrective action includes replacing all primary PT fuses, PT 2A, and_ the malfunctioning circuit boards in the GENERREX systeri. The GENERREX system's operational history has been evaluated and additional adjustments are not i l..
i. I 22 i '. i considered necessary at this time. Engineering review of j design enhancements to the present GENERREX system will continue to be performed as part of the Trip Reduction Program. The failed PT was analyzed and a winding failure was identified. Improved tes methods to detect this type of PT failure were evaluated. riowever, a more appropriate { test method has not been identified. This LER was closed l i in report 50-424/88-37. i (f) 50-424/88-23, Rev. O, " Inadequate Design Leads To Condition j Prohibited By Technical Specification." On July 29, 1988 LER 50 424/88-20 was issued, identifying l that several electrical penetrations may not have been provided with adequate redundant overload protection. As a i j result of the interpretation for reportability of that i event, two previously identified deficiencies have been 1 re-evaluated for reportability. As a result of the i re-evaluation, an event that was discovered on August 14 j 1987, was determined to be reportable on July 28, 1988. l The other event was discovered on July 7,1987, and determined to be reportable on August 11, 1988. It was determined that for each event, redundant overload 1 l protection may not have been adequate for the entire range l of protection as required by Regulatory Guide 1.63. i Technical Specification 3.8.4.1 required that electrical penetration overload protection may not have been provided for several penetrations, Unit 1 may have been operating in a condition prohibited by TS until the event was discovered. For each event the limiting condition for j operation action statement for TS 3.8.4.1 was implemented i on the event discovery dates of July 7, 1987, and i August 14, 1987. The event on August 14, 1987, involved electrical penetrations No.12 and No. 69, concerning the
- 12 and #14 size conductors.
The other event on July 7, 1987 involved penetration No. 03, 14, 34, 41, 60, and 61, l concerning #10 size conductors. The inadequate overload i protection was discovered during a broadness review for Unit 2 by the designer, Bechtel Power Corporation. The 4 j inspector verified the work complete by reviewing the closed MW0s. (g) 50-424/88-26, Rev. O, "Use Of Improper Tools Leads To l Containment Ventilation Isolation." i On September 7, 1988, an electrician was in the process of installing shorting bars into fuse holders following the g completion of an electrical switch replacement. The electrician unintentionally created a short between two 120 volts AC circuits. Various alarms and indicators actuated, including those 'cr a CVI. The appropriate CV! valves and L
h i. 23 5 ~ 1 l dampers actuated. Control room personnel verified that no abnormal radiation condition existed by observing redundant 5 monitors. The control room personnel and the electrician immediately confirmed that the electrical short had initiated the CVI. The cause of this event was the use of l an improper tool by the electrician. Fuse pullers provided F to the electrician would not fit between the inserted shorting bars, so he used needle-nose pliers to perform the insertions. These pliers made the electrical short by i simultaneously contacting two shorting bars following one shorting bar's insertion. Appropriate personnel were j advised to avoid the use of needle-nose pliers or makeshift e tools for installation of fuses or shorting bars. The proper size fuse-pullers were made available. i (h) 50-424/88-30 Rev. O, " Surveillance Missed Due To j Inoperable Rod Position Deviation Monitor." On October 27, 1988, while preparing a licensing document change, it was discovered that a plant computer design feature for monitoring deviations between Digital Rod Position Indication System and Demand Position Indication i. System had not been implemented within the plant computer software as intended. The absence of this feature means the Rod Position Deviation Monitor is operable for this function and that surveillance 4.1.3.2 has not been met, l when required, since issuance of the Unit I license. The t l surveillance required operability determination of the digital rod position indicators. For this determination, the DPIS must be verified to be with + or - 12 steps of the DRPIS every 12 hours, except when the RPDM is inoperable, l i then the requirement is at least once per 4 hours. As the plant staff were unaware of the software omission, they did l not take the required action to manually make the comparisons every 4 hours as required. The cause of this l. event was the omission of appropriate rod su'pervision programs in the original vendor supplied computer sof tware specifications. Corrective actions include increased frequency of the surveillance and an evaluation to detemine if either changes to the computer software are i feasible or changes to licensing documents are required. The inspector reviewed documentatics which indicated that the corrective action was complete. This item represents a l violation of NRC requirements which meets the criteria for non-citation. In order to track this item, the following licensee-identified item is established. L l NCV-50-424/89-14-07, " Failure To Conduct Surveillance L Resulting in A Violation Of TS 4.1.3.2 - LER 50-424/88-30."
