ML20091M094
| ML20091M094 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 08/28/1991 |
| From: | Mccoy C GEORGIA POWER CO. |
| To: | Lieberman J NRC OFFICE OF ENFORCEMENT (OE) |
| Shared Package | |
| ML20091B437 | List: |
| References | |
| NUDOCS 9201280343 | |
| Download: ML20091M094 (52) | |
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vegx o ; tvsve m am-August 28, 1991 i j Hr. James Lieberman Director, office of Enforcement U.S. Nuclear Regulatory Commission Washington, D.n. 20555 Ret Response to Demand for Information Dear Mr. Liebernant This letter responds to a letter of June 3, 1991 from Mr. James Snlezek, Deputy Executive Director for Nucicar Reactor Regulation. Mr. Sniezek's letter forwarded a Demand for Information concerning an event which occurred at Georgia Power Company's Vogtle Electric Generating Plant ("VEGP") on October 12 and 13, 1988. Since Mr. Sniezek's transmittal was not to be placed in the Public Document Room until a decision in this matter is made, GPC requests that this letter and the enclosed Respense be similarly treated as exempt from disclosure und&r 10 CFR $ 2.790. The NRC's letter and Demand for Information expresses concern that certain VEGP man &gers and supervisors may have intentionally to facilitate outagedisregarded Technical Specifications in an attempt activities. As you may be aware, the NRC's office of Investigations ("0I") initiated a review of this event in' late January,1990 after the NRC received an allegation stating that VEGP Unit 1 was willfully and intentionally placed in a condition investigation wasprohibited com by its Technical Specifications. OI's after its initiation.pleted on March 19, 1991, more than a year is convinced that an impartial and thorough review of theNonetheless, Georgii information supplied in the enclosed Response to the Demand for Information vill conclusively demonstrate that Technical - Specifications were not intentionally disregarded or villfully violated by these employees. The-enclosed Response specifically responds to the Demand ' for Information. As more fully explained in the enclosed c L 9201280343 911231 PDR ADOCK 05000424 Q PDR \
e Mr. JcCO3 Licberman August 28, 1991 Page 2 . Response, the Reactor Haheup Water Storage Tank ("RMWST") discharge valves -176 and -177 were opened on the night shif t of October 11-12, 1988 to permit the filling of the " chemical addition pot" with hydrogen peroxide. The hydrogen peroxide was to be added to the Reactor Coolant System ("RCS") to chemically clean the System as a pre-planned and scheduled outage activity. This shif t did not recognize a Technical Specification conf *1ct, much less commit a willful violation. As to the activities on this shift, GPC has identified the specific causes which contributed to the failure of the operators to recognize a Technical Specification compliance issue as 1) inadequate planning and procedures, and 2) inadequate training and guidance. This was aggravated by lack of experience as this was the first outage performed at Plant Vogtle. The actual context of the event, then, was a pre-planned evolution condected for the first time at VEGP by relatively inexperienced operators who had been provided inadequate guidance. The first opening of the subject valves on October 12, 1988 was personally directed by a rupport Shift Supervisor. In accordance with the pre-planned procedure, this operater specifically supervised the actual opening of the discharge valves -176 and -177 on the night shift of October 11-12, 1988. The shif t was under the general supervision of Messrs. Bowles and Cash. Messrs. Bowles and Cash, the support Shif t Supervisor, and the other shift personnel did not recognize that the plant was in a " loops not filled" condition requiring those valves to be closed and secured in position. Instead, these operators were focused on lowering the RCS level to "mid-loop" or the " top of the hot legs" which they equated with the " loops not filled" condition. night shift ofThis "mid-loop" October 11-12,conditipn 1988. was not reached on the These operators, who I GPC observes that the allegation supplied to the NRC in January, 1990 also erroneously equates a "mid-loop" elevation condition of the RCS of 188'-0" with " loops not filled" Mode 5. As with these three operators on the night shift of October 11-12, the submitter of the allegation apparently viewed the terms of "mid-loop" and " loops not filled" as interchangeable. Such is not the case. On the morning of October 12, 1988 by about 3:30 a.m. (CT) the RCS water level had been drained down to the 189'- 10" level and the steam cenerator tube bundles had been drained; the Plant was in Mode 5 with loops not filled, and Technical Specification S 3.4.1.4.2 was app 11 cabin. However, the RCS water level had not yet been lowered to a "mid-loop" condition as then understood by these operators.
4 Mr. Jams Licberann August 28, 1991 Page 3 possessed inadequate training and guidance concerning the " loops not filled" status of the RCS, believed that the condition triggering the Technical Specification had not yet been reached. Latar, on tue morning of October 12, 1988, the on-coming Shift Supervisor identified the Technical Specification as a potential constraint to the chemical creaning evolution. At that point in time, somewhere between 5:07 and 5:33 a.m. (CT) Mr. Bowles, who was being relieved as Shif t Supervisor, , recognized for the first time the potential applicability of the Technical Specification with respect to the optning of RMWST valves -176 and -177 on his shif t. Mr. Dowles recorded a " late entry" which Technical acknowledged Specification his crew's activities and the specific at issue. This log entry, in GPC's view, confirms the straightforward, simplistic manner in which the chemical cleaning evolution was approached by the night shif t and the late realization that Mode 5 " loops not tilled" might have been entered. Again, to GPC's knowledge no night shift crew member held any reservation or concern, o,r identified any regulatory constraint, applicable to the pro-planned and scheduled chemical cleaning evolution. In the Demand for Information and its transmittal letter, the HRC states that 01 has concluded previously that this event involved willful Technical Specification violations. GPC takes these charges very seriously and, accordingly, we have conducted a thorough review of this matter, including the portions of the OX record available to us. GPC has substantial reservations as to the completeness and accuracy of the 'oI review. With respect to the licensed personnel on the night whif t of October 11-12, 1988, the r cord is clear that they we unaware of the implications of Technical Specificatio. ,4.1.4.2 to scheduled activities prior to shift turnover. Thi. apparent deficiency in oI's analysis is underscored by oI's fallore to interview the SRO-licensed Support Shif t Supervisor who personally supervised the addition of hydrogen peroxide to the chemical mixing tank during the night shift. GPC also believes that 01 ignored the institutional causes of the entrance into the LCO by this shif t crew. The specific procedure relevant and central to this activity was the detailed procedure for the outage chemistry activitics contemplated for Unit-1 which was developed by the Health Physics and chemistry Department (Pror dure 49006-C, approved June 9, 1988). This procedure., at page 15 of 36, provides for the drain-down to mid-loop and requires that "when the drain-down is complete, Hydrogen Peroxide should be added." The developer of this procedum had
4 Mr. Jatss Llobarcan August 28, 1991 Page 4 incorrectly concluded that no change to Technical Specification was involved. With respect to the activities of the day sh.'f t of october 12, 1988, GPC's enclosed response reviews the actions of the operations Manager, Mr. W. F. (Skip) Xitchens relative to his interpretation of Technical Specification 3.4.1.4.2 as paraitting the RMWST valves to be opened for a short period of time for chemical cleaning activity. Substantial doubt exists that Mr. Mitchens know, or should have known, that the manipulation to the open position of the RMWST valves was prohibited by the Technical Specification (as indicated in the Demand) . Also, no doubt exists that he reached his interpretation that his actions were allowed by the Technical Specification af ter conscientiously and openly reviewing the matter, after obtaining advice from a more experienced operations manager and others, af ter reviewing documentation relevant to interpreting the Technical Specification, and after applying principles of Technical Specification compliance which are established and recognized in the industry. His actions were consistent with NRC quidance issued prior to the activity which stated that "the NRC endorses Voluntary Entry into the Action Statement conditions and has structured the Technical Specification to permit the licensee to exercise judgment within the latitude permitted by the Action Statement language in the Technical Specifications." Thus, if his actions led to a Technical Specification violation, it certainly was not a v111tui violation. Moreover, the enclosed Response establishes that reasonable minds can differ as to whether the actions taken on october 12-13, 1988 violated NRC requirements. These actions were viewed, in good faith, as voluntary entries into a Limiting condition for operation ("LCo") in which the required action was completed within an "immediate" duration as required by the Action Statement. As one basis for this proposition, GPC is uvare of a more recent, similar event reviewed by Region II involving the voluntary entry into a Limiting condition for operation at another facility where the required "immediate" action was viewed by the licensed operator as permitting voluntary entry into the Leo for a duration of time for a planned evolution. This demonstrates that other operators are still making this judgment. CPC's position that well-intentioned persons can reasonably interpret Technical Specification 3.1.4.1.2 as permitting voluntary entrance for short durations is supported, also, by the history of the January, 1990 allegation which prompted the NRC's review of this matter. The allegation was submitted anonymously t
Mr. J nes Licbortan August 28, 1991 Page 5 by a former manager and Plant Review Board member. On November 17, 1089 this individual voted that the October,1988 event was not reportable to the NRC under 10 CFR $ 50.73, reflecting his conclusion at that time that the events were not ' prohibited by Technical Specification. He testified to this effect on February 8,1990 in a transcribed OI interview. These events, and tne fact that NRC and indus'try representatives have long recognized the- ambiguity inherent in the use of the word "immediate" in Technical Specifications, suggest that additional HRC guidance to licensed operators is far more appropriate than formal enforcement action. OI's oversight of relevant and material facts surrounding the october,1988 chemical cleaning also is reflected by an apparent total discounting of Mr. Kitchens' good faith, straightforward efforts in interpretation of the relevant Technical specification. Mr. Kitchens postponed the chemical cicaning, applied a well-establisned and observed principle of Technical specification construction (i.e. , voluntary entrance into an LCo is permissible provided that the associated Action statement is complied with), cons:tously reviewed the relevant portione of the FSAR, and obtained input from a more experienced operations manager in addressing the meaning and application of the Technical specification. This review was open and shared with those on shif t and others, perhaps including an NRC Resident Inspector.- For OI to reach a conclusion of willful and intentional wrongdoing while possessing this information is inconceivable. After a careful and thorough review, GPC has concluded this matter is not reflective of wrongdoing on the part of VEGP licensed operators but is indicative of historic institutional weaknesses (i.e., planning and procedures for infrequent evolutions and training and pidance for operators responsible for such nvolutions) and ambiguous terminology in Technical specifications in light of historic practices and interpretations (i.e., routine voluntary entrance into LCoe for maintenence activities; "immediate* durations in- LCos and associated action statements). NRC-representatives have indicated that significant internal discussions and disagreements concerning the appropriate interpretation of the subject Technical Specification and the reaso.1 ableness of Mr. Kitchens' interpretation preceded the issuance of the Domand for Information. This discussion the extensive time taken by OI in reaching a conclusion (over, a year since completion of interviews of the operators and Mr. Kitchens), and the clear potential in the future for similarly-situated operators to reach the same type of conclusion
Mr. James Lieberman August 28, 1991 Page 6 . demonstrate the inappropriateness of formal enforcement action in this matter. GPC recognizes that the NRC now views "imm$diate" LCOs and associated action statements as action statements which implicitly prohibit voluntary entrance. The company has already implemented measures to assure that thi,s position is implemented by VEGP operators. The information best of my knowledge.provided herein is true and correct to the Sincere 1pyours p Ob C. Kenneth McCoy sworn to and subscribed-before me.this JJ day of
. August, 1991.