i 24 4 i* (1) *50-424/88-41, Rev. O and 1 " Containment Purge Supply i Isolation Valve Inoperable Due To Failure To Fully Close." i On December 13, 1988, while performing a revised Type C Local Leak Rate Test for surveillance of the containment j j purge supply isolation valves in Penetration 83, it was discovered that the 24-inch containment purge supply isolation valve 1-HV-2626A was not fully seated. This j condition is prohibited by Technical Specification 3.6.1.7 which requires that this valve be closed and sealed closed. LCO 1-88-922 was entered for 1-HV-2626A failing the leak i rate test. This event occurred because the valve did not fully close, even though the limit switch indicated that the valve was closed. Corrective actions included issuing LCO 1-88-922, innediate manual seating of the valve and successfully repeating the LLRT, and establishing conservative administrative controls to ensure that each 24-inch purge isolation valve, if cycled, will be either j manually seated or have an LLRT perfonned, as,sppropriate. l l Procedures 13125-1, Rev. 8, and 13125-2, Rev. 2, were verified by the inspector to have been revised. [ (j) *50-424/89-05, Rev. O, " Trip Of Main Feed Pump On High Vibration Resulting In Manual Reactor Shutdown." l On February 10, 1989, Control Room operators received Main i Feedwater Pump Turbine "A" high vibration alarms. A check of the vibration monitor system showed a vibration of only i 1.2 mils. (The vibration system alarms at 3 mils and trips at 5 mils). Shortly thereafter, MFP "A" tripped. l Steam /feedwater flow mismatch alams were received on all four steam generators. Turbine load was manually reduced j to approximately 700 MWe and control rods placed in Auto to follow load. Steam dump valve controllers were manually operated to attempt to match steam / feed flow. SG v4 i reached 20% level and the Shift Supervisor directed the l reactor to be manually tripped. Feedwater isolation and i start of Auxiliary Feedwater pumps occurred as expected. However, the Turbine Driven AFW pump tripped on overspeed after starting. The cause of the MFP O gh vibration trip was not positively identified. The cause of the TDAFW pump overspeed trip, although not positively identified, n.ay have been caused by particulate contamination of the lube oil, which serves as the control system hydraulic fluid. Corrective actions included temporarily installing vibration instrumentation to collect MFP vibration data. Additional surveillances were also perfomed on the TDAFW pump to ensure operability. I l l
j' I' 25 4 d (k) 50-424/89-09. Rev. O. " False Radiation Monitor Signal 1 Caused Containment Ventilation Isolation And TS 3.0.3 Entry." i On March 13, 1989, radiation monitor 1RE-0003 spiked high causing a Containment Ventilation Isolation. Appropriate valves and dampers actuated from the CVI signal to isolate 1 containment ventilation. LCO 1-89-155 was entered for 4 1RE-0003. Radiation monitor 1RE-0002 was out of service for a surveillance and'1RE-2565 was not operable because of reliability concerns. Technical Specification 3.3.2, 1 Table 3.3-2, requires a minimum of two of the three channel be operable, but there is a provision for operation with only one channel in operation. An entry was made into T5 3 3.0.3 since all three channels were inoperable. Control room operators verified that no abnormal radiological i 4 i conditions existed using 1RE-0002, which was functional but j not operable. Later that same day, 1RE-0002 was declared operable, the high alarm on 1RE-0003 was cleared, the monitor placed in bypass, and the CVI signal was reset. The cause of this event was the failure of the detector tube. The tube was replaced; however, the replacement tube i did not function properly and required replacement due to degradation of the voltage plateau. The replacement tube l was monitored and the monitor was declared operable. f (1) 50-425/89-01, Rev. O, " Spurious Signal Resulting From l Circuit Board Causes Control Room Isolation." On February 14, 1989, a Control Room Isolation occurred due to a spurious signal from radiation monitor channel 2RE-12116. Prior to this actuation, the Safety Parameters Display Console had received intermittent trouble light indications from the channel. Control room operators verified no high radiation condition existed. The monitor's output was blocked, a LC0 was entered, the CRI l-signal was reset, and normal ventilation was established. I Radiation monitor channel 2RE-12116 was returned to service i and the LCO exited on February 18. The event was caused by a random failure detected on the Central Processing Unit board in the Digital Processing Module. This random event l caused the internal timer to lock up and initiate a system reset signal. During a system reset, the monitor's fail safe function initiates a high alarm signal which caused the CRI actuation. Corrective actions included initiation of a LCO for the monitor, replacement of the defective circuit board, observation of the monitor for proper operation and return of the monitor to service. l r