NAAA4 M - I8 i: Notary Public f~ My Commission-' expires un m.ucMuM?.t 8,Wa
~
CXMinjf-2nclosure cc: Mr. James Sniezek-
-Mr. Stewart Ebneter Mr.. Alan Hardt Assistant General Counsal-for Hearings'and Enforcement Mr. David-B. Matthews l
~ l_ ._.
-. ~-. .- - - - _.. .= . . . . .
d UNITED STATES OF AMERICA NUCLEAR REGULATORY COMNISSIO.i In the Mattar of GEORGIA POWER COMPANY, *
.ti 31
- Docket Nos. 50-424 50-425 (Vogtle Electrio
- EA 91-063
, Generating Plant, a i Unita 1 and 2)
- G ;ORGIA POWER COMPANY'S RESPONSE TO THE NRC88 JUNE 3, 1991 DEMAND FOR INFORMATION c >
r
, _ , - - , . . ~ - - - ~ - - , - - - - - ' ' ' * ~
TAllLE OF CONTENTS
- 1. INTRODUCTION , . . . . . . . . . . . . . . . . . . . . . 1 II. BACKGRO'JND . .. . . . . . , . . . . . . . . . . . . . . 1 A. The First VEGP Unit 1 Refueling Outage And The Chemical C1eatting Process . . . . . . . . 2 S. The V5GP Technical Specifications And Facility Safety Analysis Report . . . . . . . 2
- 1. VIGP Technical Specification 5 3.4.1.4.2 . . . . . . . . . . . . . . . . 2
- 2. VEGP Facility Safety Analysis Report, Section 15.4.6 . . . . . . . . . . . . . 3 III. GEORGIA POWER COMPANY'S DETAILED RESPONSE TO SECTION III 0F THE NRC JUNE 3, 1991 DEMAND FOR INFORMATION . . . 4 A. The Actions of Messrs. Kitchens, cash And Bowles With Respect To The Addition of Chemicals To The VEGP Unit 1 Reactor Coolant System On October 12 And 13, 1988 . . . . . . 4
- 1. The Night Shift of October 11-12, 1988 and the Actions of Mossrs. Bowles and Cash . . . . . . . . . . . . . . . . . . 4
- 2. The Day Shift of October 12, 1988 and the Actions of Mr. Kitchens . . . . . . . 8 B. Messrs. Kitchens, cash And Bowles Should Not t
Be Removed From Licensed Activities Because They Did Hot Willfully Violate The Tech. Specs. . . . . . . . . . . . . . . . . . . . . 10
- 1. The Standards for "W111 fulness" and for Enforcement Against Individuals . . . . . 10
- a. The "Wi11 fulness" Standard . . . . 11
- b. Enforcement Actions Involving Individuals . . . . . . . . . . . . 13
- 2. Messrs. Bowleo and Cash Lacked the Necessary State-of-Mind Requisite to a Willful Violation . . . . . . . . . . . . 14 i
~~
1 TABLE OF CONTENTS, Continued
- 3. Hr. Kitchens 8 Interpretation of Tech.
Spec. S 3.4.1.4.2 was Reasonable and in Good Faith . ... . . . . . . . . . . . 18
- 4. The Chemical Addition Evolution Lacked Safety Significance . . . . . . . . . . . 22
- 5. Reasonable Hinds Can Differ as to Whether, in 1988,_ Voluntary Entry into the Tech. Spec. $ ? 4.1.4.2 LCO was Permissible . . ... . . . . . . . .. . 24
- c. Georgia Power Company Procedures Relating To The Issuance And Control Of Technical Specification Clarifications . . . . . . . . . 32
- 1. The Policies and Procedures in Place at '
the Time of the Addition of Chemicals on October 12 and 13. 1H8 . . . . . . . . . 32
- 2. Current Policies and Procedures . . . . . 32 D. The Georgia Pow 2r Company Outage Planning Process ......... . . . . . . . . . . 34
- 1. Planning for-the IR1 outage and Development of the Procedures to Add Chemicals to the RCS_at the Mid-loop Condition of Hode 5 . . . . . . . . .. . 34 2 .' Current Outage Planning Process . . -. . . 36 E.- Georgia Power company Policies, Procedures.
Practices And Training Respecting Compliance With The VEGP Technical Specifications . . ._ . 37 IV. REASONABLE ASSURANCE EXISTS THAT GEORGIA POWER COMPANY CURRENTLY CONDUCTS AND WILL'IN THE FUTURE CONDUCT LICENSED ACTIVITIES IN ACCORDANCE WITH THE VEGP TECHNICAL SPECIFICATIONJ AND ALL OTHER NRC-REQUIREMENTS . . .......... . . . . . . . . -. . - -39 !f V. CONCLUSION . . .. . .................. 41 11 _.__ _ ___ _ . . _ _ . . _ _ . - _ _ _ _ _ . _ . _ . _ . _ . _ . _ .~ . _ ._ __.._.._._ _ _ . .
I. INTRODUCTION. On June 3, 1991, the Nucinar Regulatory Commission ("NRC") , issued a " Notice of Enforcement. Conference and Demand for Information" to the Georgia Power Company ("GPC" or the
" Company") with respect to the addition of chemicala to the reactor coolant syste:s of Vogtle Electric Generating Plant
(VEGP") Unit 1 on October 12 and 13, 1988, durinq the first refueling outage of that unit. The Notice stated dat the event involved "the apparent willful violation of Technical Specification 3.4.1.4.2" which had been investigated by the NRC in response to information the NRC received in January 1990. The Notice contained a " Demand for Information" listing five specific items of information which GPC Vas to provfde. A similar Notice of Enforcement Conference and Demand for Information was sent to Mr. W. F. Kitchens, the VEGP Manager of operations during the event. Also, separate Demands for Information were sent to Mr. J. P. Cash h.,d Mr. J. E. Bowles, who were licensed Senior Reactor Operators 'on shift" on October 11-12, 1988. Following a brief background discussion (Section II), GT provides herein (Sections III. A through III.E), the spacific information required by the Demand for Information. Exhibits 1-47, referred to herein, are included herewith, separately bound as " Appendix 1." Attachments 1, 2 and 3, referred to herein, are included herewith, separately bound as " Appendix II." II. HAcKGROUND. A. The First VEGP Unit 1 Refueling Outage And The Chemical Cleanina Process. . The first VEGP Unit i refueling outage (sometimes referred to as "1R1") began on October 8, 1988 and lasted 52 days. Nunerous major activities typical of a first refueling outage were performed. Also, the addition of hydrogen peroxide to the Reactor Coolant System ("RCS") was scheduled to be performed during the C dd Shutdown mode, as a planned evolution. Addition of hydrogen peroxide to the RCS is an established and accepted method of chemically cleaning the internals of the RCS in order to remove contaminated particles (referred to as " crud") such that the radiation exposure to individuals working in and around the RCS during the outage is significantly reduced. The procedure is referred to as a " crud bursta or " chemical c1 caning" and is performed during Cold Shutdown (Mode 5) prior to opening up tt RCS for refueling (Mode 6). While the procedure may be perfou,ad with ths RCS full, it may be, and has been, performed at other plants with a reduced RCS coolant inventory. 1
planning for the chemical addition evolution at VEGp during the IR1 outage began in December 1987. By April 1988, a decision had been made to add the chemicals while the RCS was at a reduced
- Inventory pursuant to the recommendation of the VEGP Health Physics and Chemistry Department. The 1R1 outtge schedula identifying the chemical addition evolution vas approved by the VEGp General Manager after it had been approved by all VEGP Department Managers. A more detailed discussion of the planning !
process for the 1R1 outcge relative to this evolution is provided in Section III.D of this response. In the case of VEGP, the addition of hydrogen peroxide to the RCS wts to be accomplished with the Chemical and Volume Control System ("CVCS"). As illustrated on the simplified piping ! diagram attach 6d as Exhibit 1, Valve 177 controls the discharge of unborated water from the Reactor Hakeup Water Storage Tank ("RMWST"), and Valves 175, 176, and 183, located dow'.s'a cam of valve 177, govern three independent flow paths leading to the RCS. The 11ov path through Valve 176 is the one used to add chemicals to the RCS and Valve 176 regulates the input of RMWST water into the Chemical Mixing Tank (also referred to e 5 the
" Chemical Mixing Pot" or " Chem. Ad6 Pot") . Therefore, to add RHWST water to the Chemical Mixing Tank, Valves 177 and 176 must be opened. Valve 183 (ths outlet valva), must also be opened before the discharge trc the Chemical Mixing Tank can flow into the RCS.