2 26 j (m) *50-425/89-02, Rev.0 " Opening Discharge Valves Causes Plant 4 Operation Outside Of Technical Specifications." i j Technical Specification Section 3.4.1.4.2 states," i ... Reactor Makeup Water Storage Tank discharge valves l (1208-U4-175, 1208-U4-176, 1208-U4-177, and 1208-U4-183) shall be closed and secured in. position (in) Mode 5 with j reactor coolant loops not filled." On February 19, 1989, the unit made its initial entry into Mode 5 valves 2-1208-U4-175 and 2-1208-U4-177 were opened. After shift i change, new shift personnel realized that the reactor coolant system loops were not filled and that the two open i discharge valves were required to be closed. A LCO was initiated, the valves were closed and locked, and the LCO was teminated. Plant personnel believed that filling the l RCS above the loops to the reactor vessel flange level constituted a " loops filled" condition, after which opening the discharge valves would have been permissible. With the t j discharge valves open, an inadvertent dilution event of the RCS could have been initiated. A TS interpretation of what constitutes " loops filled" has been added to the Operations Required Reading Book.- The personnel involved were i counseled regarding the importance of complying with TS. Inspector followup determined that prior to the Mode 5 l entry, the SS had been asked to open these same valves to
- l allow chemistry to add primary chemicals.
At that time, the SS was aware that TS 3.g.1 required the valves to be 1 maintained shut in Mode 6 and thought that the change to j Mode 5 would allow.he evolution. TS 3.4.1.4.2 however, also controls these valves when the RCS loops are not l-filled. Operations procedure 12006-C established positive control of these valves by tagging them closed. These valves are untagged by operations procedure 13000-2 upon filling and completing air sweeping of the RCS. The i removal of the RMWST valves to the CVCS was a discussion i item at the shift turnover, however, neither SS recognized the consequences. Later in the shift, the deficiency'was identified and corrected. This item was formally discussed following the enforcement conference on March 22, 1989. This item represents a violation of NRC requirements which i meets the criteria for non-citation. In order to track t51s ites, the following licensee-identified item is i established. I NCV 50-425/89-15-10, " Failure To Maintain RMWST, Discharge Valves Shut Closed And Secured In Position While In Mode 5 i Resulting In TS 3.4.1.4.2 Violation - i.ER 50-425/89-02." l (n) 50-425/89-03, Rev. O "Depressurizing RHR System Leads To Technical Specification 3.0.3 Entry." On March 9,1989, with the unit having just entered mode 3 j for the initial heatup, preparations were being made to. b
l j., l-27 i-f- perform the Pressure Isolation Valve Leakage Test. In j order to ensure proper pressure across the valves to be tested, the Shift Supervisor decided, without an approved l procedure, to depressurize the Residual Heat Removal system, using the RHR test return valves. The SS directed i i a momentary opening of these valves. This resulted in the i return line valves being left open for approximately la { hours, reducing the flow capacity of both RHR trains, and { 1eading to operation under Technical Specification 3.0.3 provisions. This event was caused by (1) operations personnel attempting an evolution without approved procedural guidance, (2) lack of closed loop connunication, j and (3) inadequate system status sensitivity by the operations shift team. Corrective actions include (1) counseling the Shift Supervisor and briefing of each operating crew by th Plant General manager on the j importance of conducting plant evolutions with approved procedures, (2) changing the appropriate procedure (3) stressing precise control room communications. (4) i stressing sensitivity to system status in shift briefings and requalification training, and (5) improving the locked t valve program. This item was cited as a NRC violation in report 50-425/89-12. Remaining corrective actions will be verified in closecut of the violation. l (o) *S0-425/89-04, Rev. O. " Reactor Coolant System Leakage During Check Valve Testing." On March 9, 1989, with Unit 2 in Mode 3, plant operations l personnel performed a pressure isolation valve leakage test. The Primary Coolant Loop #3 Cold Leg Check Valve (2-1204-U6-085) exhibited excessive leakage. A Notification of Unusual Event was declared, because the Reactor Coolant System leakage exceeded the technical specification limit of 5 gpm specified in Section 3.4.6.2.f. On March 10, 1989, the plant entered Mode 5 and the NUE was terminated. The event was caused by excessive wear on internal check valve components. Wear was found 4 I near the pivot pin which allowed the disc to drop down and not seat properly. The valve consists of a disc with two arms which insert into a lock block. The pivot pin goes 1-into the lock block. The disc arms are notched out for alignment with th? pivot pin. Wear was found on both i notches in the arms which allowed the disc to drop. Corrective action included replacement of the internal components in this valve and the three identical check valves in the other three loops. 4 1 4 I
l I p 28 l j (p) *50-425/89-08, Rev. O, " Improper Control Of Steam Generator Water Level Leads To Feedwater Isolation." On March 19, 1989, unit 2 heatup was in progress. The unit j Balance-of-Plant operator was manually controlling the 4 steam generators water levels when a technician requested his assistance in perfoming a surveillance test. The BOP operator left the front panel to go to a back panel area. When he returned several minutes later, he found that an l ' automatic feedwater isolation 'had occurred because SG =4 had exceeded the 78% (narrow range) high-high water level ) setpoint. The operator stopped the feed to SG #4, returned the flow to normal, and long cycle recirculation was j re-established. The BOP operator intended to leave the front panel for only a few moments and did not request j relief. This is the direct cause of this event. Contributing to this event was the Shift Supervisor's j omission in assigning a dedicated Steam Generator Water i Level Controller which is the plant policy when manual SG feeding is in progress. The 80P operator was counseled regarding the importance of maintaining a continuous watch i on operations in progress or else requesting relief if l needed. The SS was advised of the necessity to comply with plant practice to have a dedicated SGWLC when manual SG feeding is in progress. This item was formally discussed 1 following the enforcement conference on March 22, 1989. This item represents a violation of NRC requirements which l meets the criteria for non-citation. In order to track i this item, the following licensee-identified item is established. L i NCY 50-425/89-15-11. " Failure To Exercise The Duties And l Responsibilities Of The R0 And SS As Delineated In i Operations Procedure 10000-C - LER 50-425/89-08." i (q) *S0-425/89-11, Rev. O, " Valve Closure Leads To i Non-Compliance With Technical Specifications." j i Technical Specification 3/4.5.2 require that the Safety i Injection Pump Cold Leg injection valve 2-HV-8835 be open while in Modes 1, 2, and 3. On March 19, 1989, the shift operating crew closed the Safety injection pump cold leg injection valve to the Reactor Coo 1 ant System cold Legs (2HV-8835) while performing the system operating procedure to fill SI accumulators at low RCS pressure in Mode 3. Closure of this valve prevents both SI pumps from being capable of providing automatic injection to the RCS cold legs upon receipt of a 51 actuation signal. On March 26, i while considering LER 2-89-003 (both trains of Residual Heat Removal rendered inoperable due to consen valve I manipulations) and similar situations for other