B. The VEGP Technical Soecifientions And Facility Safety Anillais Report.
- 1. VEGp Technical Specification 5 3.4.1.4.2.
From March 1987, when the Unit 1 operating license was issued, through 1989, Technical Specification (" Tech. Spec.") $ 3.4.1.4.2 required, in relevant part, that the RMW4T discharge Valves 175, 176, 177, and 183 be closed and secured in position while the reactor is in Mode 5 with the RCS in the " Loops Not Tilled" condition. The Westinghouse analysis of the boron dilution accident divides Mode 5 into two conditions: Mode Sa, " Loops Filled," and Mode 5b, " Loops Not Tilled. " ~5e " Loops Not Tilled" condition is not defined in the VEGP Tech. Specs. Also, in October 1988, the " Loops Not Filled" condition had not been explicitiy defined for the VEGP operators during their training or in any guldence documents or procedures. The Westinghouse analysis of the boron dilution accident defined " Loops Not Filled" based on volumes which equated approximately with a RCS water level beJow 192 feet 2r when the RCS piping, including the primary side of the steam generator tubes, was not full (e.g., there was an air void 2
f' D l, (/ co: whero in thu RCS piping, including th0 pricory cido of the l steas generators). Ang ExhAbit 17. ! The relevant " Action Statementa for Tech. Spec. $ 3.4.1.4.2
- reads: l I
With the (RMWST discharge valves) not closed and secured in position, immediately close and secure in position the RRWST discharge valves. San Tech. Spec. S 3. 4.1. 4 2, attached as Exhibit 2, sheet 1 of 2. The " Bases" section of the Tech. Specs. explains the purpose of Tech. Spec. $ 3.4.1.4.2 as follows: Tha locking closed of the required valves in Mode 5 (with the loops not filled) precludes the possibility of uncontrolled boron dilution of the filled portion of the Reactor Coolant System. This action prevents flow to the RCS of unborated water by closing flovpaths ! rom sources of unborated water. These limitations are consistent with the initial conditions assumed for the boron dilution accident in the safety analysis. Egg Exhibit 2, sheet 2 of 2.
- 2. VEGP Facility Safety Analysis Report, Section 15.4.6.
Section 15.4.6 of the VEGP Facility Safety Analysis Report ("FSAR") describes the analysis of a boron dilution accident resulting free a malfunction in the CVCS. Il c.4 uror 1988, FSAR S 15.4.6 contained the following lenguage ir.!2A: tion 15.4.6.2.2.2: , For dilution during cold shutdown, the Technical Specifications provide the required shutdown margin as a function of RCS boron concentration. The specified s')atdown margin ensures that the operator has 15 min from the time of the high flux at shutdown alarm to the total loss of shutdown margin. Egn Exhibit 3 at p. 15. 4. 6-4. Additionally, Section 15.4.6.2.1.2 expressly stated that an snalysis had been performed "to evaluate boron dilution events during cold shutdown." It identified four
" initiators" which had been analyzed, including the afailure to secure chemical addition," but that initiator was not identified as the most limiting. It also included the following paragraph at the very end of the section:
3
Since tho activo volunos considored aro so ccall in cold shutdown with the reactor coolant loops drained it was determined that the same valves locked out in re, fueling would need to be locked out in cold shutdown when the reactor coolant loops are drained. Ets Exhibit 3 at p. 15.4.5-2a. With respect to refueling, rSAR $ 35.4.6.2 provided that dilution during Mode 6 could not occur due to administrative controls shich isolated the RCS from potential sources of unborated water, including the RMWST discharge valves which "will be locked closed during refueling operations." Egg Exhibit 3, Sections 15. 4 . 6. 2.1.1 and 15. 4. 6. 2. 2.1, at pp. 15.4.6-2 and ~4, respectively. It should be noted that prior to December 1986, FSAE 5 15.4.6 discussed a boron dilution accident analysis of Mode Sb which didaddition." chemical exist at that time for the initiator " failure to secure That analysis was revised in December 1986 and, thereaf ter, it no longer contained an analysis of Mode 5b.
}towever, only piecemeal changes were made to FSAR S 15.4.6 in December 1986 to reflect the then current boron dilution analysis. The result was a patchwork discussion which suggested that an analysis of Mode 5b still existed while, at the same ,
time, it also attempted to explain that administrative controls were necessary in Mode sb because such an analysis no longer existed. For a more extensive discussion of the evolution of FSAR $ 15.4.6, as well as a discussion of NRC Safety Evaluation Report $ 15.4. 6, see Attachment 1. III. GEORGIA POWER CCMPANY 'S DETAILED RESPONSE TO SECTIO'A III 0F THE NRC JUNE 3. 1991 DEMAND FOR IHFORMATION. A. The Actions of Messrs. Kitchens, cash And Bowles With Respectcoolant Bractor To TheSystem Additionon of October Chemicals 12 To And The 13.VEGP Upit 1 1988
- 1. The Night Shift of October 11-12, 1988 and the Actions of Messrs. Bowles and Cash.
on the morning of October 11, 1988, the VEGP Unit i reactor was in bega duty. Cold Shutdown with the Loops Filled when the " Day Shift" Egg VEGP Unit 1 Shift Eupervisor Les for October 11-I The events described herein are, in the company's opinion, l the most probable sequence of events based on (1) the infornation t provided to the company by the various individuals involved, and (2) a review of those oI interview transcripts which were mada l available to the company. i I
13, 1988, attached as Exhibit 4, entry at 0536 hours on October 31, and VEGP Unit 1 Control L9g for October 11-1 1988, attached as Exhibit 5, entry at 0602 hours on Octobor 11.), Mr. Jeffrey T. Casser was the Unit Shif t Supervisor on the Day Shift and Mr. John D. Hopkins was the On-Shift Operations Supervisor ("0 SOS").3 At 7:21 a.s. CT that morning, the Day Shif t began draining down
*he RCS in preparation for refueling. En Exhibit 4 and Exhibit 5 entries at 0721 hours on october 11.
At 9:35 a.m. CT that morning, red clearance tag were hung by the Day Shif t on dilution flow path valves (Nos.175, 176, 177, 181,183 and 226) pursuant to VEGP Procedure 12006-C, 5 D(.2.14. Kit VEGP Procedure 12006-C, Rev. No. 9 " Working copy," attached as Exhibit 6, at p. 31; RER A112 Clear Clearance No. 1-80-371, attached as Exhibit 10.gnce Sheet That for procedure required those valves to bt closed prior to draining the RCS to "25% cold calibrate pressuricer level," which level corresponds to a RCS water level of approximately 219 feet. The clearance 2 Although VEGP is in the Eastern Time Zone, the time entries on the VEGP Shift Supervisor and control Room Logs reflect Contral Time (hereinaf ter "CT") to correspond with The Southern Company energy control center, located in the Central Time Zone in Alabama. 3 The hierarchy of the VEGP Operations Department relevant to this discussion, beginning with the department head, was first the Operations Manager, second the Deputy Manager of Oparations, third the Operations Su operations Supervisors,perintendents, fourth the On-Shif t and fifth the Unit Shift Supervisors. In addition, the following personnel provided direct support to and were under the direction of the Unit Shif t Supervisors: dupport Shif t Supervisers, Reactor Operators, Balance-of-Plant Operatorn and Plant Equipment Operators. 8 The red clearance tags ensured that the valves could not be manipulated without first obtaining the proper approvals to
" release" the clearance. 533 VEGP Procedure 00304-C, Rev. No.
14, attached as Exhibit 7, " WARNING," at p. 11. At that time, VEGP procedures permitted the use of clearance tags to administrative 1y control small valvas which could not feasibly be locked but were required under the Tech. Specs. to be " closed and secured in position." Egg VEGP Procedure 20019-C, Rev. No. 4, attached as Exhibit 8, S 5.1.4, p. 2. However, as a result of an April 1990 NRC Notice of Violation, GPC revised its procedures to require a locking mechanism, and to eliminate the use of clearance tags, when the Tech. Specs. require valves to be secured in position. Sig NRC Inspection Report Hos. 50-424/91-14 and 50-425/91-14, dated July 19, 1991, attached as Exhibit 9, Details S 3.1, at p. 10. 5 Y
7- _ _ _ _ _ ._ _ .-_ _ _ _ . _ .. _ _ __ ___ _ __ _ _._. tags voro verified by tho Day Shif t at 10:53 a.c. Cf. 333 Exhibit'10. On the evening of October 11, 1988, the operations
- Department " Night Shift" crew relieved the bay Shift and Kr. John Bowles was the on-coming Unit Shift Supervisor, Mr. Jimmy Paul Cash, the 050s, and Mr. W. Thomas Ryan, the Support Sbitt Supervisor. 133 Exhibit 4 entry at 1736 hours on October 11.8 g At tl.a start of the Night Shif t, the RCS vater level had been drained down to the 1948 level and activities were in progress to further drain the RCS. Id2 Either preparation for the displacement or initial displacement (by, injection of nitrogen of primary water from the steam generator tube bundles was gas)iated init at 7:06 p.m. CT on October 11 and the displacement was completed by 1:50 a.m. CT on October 12, 1988. 133 Exhibit 5 entries at 1f06 hours on October 11 and 0150 hours on October 12.
i Sy about _3:30 a.m. CT on the morning of October 12, 1988, the RCS , water level had been drained down to the 189'-10" level. Egg - Exhibit 5 entry at 0333 hours on October 12. At about 3:00 a.m. CT on October 12, in preparktion for the i planned addition of hydrogen peroxxde to the RCS, a "runctional Test Forn" was authorized by the Support Shift Supervisor and , completed to release Clearance No.- 1-88-371 from RMWST discharge l valves 176, 177 and 181. 513 Functional Test Torm for Clearance i 1-as-3 hours.l1,attachedasExhibit14, Clearance No. 1-88-371 was later restored at 4:15 a.m. entries at 0250 and 0310 ; CT and verified at 4:25 a.m. CT. Egg Exhibit 11 entries at 0415 and 425 hours. ; At 4:00_ a.m. CT on October 12, Mr. Ryan supervised Plant ; Equipment operators and' coordinated with the Chemistry Department i in order to load approximately five bottles of hydrogen -peroxide into tho Chemical. Mixing-Tank and fill the tank with water from 1' the RMWST. VEGP Procedure 13007-1, Rev. No. 2 (attached as 8 As this was the first refueling outage at the VEGP_ site, it.vas a relatively new experience for a number of the VEGP operators, including Messrs. Cash, . Bowles, Ryan and Hopkles, and, unt times relevant to the' chemical addition activities, the Unit 1 ; Control Room was busy. VEGP_ Procedure 00304-C, S 4.7, entitled " Performing l Tunctional Tests," contains provisions for releasing a clearance from a piece of equipment on a temporary basis. Egg Exhibit 7 at
- p. 19-21.- Its application was not limited to performance of a functional test; the established practice at VEGP at the time was to use "functionals" when the operators wished to retain-administrative control over a piece of equipment in operation until'the clearance was restored.
6
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Exhibit 12), S$ 4.7.1 through 4.7.4, addres=d tho icolaticn cf the Chemical Mixing Tank (to permit the loading of chemicals into the tank pursuant to VEGP procedure 35110-C) and the opening of Valva Exhibit176 12 in at order to fill the tank with RMWST water. Sit pp.12-13. opening of Valve 177. The Functional Test Form authorized the Because of difficulty in verifying the RCS water level measurement and/or the impending shift turnover, the chemicals were not injected into the RCS (S$ 4.7.5 through 4.7.12 of Procedure during the Night13007-1 Shif t. (Exhibit 12)) at that time or at any time Mr. Dowles recorded at 4 :00 a.m. CT the following entry in the Shif t Supervisor Log Lt the t.ing ihn shcaln 11 Etta loaded: CVCS chemical mixing pot loaded with hydrogen peroxide, runctional clearance 1-sti-371 te allow sending chemicals. , En Exhibit 4 entry at 0400 hours on October 12. Between 5:07 a.m. and 5:33 a.tr.. CT on October 12, 1988, the on-coming Day Shif t supervision for the first time raised a question concerning the application of Tech. Spec. S 3.4.1.4.2. Following this discussion, Mr. Bowles added the following to the Shitt Supervisor Log as a " Late Entry" ("LE"): Valves 1-1208-04-177, 1-1208-U4-176, and 1-1208-U4-181 opened to fill CVCS drain pot. Above mentioned valves immediately shut upon completion of fill in accordance ; with Tech Spec 3. 4.1. 4. 2. En Exhibit 4 entry "LE 0400" directly following the entry at 0507 hours on October 12. Although Mr. Bowles identified BMWST discharge Valvet 176, 177 And ljt1 in the Late Entry, it is clear that Valve 181, which controlled ti.e discharge from the chemical Mixing Tank to the RCS, had not been' opened. Messrs. Bowles, Cash and Ryan were unaware of any conflict be:veen the Tech. Specs. and the opening of RMWST discharge Va.ves 176 and 177 at the time of the operation of those vs.1ves at 4:00 a.m. CT on October 12. 1988. No one on the Night Shift raised a question concerning the operation of the valves. In fact, as will be discussed further below, Mr. Bowles and Mr. Cash did not believe, at the time the valves were opened, that the RC!i was in the " Loops Not Filled" condition, a prerequisite to the applicability of Tech. Spec. S 3.4.1.4.2. However, once Mr. Bowles discussed the Tech. Spec. With the on-coming Day Shift supervision, both he and Mr. Cash thED considered for the first time the applicability of the Tech. Spec. At that point in time (5:07-5:33 a.m. CT) Mr. Bowles recorded the "LE 0400" entry quoted above. i The Functional Test Form permitting the 4:00 a.m. valve l manipulation (Exhibit 11) does not indicate the period of time , 7 l
l that RMWST dischargo */olves 176 and 177 woro opan; it only l indicates the period of time that the valves were released from Clearance No. 1-88-371 (i.e., about one hour). ,
- 2. The Day Shif t of October 12, 1988 and the Actions of Mr. Kitchens. I At 5:33 a.m. CT on October A1, 1988, the Day Shitt relieved the Hight Shif t. Mr. Jeff Gasser was the on-coming Unit Shift Supervisor and Mr. John D. Hopkins was the on-coming OSOS. Act Exhibit 4 entries at 0533 and 0535 hours on October 12. Messrs.
Gasser and Hopkins realized when they reviewed the log books in preparation for beginning their shift, that the prior Night Shift had opened the RMWST valves. Mossrs. Hopkins and Casser had a l question about the propriety of opening the RMWST discharge valvas in light of Tech. Spec. S 3.4.1.4.2, and the matter was d with the prior Hight Shif t Unit Shif t Supervisor, Mr. discuss Bowles. 9 As discussed above, that led Mr. Bowles to the decision to record the "LE 0400" entry on the morning of the 12th. Since the chemical addition remained to be performed during his shif t, Mr. Hopkins discussed the implication of Tech. Spec.
$ 3. 4.1.4.2 wxth Mr. Gasser and with Mr. W. F. " Skip" Kitchens, the Operations Manager at the time, who was in the control Room.
Mr. Kitchens told Mr. Hopkins to sucpend chemical addition activities until they, Mr. Kitchens and Mr. Hopkins, could discuss the matter again after the 6:00 a.m. C7 combination OSOS/ outage status meeting that morning. The OSOS/ outage status meeting was attended by about 20 individuals, including the osos, the outage & Planning Manager, Mr. Kitchens, and, we believe, an NRC Resident Inspector. While discussing the outage in general, the chemical addition evolution was raised as an item since, pursuant to the schedule, the RCS could not be opened until the chemical cleaning was complete. Mr. Kitchens believes that he explained at the meeting that the
, chemical addition had been put on hold because a Shif t Supervisor had raised a question concerning Tech. Specs. which Mr. Kitchens wanted to review, i
I Without question, the focus of the prior Night and Day Shif ts was on achieving the condi110D of "Mid-loop" elevation, and not the achievement of a " Loops Not Filled" condition. In contrast to Messrs. Bowles and Cash, Mr. Hopkins recognized the possibility that the RCS yAg in the Loops Not Filled condition and Mr. Casser, who was apparently the only licensed individual to do so, concluded that the RCS was in the Loopa Not Filled l condition because primary water had been displaced from the steam generator tubes. l 8 l
l At a bout 6 : 10 0. c. CT, following tha OSOS/outogo Otatus mentirug, Messrs. Kitchens and Hopkins reviewed the Tech. Specs, and the VEGP FSAR and they spoke with Mr. Walter Marsh, the Deputy Manager of Operations at the time. Mr. Hopkins concluded,
- with the concurrence of Mr. Kitchens, that, assuming the RCS was in the Loops Not Filled condition, voluntary entry into the Lc0 of Tech. Spec. S 3.4.1.4.2 for a maximum of flyg minutes vould be conservative and would not violate the Tech. Spec. Mr. Hopkins' conclusion was based on Mr. Kitchens' determination that opening the RHWST discharge valves for no more than 15 minutes would ge pernissible. Mr. Gasser concurred with Mr. Hopkins' decision and no one on-shif t raised any concerns with the decision.
Af ter reaching their conclusion, Messrs. Casser and Hopkinu authorized the release of Clearance No. 1-88-371 through the completion of the Functional Test Forms attached as Exhibit 13. They directed their shif t personnel to open the RMWST discharge valves for no more than five minutea and to contact the Control Room at the moment the valves yere opened and, again, at the moment the valves were closed. The chemical addition procedure was performed by Messrs. Gasser and Hopkins a total of three times over the course of October 12 and 13, 1988. They were careful to record in the Shif t Supervisor Log the time that the specific valves were open during each injection. Egg Exhibit 4 entries at 0705 and 0709 hours on October 12 apd entries at 1030, 1034, LE 1640 and LE 1644 hours on October 13. Subsequently, Messrs. Hopkins and Kitchens contacted the Manager of Huclear Safety and Compliance ("NSAC") at VEGP, Mr. James E. Swartzvolder, on scporate occasions. Mr. Svartzvelder, who was also a licensed Senior Reactor Operator and an experienced operator, concurred that a permissible interpretation 8 At shif t turnover, Mr. Gasser had developed a pn1Jminny conclusion that a short-duration entrance into the LCo of Tech. Spec. S 3. 4.1. 4. 2, voluntarily made, was permissible so long as there was compliance with the Action Statement. When he raised the issue, he sought clarification from his supervisor. Consequently, the question posed to Mr. Kitchens had been tentatively, albeit not conclusively, answered as paraitting the evolution. Mr. Kitchens nonetheless deferred the evolution until time permitted an adequate review. )
' Although GPC is aware of an allegation that Mr. Kitchens personally manipulated the valves, it is clear that the valves were manipulated by others under the direction of Hessrs. Gasser and Hopkins.