J, 29 l safety-related systems, a shift supervisor realized that the system operating procedure for filling SI accumulators at low RCS pressure requires closure of 2HV-8835 while in Mode 3. Upon discovering th4-a review of the Unit 1 and Unit 2 accumulator fills was nitiated. Nine separate instances were identified for Unit 1 when 1-HV-8835 was i j closed while in Mode. 3, in addition to the single occurrence on Unit 2, specified previously. The cause of 1 these events is inadequate procedures which did not prevent closure 2HV-8835 during Mode 3 or require accumulator fill j prior to Mode 3 entry. The procedures are being changed to i correct these inadequacies. Future followup on this 1.ER corrective actions will be in closecut of the violation. 7 5 This event is one example of violation 50 424/89-14-01 and 50-425/89-15-01, " Failure To Establish An Appropriate { Procedure To Maintain SI Operable While Filling j Accumulators. t j (r) *50-425/89-14 Rev. O, "Feedwater Isolation Results From. j Error In Startup Test Procedure." ) On April 3, Unit 2 startup testing was in progress. A test ] signal was incorrectly inputted into the steam dump control circuit causing the steam dumps to fully open instead of j opening 10% to 15% as expscted. This led to a steam generator water level swell and a feedwater isolation due i to SG #4 reaching the high-high level. Main feedwater isolation occurred as designed, and the safety pw i isolation valves closed, but main feed pump "A" did not trip. As a result the Auxiliary Feedwater system did not automatically start, although it was already being used to supply'SG water. Manual control was taken of the Steam Generator Feed and unit parameters were stabilized. The i test procedure, which called for an incorrect test signal, i was corrected and the remaining startup tests are being reviewed to ensure that proper connections are specified. Sliding links associated with MFP "A" circuits were found j'~ open and are believed to be an oversight from the Unit 2 construction phase. Similar sliding links were inspected to ensure closure. i This item is part of one example of violation 50-424/89-14-01 and 50-425/89-15-01 discussed in paragraph 3. (s) *50-425/89-15 Rev. O, " Faulty Circuit Cards Results In ESF l Actuations." On April 5,1989, a spurious trip of Main Feedwater Pump "A" generated a Feedwater Isolation signal and automatic actuation of the Auxiliary Feedwater System. On April 7, a i I
T 4, 30 i i i FWI and AFW actuation occurred when a steam generator reached its high-high level setpoint during a test of a i Main Feedwater Isolation Valve. On April 9, a second j spurious trip of MFP "A" generated a FWI and subsequent AFW actuation. The cause of the April 5 and April 9 events was l faulty circuit boards in the Solid State Protection System logic circuits. The April 7 event, although not directly caused by a faulty circuit card, was a consequence of the 1 valve lineup used to functionally test repairs made following the April 5 event. The lineup of long-cycle j recirculation was not properly restored prior to resumption { of startup testing. Corrective actions include replacing j the faulty circuit boards and counseling plant operators regarding proper shift turnover of unusual plant configurations and the need for procedural compliance. This event is part of one example of violation 50-424/89-14-01 and 50-425/89-15-01 discussed in paragraph 3. i j One example of a cited violation and thirteen non-cited violations l were identified. i 5. Actions on Previous Inspection Findings - (92701)(92702) a. (Closed) Violation 50-424/87-30-03, " Failure To Properly Close Valve." l The inspector reviewed the licensee response dated July 13, '087. i Valve No. 1-1208-04-348 has had the lock removed to preclude ature errors in positioning from the remote operator. l b. (Closed) Violation 50-424/88-05-02, " Lack Of Material Control." l The inspector reviewed the licensee response dated March 10, 1988. 4 The inspector noted that procedures exist to control the purchase and ' receipt of weld rod. c. (Closed) Violation 50-424/88 24-01, " Failure To Adequately Design And Install Water Tight Penetration Seals And Perforin An Analysis Which Evaluates Their Failure." The inspector reviewed the licensee response dated September 15,'1988 and reviewed completed MW0s 18900130 and 18900180. During this l inspection period, a similar actuation of the ~ ire suppression system occurred which challenged the seal configuration. Observation by the NRC inspector at that time noted that no water penetrated into the Control Room. i e ee- - +- +