10 For convenience, the Company has prepared a chronology of the pertinent events of October 11-13, 1988, which is attached as Exhibit 14. 9 l
had be:n c de. Han tholocs, Massrc. H:pkinc and/cr Kitchons ! asked Mr. Swartzwelder to initiate a formal amendment to Tech. Spec. S 3.4.1.4.2 to clarify the acceptability of the chemical addition decision for the future, since it was likely that the ' chemical cleaning would 'os conducted during future refueling outages. B. Messrs. Kitchens, cash And Bowles should Not Be Removed Trom Licensed Activities Because They Did Not Willfully Violate The Tech. Snees. _.
- 1. The Standards for "W111 fulness" and for Enforcement Against Individuals.
In its June 3, 1991 Demand for Information, the NRC states that the NRC's Office of Investigation ("0I") completed an investigation of the October 12-13, 1988 chemical addition evolution. OI concluded that Tech. Spec. S 3.4.1.4.2 was
" knowingly and intentionally violated by the VEGP Operations Shif t Supervisors with the express knowledge and, in the case of one shift crew, the conen, ence of the operations Manager." In the Demand for Informativ.1, the NRC goes on to add that "(b)ased on the investigative findings, the NRC is concerned that an NRC-licer. sed VEGP manager and NRC-licensed supervisors may have intentionally disregarded Technical Specifications in an attempt to facilitate outage activities." In its Demand for Information, the NRC has specifically requested that the company explain "why Messrs. W. T. Kitchens, J. P. Cash and J. E. Bowles should not be removed from 10 CTR Part 50 and 10 CFR Part 55 licensed activities...."
GPC has carefully reviewed the facts surrounding the October 12-33, 1988 chemical addition evolution as discussed above. As will be discussed below, the facts in this case do not support t, conclusion that any violation of Tech. Specs. that may have occurred was a " willful" violation as that term is used in the Atomic Energy Act and by the NRC. Aoditionally, in accordance with the NRC's Enforcement Policy (10 C.T.R. Part 2, Appendix C), the actions of the individuals in question in this casa do not warrant enforcement sanctions directly affecting either their licenses or their continued emplopent in Part 50 and Part 55 licensed activities. Before addressing the npecific f acts as they pertain to each of the individual operators whose actions have been questioned, and before responding to the NRC's specific request in the Demand for Information, a brief review o the standard of " willfulness" is warranted. .Moreover, we briefly outline, as we understand it, NRC's policy regarding tha extraoruinary measure of imposing enforcement sanctions directly against individuals employed at licensed facilities such as Vogtle. These standards and 10
l guidalin:s will allcw us to rovicv tho fcets in oppropriato } perspective and respond to the Demand for Information.
- a. The " Willfulness" Standard.
- Chapter 18 of the Atomic Energy Act of 1954, as amended (the "1954 Act"), specifies various criminal penalties for willful violations of the statute and regulations or orders of the NRC.
42 U.S.C. $$ 2271-2284. While the term " willful" is not defined in the 1954 Act, the statute's 1cgislative history suggests that a very high standard was intended. The Conference Report accompanying the 1980 amendment of Section 223 of the 1954 Act explains that the " knowing and willful" intent required for a violation of that particular section is a "high standard for state of sind." H.R. Conf. Rep. No. 1070, 96th Cong., 2d Sess., 30 (1980), 2274. reprinted ID 1980 U.S. Code Cong. & Admin. News 2260, The NRC's interpretation of the word " willful" is set forth in the Enforcement Policy. Section III of the Enforcement Policy reads, in pertinent part, as follows: The term " willfulness" as used here embraces a spectrum of violations ranging from deliberate intent to violate or falsify to and including careless disregard for requirements. W111 fulness does not include acts which do not rise to the level of carelers disregard, sigt, inadvertent clerical errors in a document suoaitted to the NRC. 10 C.F.R. Part 2, Appendix C, 5 III. Elsewhere 1.1 Section III, the NRC states that " indications" of willfulness include
" careless disregard of requirements" and " deception." 14 Final.ly, Section V.E. of the Policy $tatement describes carelesk disregard as involving "more than mere negligence."
What this means is that willful violations, for purposes of HRC enforcement actions, require a particular state of mind that goes beyond those instances in which actions are taken knowingly (that is, in this case, more than knowledge that the RMWST valves had been or were to be opened). A willful violation of NRC requirements must involve an additional element of the actor's mental state, either deliberate intent to violate or, at a minimum, careless disrecard for agency requirements. Moreover, l l careless disregard is something more than mere negligence (e.g., more than simply unreasonable logic under the circumstances) . l The logical inference resulting from Appendix C is that if a l licensee or individual operator in good f aith considers and attempta to comply with HRC requirements, he or she will not be deemed to have acted with either deliberate intent to violate or 11
i coroless disrcgcrd fCr rcgulaticns and, tgprofcro, will not be
-held accountable for a willful violation rederal and NRC case law, in defining " willfulness" and *
" careless disregard," similarly indicate that a willful vic.lation cannot result if an individual or licensee had considered NRC's requirements and reached a conclusion, even if incorrect, that the actions in gaestions would not violate relevant statutory or regulatory provisions. The existence of a reasoned justification defeats a-charge of willfulness, despite the fact that a particular action was taken, knowingly and intentionally, that
,was ultimately found to violate NRC requirements.
In Wranolor Laboratorleg, LBp-89-39, 30 NRC 74 6 (1989) , the Board ruled that the licensee's failures were not evidence of careless disregard of NRC regulations or of willful intent to violate NRC requirements. 30 NRC at 780. It did so because the licensee made " serious albeit defective" ef forts to comply with NRC regulations. Id. For instance, ths licensee's decision not to report events, as required, to the NRC was based on " multiple incorrect assessments and misapprehension of his regulatory obligations." Id. Nevertheless, the Board found that reasons credible to the licensee existed for not complying with NRC requirements. Even though these reasons were factually incorrect, the Board held that they prevented a conclucion that there was a willful violation of NRC requirements or careless disregard of regulations. Another NRC decision. underscores the conclusion that a violation (assuming one occurred) is not " willful" if there was a reasoned contemporaneous justification for the action taken -- even if the basis for that justification is later found to be factually incorrect. ERA Reich Geo-Physical. Inc ._ , ALJ-8 5 -1, 22 NRC 941 (1985). The administrative law judge in that case examined the factual basis for each of six alleged willful violations. Ultimately, he determined that two of the six violations did not rise to the level of careless disregard and, therefore, were not " willful" in nature. In both instances, the rationale supporting this conclusion was that, because the licensee had a reasonable basis for believing it was not violating NRC requirements, it could not be charged with careless disregard or, concomitantly, a willful violation. Id. at 954, 957-58. II GPC observes that even if the licensed operator acted negligently (i.e., contrary to what a reasonable person would have done under similar circumstances) in attempting to comply, the operator's action will not constitute a willful violation, absent gross negligence or recklessness. In other words, a bona fide attempt to comply with requirements defeats a finding of L " intentional" misconduct or " careless disregard" for regulations. 12 i l l l
) The Supreme Court has also, on several occasions, addressed the topic of willful violations. In doing so, it has consistently held that the word "wilitula is generally understood
- to refer to conduct that is not merely negligent. Itgt, tiqLAughlin v. Richland Shng_C21, 486 U.S. 128, 108 S. Ct. 1677, 1681 (1988); United States V. Murdock, 290 U.S. 389, 54 S. -
Ct. 223, 225 (1933) (" knowing, t]he wordor(willful) oftan denotes an act. which is intentional, or[ voluntary, as distinguished from accidental"). " Willfully" means purposely or obstinately and is designed to describe the attitude of a flicensee , who, having a free will or choice, either dntentiona)lly disregards the statute or is plainly inditferent to its requirements. Alakana Pover co. v. Federal EnergLEeaulatory comm62, 584 P.2d 750, 752 (5th Cir. If/78) (quotin St. Louis & S.F. RV. _ v. Unitgji States, 169 T. 69, 71 characterize an action (8th Cir. g 1909)). It is a term employed to that is done without grounds for believing that it is lawful. liurdock, 54 S. Ct. at 225. Furthermore the Court has held that if one acts reasonably, or gymn unreason, AhlY (but, but recklessly), in determining his legal obligations, he cannot be charged with a willful violation. McLauchlin, 108 S. Ct. at 1682 and n. 13. Based on this precedent, and consistent with the undorlying f acts, the company concludes that Messrs. cash, Bowles and Kitchens clearly should not be found to have committed either an intentional violation of NRC requirements or to have acted with careless disregard for those requirements. With respect to Messrs. Cash and Bowles, as will be discussed further below, these two individuals never made a conscious decision thet their actions would or would not violate Tdch. Specs. Rather, apparently due to insufficient training and guidance, they were unaware that the plant was, or might have been, in the Loops Not Filled condition and assumed that Tech. Spec. S 3. 4.1. 4. 2 51151 npj; apyly. While, in retrospect, this may have been an error, their actions did not constitute " careless disregard" of the Tech. Specs., as those terms have been construed by the NRC and the courts. In the case of Mr. Kitchens, he also did not intentionally violate or carelessly disregard the Tech. Specs. On the contrary, he made the conservative assumption that Tech. Spec. $ 3.4.1.4.2 applied and made a reasonable, good faith decision that the planned evolution would be in compliance therewith. His actions did not amount to a villful violation.
- b. Enforcement Actions Involving Individuals.
The NRc, in its Enforcement Policy, has previously recognized that enforcement actions directly impacting individuals are "significant personnel actions, which will (or 13 l
,,_m_____ _ _ _ _ ._ -- - - - - - - - - - - - - - - - - - - " - - - - - - ' ~ - - - - - - - - ' - ' ~ - - ' - ' '
sh:uld be) closoly contro11cd end judicioucly cpplied.o to C.F.R. Part 2, Appendix C, Section V.E. As previously noted, the Company does not believe that thib extreme form of sanction is warranted or supportable in this instance. , Section V.E. of the Enfor:oment Policy specifies that "(a)n enforcement action will normally be taken (against an individual) only when there is little doubt that the individual fully ur.derstood, or should have understood, his or her responsibility; knew, or should have known, the required actions; and knowingly, or with careless disregard (i.e. , with more than mere negligence) f ailed to take actipps which have actual or potential safety significance." Id. Even apart from the element that there be actual or potentisl safety significance, the Enforcement Policy sets a very high threshold of factual proof for individual enforcement actions. This high standard has not been met in the present case, as will be discussed below. The high stann.rd for enforcement actions involving individuals also inherently recognizes that it is often difficult to properly attribute fault to an individual acting within a licensed environment which contemplates the application of judgment. Ir. i.he long tern, the effect of an enforcement regime which punishes judgments made in good faith could lead to diminished morale and difficulty in recruiting licensed personnel. This would ultimately reduce assurance of public health and safety. The Company believes that these general perspectives should also be kept in mind when considering the events at VEGP on October 12-13, 1988.
- 2. Messrs. Bowles and Cash Lacked the Necessary State-of-Mind Requisite to a Willful Violation.
The single most important fact respecting the activities of Messrs. Bowles and Cash is that they were unaware of the applicability of Tech. Spec. S 3.4.1.4.2 when chemicals were added }p the Chemical Mixing Tank at 4:00 a.m. CT on their Night Shift. It was only when personnel from the following Day Shift 12 Similarly, the examples provided in Enforcement policy Section V.E. of cases where individual enforcement might be appropriata consistently involve either " willfulness a or some gross disregard for responsibilities. The latter include instances of inattention to duty or falsification of records, not relevant to the present facts. 33 The NRC June 3, 1991 Demand for Information sent to Mr. Cash suggests that he was involved in chemical addition activities on "four occasions." It is important to make clear that neither Mr. Cash nor Mr. Bowles were involved in the three chemical additions made by the Day Shifts of October 12 and 13, 14 l a_-- -- - - - , - - - . -- - - - - - - - - - . - - - - - - - - _ . . - - - - - - . - - - - - - - - _ - - - - _ _- --, '
brcught th3 matter to thoir ettcnticn (in tho 5:07 to 5:33 a.o. I CT time frase), that Messrs. Cash and Bowles recognized the possible applicability of the Tech. Spec. The only relevant overt act taken by either of them af ter this recognition was the
- 1 ate log entry, which is not in question here.
Messrs. Cash and Bowles lacked the state-of-mind requisite to a finding that they either intentionally violated or carelessly disregarded Tech. Specs. They could not have been carelessly disregarding Tech. Spec. $ 3.4.1.4.2 when they were unaware of its applicability. That is, clearly they did not understand that they had responsibilities regarding Tech. Spec. $ 3.4.1.4.2 and, therefore, they did not know, or even consider, the required actions. They were not " plainly indifferent" to the Tech. Spec. Eta Alabama Power Co., 584 F.2d at 752. In fact, given that they were proceeding by procedure to implement a pre-planned evolution, and based on their training and guidance at the time, it cannot be said that they should have recognized the applicability of the Tech. Spac. The primary factor in Mr. Cash's and Mr. Bowles' lack of recognition was inadequato training a Loops Not Filled condition of Mode 5.pp guidance respecting In October 1988, thethe operators received little or no trainino on the boron dilution accident with the RCS in the Loops Ne' tilled condition. Consequently, many VEGP operators understood the Loops Not Filled condition to mean the Rcs water leve? when the RCS had been drained dovn to below the " top of the not leg," or, in the case of Mr. Cash, below the " top of the loops." However, when primary water was displaced from the steam generator tubes (which, ironically, causes the RCS vater level to rise), the unit was technically in the Loors Not Filled condition according to the 1988, which were the occasions when chemicals were actually injected into the RCS. Messrs. Bowles and Cash only supervised the addition of chemicals to the Chemical Mixing Tank on one occasion relevant to this matter, i.e. , the Night Shif t of October 11-12, 1988. I' significantly, the VEGP operators' general lack of serstanding of the " Loops Not Filled" and " Loops Filled" k .1ditions was observed by the NRC in 1989 when it reviewed a VEGP LER associated with a February 1989 VEGP Unit 2 violation of Tech. Spec. $ 3.4.1.4.2. Ett NRC Inspection Report Hos. 50-424/89-14 and 50-425/89-15, dated June 15, 1989, attached as Exhibit 15, at p. 26. That violation occurred when the Unit 2 operators, who believed that filling the RCS above the loops .up to the reactor vessel flange level constituted " Loops Filled," released a clearance from the RMWST discharge valves, opened the valves and left them open for four hours with the RCS in the Loops Not Filled condition. 15
han-curr:nt g itinghwam analysis. Eg.g diccusolon in SGetion 21 ! 1 9 a . "'
.1 1980 <h. , was only rudimentary guidance available co e . - , >
n the Control Room respecting RCS water levels
- s. at rc .cories. At the tima of the IR1 outage, plant
.. m mr '~
~ t h wordance with their training -- attuned to 4-or. ' 7ersus :., oops Not Fillod) and associttad at . Fw vetor .evels due to industry evento and f ~ h- x ,ca a . Ths op.tra ors used the term "Mid-
- . n r str' o to the a mdition during Cold Shutdown tv, - 1 3 N el had b n. drained down to a level at gr agw .e an .sve t.he center 1ine of the RCS hot-leg piping, L 1,c. 188' minimus RCS water levol during the RCS drain-down pocec. . at, A L., Exhibit 6, 5 D4. 2.13.a (ll) , at p. 30.
The opere, vs dr ' not ger. orally aquate Mid-loop with a specific 1-nhution ud sera operators equacy it with Loops Not Filled, inclucAng aossrs. Cash and Bowles When Messrs. Cash and Bowles came on rtif t on October 11, 1980, the: Day Shif t had dready completed Sect. ion D4.2.14 of VEGP
.1' roc < dure 12006-C, Rave No. 9 (Exhibit 6), which requires that
" As descr _ bed more fully in Sec.cion III.E, herein, today there is a cont in trable amount of training provided to the VEGP operators concerning Tech. Qyes requirements, includ.8.ng the Loops Not Tilled condition. Also, GPC has taken action sinco Oct her 1988 to clearly defina the Loops Not Fil3ed condition.
On teh uary 22, 1.989, the Operations Manager, Mr. W. F, Kitchens prepared a "Tecn. Spec. Interpretation, addressing the ina ;ter,. attached as1 Exhibit 16. That interpretation was sued in responta to the February 1989 VEGP Unit 2 violatio. described in footnote 14 above. _ Further clarification was developed on March 3C, 1990 based on data obtained from Westinghouse. 3g.3 T8 x l Spec. $ 3.4.1.4 Interpretation, dated March 30, 19 90, atte ~.b " ; as Exhibit 17.
" Since 1988, guidance available- in the control Room to assist the operators -during RCS drain-down .and Mid-loop activities has ovolved into en elaborate sarie s of drawings and charts. For a full discussion of the evolutir,n of VEGP operator guidance concerning RCS water levels at reduced RCS inventories, see Attachment 2. GPC observes that pocential confusion of
' operators vith respect to Tech. Specs. applicable to outage conditions and modes has recently been identified as an Industry-related issue. S_qa NRC Memorandum'from Gary Holahan, dated May 16, .1L991, and certain of his comments to the NRC Commissioners on rune 1?, 1991, both attached as composite Exhibit 18. In the sase of VEGP operators, the Mid-loop condition had received emphasis in training to a far greater extent than thc. Loops Not . Filled _contition. 16 l i
+-
1 the RMWST dischargo valvan ba cloacd, locked and taggGd. II GPC is of the opinion that completion of Section D4.2.14 during the prior Day shif t by Mr. Gasser is likely the principal reason why Mr. Casser was the one who later raised a question concerning the ' Tech. Spec. Another institutional factor contributing to this incident was inadequate review of procedures during outage planning. A detailed description of the planning process for the 1R1 outage relevant to the chemical addition evolution is contained in Section III.D, herein. In summary, the procedures which Messrs. Bowles and cash were following failed to identify any conflict with Tech. Spec. $ 3.4.1.4.2 because, to the VEGP personnel who prepared those procedures as well as to others participating in the outage planning process, it was not clear that a conflict existed. Only one procedure (49006-C, Rev. No. 0) directly addressed at which point during the RCS drain-down process ("Mid-loop") the chemical cleaning was to be performed. That procedure was prepared and approved by the Health Physics and Chemistry Department and was not reviewed by the operations, or any other, Department. The procedure addressing the cpecific valve manipulations required for the chemical addition (13007-1, Rev. No. 2) failed to specify at what RCS water level the procedure was permitted to be performed, although the procedure appearsyo contemplate that it would be performed with Loops Filled. Based on the foregoing, when it came time to perform the chemical addition evolution on their shift, Messrs. Cash and Bowles had no reason to suspect that there was any conflict between the Tech. Spec. and the pre planned and scheduled chemical cleaning. They were performing the evolution pursuant to rpproved procedures and simply did not spot the problem before the shift thrnover, when the Day Shift personnel raised the issue. Additionally, Messrs. Cash and Bowles were essisted by, and had delegated the activity to, a Support Shif t Supervisor, Mr. Ryan, who apprr ec i 9 Functional Test Form allowing temporary lifting ( the clearance on three of the RMWST discharge valves (Noa. 476, 177 and 181), and who supervised the II As discussed in the FRC Jrne 3, 1991 Demand for l Information, Section D4.2.14 is included in the procedure l pursuant to Tech. Spec. S 3. 4.1. 4. 2, although the water level associated with that step (about 219 feet) was much higher than the " top of the hot leg," the level most operators equated with Loops Not Filled at the time. I' The procedure did not expressly provide for opening Valve 177, which is normally open during Loops Filled. In October 1988, this valve was opened pursuant to the Functional Test procedures. 17 l
ll } > valvo_canipulctieno pursucnt to the cpplicablo proceduro (13007-1, Rev. No. 2). Even Mr. Ryan, a licensed Senior Reactor operator, who was in the best position to spot any potential conflict, dia not- recognize that there was a conflict with the Tech. Spec. Furthermore, to GPC's knowledge, no one else on that shif t spotted the conflict or raised a question concerning the Tech. Spec. Moreover, considering the training and procedures-provided at the time, it cannot even be said that Messrs. Bowles and Cash should. have known that the. Tech. Spec. was applicable. Therefore, no willful violation occurred.