f i 31 l d. (Closed) IFI 50-424/88-43-01, " Verify Resolution Of Restoring The ] SSMP To A Condition To Correctly Indicate The Operability Status." The licensee corrected the condition by implementing a design change j which removed the Boric Acid Pump Motor handswitches as an input to i the SSMP. The inspector verified the change was implemented on l Unit 1. Following the verification, the inspector noted that Unit 2 had not implemented a similar change. The inspector was informed l that design change MOD 89-V2M039 was being developed for Unit 2. The j inspector considered the late implementation of a Unit 2 change to be 4 a weakness in the area of engineering support'in maintaining the i designs both units identical as possible. This change involves the lifting of two leads in each train panel. To track the accomplishment i of Unit 2 change, the following inspector followup item is identified. l IFI 50-425/89-15-03, " Verify Resolution Of Restoring The $$MP To A l Condition To Correctly Indicate The Operabil.ity Status." 1 e. (Closed) Violation 50-424/88-56-01, " Failure To Implement Operations Procedure 14900-1 Containment Exit Inspection Required By TS 6.7.1." ) The inspector reviewed the licensee response dated March 7 1989. Corrective actions have been observed in practice by the inspector. Procedure 43006-C was revised to include controls for health physics j responsibilities. 1 f. (Closed) Unresolved Item 50-424/88-56-02, "Revi.ew Licensee Evaluation Of Compliance To 10 CFR 50.62." l This item concerned the sensitivity of unit personnel to the proper operation and maintenance of AMSAC equipment. The licensee has implemented quarterly and refueling surveillances procedure 54804-1, [ revised response procedure 54804, and revised response procedure 17005-1. Unit operating procedures 12004-C has been revised to the correctly indicate the power level where the equipment becomes i operational. Failure to comply with 10 CFR 50.62 was the result of a failure to establish adequate procedures. Failure to comply with 10 l CFR 50.62 was the result of a failure to establish adequate procedures. l This item is considered to be one of the examples of violation 50-424/89-14-01 and 50-425/89-15-01 " Failure to establish adequate 4 procedures to ensure AMSAC was available. I I g. (Closed) Violation 50-424/88-61-01, " Failure To Implement Operations Procedure 10001-C, Required By TS 6.7.la, To Annotate Ana Verify 3 Proper Operations Of Control Room Chart Recorders." o i In the licensee response dated March 7,1989, to the Notice dated January 20, 1989, the licensee consnitted to full i:.aspliance on l January 31, 1989, upon issuance of standing order C-89-01. This. l t
~ 32 a j standing order was reviewed by the resident inspector on March 24, j 1989, and was found to be satisfactory. 1 One example of a cited violation and one inspector followup item were l i identified. l 6. Exit Interviews - (30703) The inspection scope and findings were summarized on May 5,1989, with those persons indicated in paragraph 1 above. The inspector described the areas inspected and discussed in detail the inspection results. No dissenting comments were received from the licensee. The licensee did not identify as proprietary any of the materials provided to or reviewed by i, the inspector during this inspection.- Region based NRC exit interviews l were attended during the inspection period by a resident inspector. This ) inspection closed five violations (paragraph 5), one unresolved item (paragraph 5), one inspector followup item (paragraph 5), and nineteen Licensee Event Reports (paragraph 4.b(3)). The items identified during this inspection were: Violation 50-424/89-14-01 and 50-425/89-15-01 contains six examples where procedures were not either established or implemented as follows: " Failure To Implement Procedures 00101-C and 50009-C Resulting In TS i l 6.7.1.a Violation" - paragraph 2.b(1) l " Failure to implement Procedure 12004-C Step 4.1.3g and 4.1.4 for Perfoming Transfer From Auxiliary Feedwater to Main Feedwater" - paragraph 3 " Failure To Establish An Adequate Procedure For The Testing Of Steam Dumps" - paragraphs 3 and 4.b(3)(r) ) i " Failure To Implement Procedure 12004-C To Secure From Long-Cycle Recirculation" - paragraphs 3 and 4.b(3)(s) " Failure To Establish An Appropriate Procedure To Maintain 51 l Operable While Filling Accumulators" - paragraph 4.b(3)(q) l " Failure to establish adequate procedures to ensure AMSAC was available" - paragraph ! # IFI 50-424/89-14-02 and 50-425/89-15-02, " Review Licensee Evaluation Regarding Adjustment Of The P-9 Setpoint When Steam Dumps Are Removed From j Service" - paragraph 3 l i IFI 50-425/89-15-03, " Verify Resolution of Restoring The SSMP To A Condition To Correctly Indicate The Operability Status" - paragraph 5.d NCY 50-424/89-14-03, " Failure To Perfom Required Testing Per Surveillance Requirements Results In TS 4.3.3.10 Violations - LER l 50-424/89-06" - paragraph 4 b(2)(a) 4 1-l