- 3. Mr. Kitchens' Interpretation of Tech. Spec. S 3.4.1.4.2 was Reasonable and in Good Faith.
Mr. Kitchens did not willfully violate the Tech. Specs. 3-because his actions at the time do not evidence that he either (1) intended to violate the Tech. Specs. , or (2) proceeded in careless disregard of the Tech. Spec, requirements. on the contrary, based -on a review of the facts, GPC finds that he conducted a reasonable inquiry and proceeded in good faith under the circumstances. The company believes that the conclusion Mr. Kitchens reached at the time-was reasonal7e, even if incorrect based on present-day NRC guidance. _However, even if the NRC finds that Mr. Kitchens violated the Tech. Spec. , it should conc;ade that his actions did not rise to the level ok a "willfula violation c2 Tech. - Sr ecs, as that term has been construed by the FRC and others. Enforcement action against Mr. Kitchens individually is particularly inappropriate when, in accordance with the Enforcement Policy, such action is to be taken only when the NRC finds "little doubt" that he " knew, or
- should have known," that his actions violated the Tech. Spec.
Mr. . Kitchens _' review was _ conducted carefully and openly. When he was first approached by Mr. Hopkins, Mr. Kitchens placed the chemical cleaning evolution on hold so that he could take the time to perform a careful review of the Tech. Spec. and its bases. The delay in the scheduled evolution was raised during the outage status meeting that morning. He reviewed Tech. Spec. S 3.4_1.4.2 and its Tech. Spec. Bases and he reviewed the FSAR. Before reaching a conclusion, he also consulted with Mr. Hopkins L . and with his Deputy Manager of o
.axperienced operations manager. Following perations, Mr.
his Marsh, a more decision, he also discussed the matter with the VEGP NSAC Manager, Mr. swartzwelder, who was also an experienced senior reactor
- operator.
Mr. Kitchens knew that voluntary entry into Tech. Spec. LCOs L was a common practice in the industry and at VEGP, particularly for maintenanc? purpose.c, provided that there was compliance with tb n -tion Stahmentiin accordance with Tech. Spec. SS 3.0.1 and 3.0 2. Such voluntary entries are clearly permitted in the case of wa Spec. Action Statements which provide a specific time 16 l-
. __ A
p:riod, such cc in houro, baforo cortcin actions cro requircd to be performed. However, vo)untary entry into Tech. Spec. Action Statements which require immediate action was unusual and was not an established practice. Mr. Kitchens was aware of no guidance
- document frca the NRC that prohi which required immediate action. ped In voluntary entry into anMr.
these circumstances, LCO Kitchens, who was the highest-ranking GPC employee holding a VEGP Senior Reactor Operator's license, proceeded to determine the intent of Tech. Spec. 5 3 4.1.4.2 so he could make an informed deaision.
- The term "immediate" was not defined in the Tech. Specs.
Mr. Kitchens understood it to mean "without undue delay" under the circumstances, although not necessarily the very next action performed. Furthermore, Mr. Kitchens' experience was that an LCO requiring *immediate" action inherently allowed some finite time for action. Mr. Kitchens recalls that, in June 1987, VEGP experienced an entry into an LCO requiring immediate action concerning the Digital Rod Position Indication ("DRPI") system and the NRC Resident Inspector at the time, Mr. Roy Schepens, then concurred with GPC's decision to first determine the cause of the DRPI f ailure before completing pursuant to the LCO Action Statement.yheTherefore, immediateMr.action Kitchens had reason to equate an LCo requiring an immediate action with an LCo providing an express time period. Prior to deciding that entry into the LCO was allowed, Mr. Kitchens also specifically reviewed the Tech. Spec. Bases and other documents to assure that the action would comply with the safety underpinningt of the Tech. Spec. The Bases of Tech. Spec. 5 3.4.1.4.2 indicated to Mr. Kitchens that the purpose of that Tech. Spec. was to prevent an uncontrolled boron dilution of the RCS. Mr. Kitchens and Mr. Hopkins believed that the intent of the Tech. Spec. (i.e., an uncontrolled boron dilution event)
" No such guidance from the NRC existed. As discussed in detail in the Section III.B.5 herein, the Company believes that reasonable minds can differ as to whather voluntary entry into Tech. Spec. 5 3.4.1.4.2 was permissinle in october 1988.
l 20 Following thht event, GPC revised the relevant VEGP response procedure (17010-1) to direct the operators to place the ' DRP1 systen in the " Data A" channel or the " Data B" channel before taking the Tech. Spec. "immediate" action to manually trip the reactor. The NRC has indicated its concurrence with that revised procedure by virtue of the fact that it closed its review of the LER associated with the event based on the procedure revision. Les e Inspection Report No. 50-424/87-60, dated December 17, 1987, Report Details S 4.b(3) (p), at p.12, attached as Exhibit 19. 19 l l
W:uld be met if tho ep:ning of tho volvoc was p rferced ungpr strict administrative controls and with clear time limits. Mr. Kitchens reviewed FSAR $ 15.4.6 and concluded that the ' boron dilution accident had been analyzed for the Loops Not Filled condition of Mode 5 and that 15 minutes was available for the operator to respond. That conclusion is understandable given that portions of FSAR S 15.4.6, as it existed in October 3988, indicated that an analysis of Mode 5 had been performed and that adequate operator response time was avai1+ble. (At that time, FSAR $ 15.4.6 was a confusing patchwork of Amendment 17 (July 1985), which indicated that Mode 5, including the Loops Not Filled condition, was analyzed and that adequate operator response time was available without administrative controls, and Amendment 30 (December 1986), which attempted to describe that, as in the case of Mode 6, administrative controls were necessary to lock the RMWST discharge valves closed in the Loops Not Filled condition of Mode 5. A more detailed discussion of the evolution of FSAR S 15.4.6, as well as the NRC Safety Evaluation Report 5 15.4.6, is included as Attachment 1.) Mr. Kitchens also reviewed FSAR S 9.3.4.1.2.5.14 which stated that one purpose of the Chemical Mixing Tank was to facilitate the addition of chemicals to " clean-up" the RCS durina refuelina shutdowns. A copy of the October 1988 version of FSAR S 9.3.4.1.2.5.14 is attached as Exhibit 20. Mr. Kitchens and Mr. Hopkins spoke to Mr. Marsh, who was a more experienced operations manager than either of them. When they questioned him albut the term "immediate" an used in Tech. Spec. Action Statemer.ts, they understood him to say that the term hadbeeninterpretedatanotherfacility(believedtobepan Onofre) to mean that the operator had 15 minutes to act.2 This 21 The Company notes that NRC Generic Letter 91-08, " Removal of Component Lists from Technical Specifications," dated May 6, 1991, identifies acceptable administrative controls for opening i locked or sealed closed contair. ment isolation valves which are consistent with the administrative controls utilized during the VEGP chemical addition evolution on October 12-13, 1988. 22 Mr. Marsh has informed GPC that he may have addressed the l "immediate" time duration associated with " operator action" compensatory for automatic action, as contrasted with "immediate" as used in Tech. Spec. S 3. 4.1. 4. 2, Mr. Marsh has no vivid L recollection of the advice he gave, but has the highest regard for the integrity of Messrs. Hopkins and Kitchens and does not question their recollections. Further, Mr. Marsh is presently of the opinion that (1) an interpretation of Tech. Spec. S 3.4.1.4.2 is a grey area, (2) no clear NRC guidance has been provided relative to the "immediate" issue, and (3) manipulation of the 1 l 20 i
=c_ furthor ^cenfien:d Mr. Kitchsno' conclusion that- the Lco allowcd a
- time for_ action,' and thus could be entered voluntarily.
Mr. Kitchens also performed a simple calculation and
- determined that, based on an RCS concentration of 740-ppa and the RMWST= discharge valves' flow rate of 3.5 gpa- (specified in the - !
FSAR),
'for there would the; planned be an-insignificant amount of beron dilution addition. Thus,-Mr. Kitchens concluded not only
.that the Tech. Spec. permitted administrative 1y controlled additions timpact on of safety hydrogen would peroxidgj occur -but also that.no deleterious The reasonableness of Mr. Kitchens' interpretation is demonstrated: by the-concurrence of the'other licensed operators sinvolved.in.the event and'by findings of those who later reviewed thelevent. At the_ time of the event the licensed operators who-were involved in the evolution concur, red with the-interpretation
-and-proceeded accordingly. No one on-shift raised a~ concern with entry into Tech. Spec.; 5_3.4.1.4.2. Following the evolution, Mr.