33 i NCY 50-424/89-14-04, " Failure To Take Required Temperatures Results In L Inadequately Performed Surveillance Resulting in A TS Violation - LER 50-424/89-07" - paragraph 4.b(2)(b) NCV 50-424/89-14-05, " Failure To Conduct An Adequate Engineering Review Of The AFW Electrical System Which Led To A;N Inoperability Resulting In a TS 3.7.1.2 Violation - LER 50-424/99-08" - paragraph 4.b(2)(c) NCY 50-424/89-14-06, " Failure To Follow Procedures While Conducting A j Liquid Waste Release. Resulting(d) In A TS 3.3.3.9 Violation - LER 50-424/89-10" - paragraph 4.b(2) 1 NCV 50-424/89-14-07, " Failure To Conduct Surveillance Resulting In A j Violation Of TS 4.1.3.2 - LER 50-424/88-30" - paragraph 4.b(3)(h) l NCV 50-425/89-15-04, " Failure To Meet A Mode Change Prerequisite Resulting In A TS 3.7.12 Violation Requiring Valve 2HV-19051 To 8e l Operable Prior To Entering Mode 4 - LER 50-425/89-05" - paragraph j 4.b(2)(e) 2 NCY 50-425/89-15-05, " Failure To Follow Procedures Resulting In l Inadvertent SI Actuation - LER 50-425/89-06" - paragraph 4.b(2)(f) i l NCV 50-425/89-15-05, " Failure To Establish An Adequate Sampling Procedure For Diesel Fuel Oil Per TS 6.7.1.a - LER 50-425/89-09" - paragraph 4.b(2)(h) NCY 50-425/89-15-07, " Failure To Obtain A Radioactive Release Permit i Prior To Releasing Radioactive Materials To Unrestricted Areas Resulting In A TS 3/4.11.1 Violation - LER 50-425/89-10" - paragraph 4.bf2)(1) NCV 50-425/89-15-08, " Failure To Follow Procedures While Performing i Maintenance On 2RE-2562A Resulting In The Plant Operating In A Condition Prohibited 8y TS Thus Requiring Entry Into TS 3.0.3 - LER 50-425/89-12" - paragraph 4.b(2)(j) NCY 50-425/89-15-09, " Failure To Maintain The Auxiliary Feedwater System l Operable Resulting In A Condition Prohibited 8y TS 3.7.1.2. - LER 50-425/89-13" - paragraph 4.b(2)(k) NCY 50-425/89-15-10 " Failure To Maintain RMWST, Discharge Valves Shut Closed And Secured in Position While In Mode 5 Resulting In TS 3.4.1.4.2 Violation - LER 50-425/89-02" - paragraph 4.b(3)(m) l NCV 50-425/89-15-11 " Failure To Exercise The Duties And Responsibilities L Of The R0 And 55 As Delineated In Operations Procedure 10000-C - LER 50-425/89-08" - paragraph 4.b(3)(p) 4 The strengths -in the areas of maintenance (paragraph 2.b(7)) and startup testing (paragraph 3) and the weakness in the area of operations i (paragraphs 3, 4.b(2), and 4.b(3:' were also discussed. i l 4 --=.:-
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j 7. Acronyms And Initialism 4 l ABN As-Built Notice A/DV Anchor Darling Valve AFW Auxiliary Feedwater System AMSAC ATWAS Mitigating System Actuating Circuitry j ASTEC Automatic Surveillance Technical System j BFIV Bypass Feed Isolation Valve i BFRV Bypass Feed Regulation Valve BOP Balance-of-Plant i CCP Centrifugal Charging Pump CCW Component Cooling Water System i j CFR Code of Federal Regulations CRI Control Room Isolation 2 CVCS . Chemical & Volume Control System 1 CVI Containment Ventilation Isolation DC Deficiency Cards i DFDS Diesel Fuel Oil Storage DPIS Digital Position Indication System j DRPIS Digital Rod Position Indication System ECCS Emergency Core Cooling System ERF Emergency Response Facility ESF Engineered Safety Feature FI Flow Indicator FWI Feedwater Isolation GE General Electric i GPM Gallons Per Minute HS Hand Switch l HV High Voltage I&C Instrument and Control l IFI Inspector Followup Item ISEG Independent Safety Engineering Group LCO Limiting Condition for Operation i LER Licensee Event Reports LLRT Local Leak Rate Test LOSP Loss of Offsite Power i MDAFW Motor Driven Auxiliary Feedwater System Pump MOD Minor Departure from Design MFIV Main Feedwater Isolation Valve MFP Main Feed Pump MFW Main Feedwater MOV Motor Operator Valve MWO Maintenance Work Order i NCY Non-cited Violation NPF Nuclear Power Facility l, NR Narrow Range NRC Nuclear Regulatory Commission NSCW Nuclear Service Cooling Water .NUE Notice of Unusual Event 0505' On-Shift Operation Supervisor i
i-l *e I* 9 35 PERMS Plant Effluent Radiation Monitoring System PORV Power Operated Relief Valve PT Pressure Transmitter PV Pressure Valve RCOT Reactor Coolant Drain Tank RCS Reactor Coolant System l RHR Residual Heat Removal System l RMWST Reactor Makeup Water Storage Tank R0 Reactor Operator RPDM Rod Position Deviation Monitor RWST. Reactor Water Storage Tank SAER Safety Audit and Engineering Review SG Steam Generator l SGWLC Steam Generator Water Level Control SI Safety Injection System j SS Shift Supervisor i SSMP Safety System Monitor Panel TDAFW Turbine Driven Auxiliary Feedwater Pump TS Technical Specification TSC Technical Support Center l i 1 3 I 1 I a}}