- Kitchens and Mr.- Hopkins recall that Mr. Swartzwalder, the NSAC Manager,- indicated his concurrence with .the interpretation. When the evolution was,later reviewed by_the corporate office, Mr.
? Jack: Stringfellow, (a licensing engineer,- concluded that- the Tech.
Spec._he.d not been1 violated. _Upon further-review by the Plant - Review, Board, all voting members-or alternates present_ concluded
- and voted that1the evolution did not violate the Tech. - Specs.
Additionally,.Mr. George Bockhold, Jr., the plant General Manager at the time, also concurred with .Mr. Kitchens' interpretation. Furthermore, at the time Mr.: Kitchens rendered his interpretation, he was'not motivated by-schedular or economic '
; benefits flowing'from the_ completion of the chemical addition
; evolution.' - Whenzhe vast faced .with the decision of whether the -
scheduled chemical addition evolution was -permitted _ by Tech. o
- Specs.,ihisjoptions were:to either proceed with or: cancel the scheduled evolution. 'His decision to proceed resulted in an economic cost
.criticalJpath to GPC due;to its effect-of' lengthening the schedule. There: vas, however, a safety benefit-whichcaccrued to GPCL and .VEGP. outage workers in that the chemical addition was designed.to,Eand did'in fact, reduce the L
RMWST discharge ' valves [in Mode 5 with Loops Not tFilled would not
.violateTthe; Tech. Spec., although-it is."not a good idea."
1 23 Mr. Kitchens' calculation was not-intended as n' substitute for the FSAR $ _15.4.6 analysis' of the boron dilution accident.
-Indeed,_he had concluded that such an analysis already existed-for.the: Loops 1 Not Filled ' condition of Mode 5. His calculatior, wass a: prudent operator' check intended to ensure that-there would
~te a negligible effect on boron concentration, and, therefore, reactor _ criticality.
4 21 1:-
cecupational radiation exposuro which tho outago workoro would have otherwise received without the evolution. A more detailed discussion of the costs and benefits flowing from the chemical
-addition evolution is included in Attachnent 3.
- B sed on' the foregoing, the circumstances surrounding the October'12-13, 1988 chemical addition evolution establish. that Mr. Kitchens made a good f aith, reasonable attempt to determine, understand and comply with, NRC requirements. The facts do not support a finding that Mr. Kitchens " willfully" violated Tech.
Spec. $ 3.4.1.4.2, as that term has been construed by the NRC and the courts. Rather, the facts evidence that there is, at a minimum, substantial doubt that he " knew or should have known" that his interpretation violated the Tech. Spec. His experience told him-that his interpretation was reasonable and later reviews confirmed his interpretation. Indeed, as will be discussed later herein, the Company believes that reasonable minds can differ as I to whether the voluntary entry into Tech. Spec. $ 3.4.1.4.2 was l permissible in 1988. Furthermore, there was no scuedular or economic motivation for Mr. Kitchens to make the decision he made.~ Therefore, enforcement action against Mr. Kitchens individually is inappropriate under these circumstances .ss the .
' Enforcement Folicy threshold that there be "little doubt th'.t the individual . . . knew, or shem1.4 have known, the required actions" is clearly not met.
- 4. The Chemical Addition Evolution Lacked Safety Significance.
As s cussed above, the Enforcement Policy (at Section V.E.) also prov. 3s that enforcement actions involving individuals should only be taken where the alleged improper actions have actual or potential safety significancs. In the present case, such safety significance is minimal. (This is, of course, also a f actor for the NRC to- keep in mind when considering any enforcement action against the Company regarding these events.) On November 14, 1989, Westinghouse complated an analysis of GPC's proposed Tech. Spec. change to allow opening of the RMWST valves for short periods of time during_ Modes Sb and 6 for o purposes of chemical addition. Egg Westinghouse letter, J.L. Tain to C.K. McCoy, dated November 14, 1989 (with attached safety Evaluation No. SECL 89-943), attached as Exhibit 21. The l- analysic concludes that, while the evolution was not then analyzed in FSAR $ 15.4.6, the proposed change (1) did not involve an "unreviewed safety question." as that term is defined in 10 C.F.R. $ 50.59, and (2) met the NRC GRP S 15.J . w criteria since a minimum of 15 minutes (from receipt of the Figh. flux at shutdown alarm} for operator action was availab.e to mitigate an accident during Mode Sb and 30 mir.utes was available during Mode 6. Een Exhibit 21 at p. 1. The Westinghouse analysis also concluded that chemical addition during Meies Sb and f did not 22 l l
violato the plant's licensing bacio acceptanco critoria. Egg Exhibit 21 at p. 2. Not only does the Westinghouse analysis : support the conclusion that the chemical addition evolution was l not rnportable under the second and third criteria of 10 C.F.R. $ ' 50.73(a)(2)(ii), but it clearly demonstrates that the evolution lacked safety significance in terms of the boron dilution accident. On February 20, 1990, the NRC granted a GPC November 21, 1989 application to amend the VEGP Tech. Specs, to allow opening of_ the RMWST discharge valves for short periods of time during Modes 5b and 6 to add chemicals. Esa Issuance of Amendment No. 28 to Facility Operating License NPF-68 and Amendment No. 9 to Facility Operating License NPF Vogtle Electric Generating Plant, Units 1 and 2 (TACs 75320/75321), dated-February 20, 1990, attached as Exhibit 22. The NRC Safety Evaluation attached to the license amendments concludes that GPC's November 21, 1989 submittal used conservative assumptions, that the NRC Standard Review Plan acce z tance criteria had been met or exceeded, and that the pronoseo Tech. Spec. amendment will not have any adverse affect on safety. Egg Exhibit 22, Safety Evaluation at p. 2. On August 16, 1991, Westinghouse completed an analysis, at the request of GPC, of the actual effect of the chemical addition evolution given the boron concentration of the RCS at_the times of the additions on October 12 and 13, 1988. The Westinghouse analysis concludes that, given a boron concentration of 774 ppa at 7:00 a.m. CT on October 12, 1988, when the RMWST discharge Valve 176, 177 and 181 were opened, over 48 hours of flow through those volves would have been required before reaching criticality (nearly nine hours of flow from the initiation of the high flux ! at shutdown alarm would have been necessary) . With respect to i the chemical additions performed on October 13, 1988, approximately twice those times (i.e.', approximately 96 hours and 18 hours, respcetively) would have been required before reaching criticality. A copy of the Westinghouse analysis is attached as Exhibit 23. Considering the 15 minute acceptance criteria from NRC SRP S 15.4.6, the Westinghouse analysis demonstrates that there was minimal safety significance associated with the chemical addition . evolution. Furthermore, even if the operators opening the valves had allowed the flow to run continuously through the valves uninterrupted, within 24 hours a shutdown margin calculation , would have been performed and compared to chenistry samples of L the RCS- taken, and the dilution of boron concentration would have been discovered, the source identified and the valves closed. I l 23
$. Reaconablo Hindo can Dif for ao to Whether, in 1988, voluntary Entry into the Tech. Spec. S 3 . 4 .1. 4 . 2 LCo was Permissible. ,
The NRC's June 3, 1991 Notice of Enforcement Conference and Demand for Information to GPC suggests that the wording of VEGP Tech. Spac. S 3.4.1.4.2 "is exceptionally cicar and not open to any interpretation that would allow the intentional manipulation to the open position of the (RMWST discharge) valves with the plant in the specified condition." The company vigorously disagrees with this statement based on the following facts which demonstrate that the Tech. Spec. is not exceptionally clear. Rather, the issue of voluntary entry into Tech. Spec. LCos, and specifically those Tech. Spec. LCos requiring immediate action, is an evolving industry issue for which NRC guidance was lacking in 1988. In this context, the issue before Mr. Kitchens was one where reasonable minds could' curtainly dif fer. It has been suggested that the use of the words "shall be closed and secured in position" in the LCO for Tech. Spec. S 3.4.1.4.2 may have led the NRC to its tentative conclusion that the Tech. Spec. is " exceptionally clear" so as to prohibit the voluntary entrance inte the Leo. The Company believen it is unreasonable to draw such a conclusion from the LCO wording in light of both the historical context and the industry experience in applying other Tech. Specs. A host of Tech. Spec. LCOs use similar "shall" wording and yet the NRC has expressly countenanced as permissible the voluntary entry into a number of those LCOs. For example, VEGP Tech. Spec. S 3.5.2 states that, during Modes 1, 2 and 3: Two independent Emergency Core Cooling Systems (ECCS) subsystems shall be OPERABLE with each subsystem comprised of: (a) One OPERABLE centrifugal charging pump, (b) One OPERABLE Safety Injection pump, (c) One OPERABLE RHR heat exchanger, (6) One OPERABLE RHR pump, and (e) An OPERABLE flow path. . . (emphasis added). As NRC is well aware, VEGP operators perform PM on the components listed above during Modes 1, 2 and 3. Another example is VEGP Tech. Spec. S 3.6.3 which stetes that, during Modes 1, 2, 3 and 4, "[t]he containment isolation valves shall be OPERADLE" (emphasis added). In this case, as NRC knows, the VEGP ooerato:s open the valves under administrative controls during Modes 1, 2, 3 and 4 to perform maintenance or testing, which, in some cases, renders the valves inoperable. With respect to volontary enny into Tech. Spec. LCOs generally, NRC provided a position in a January 1, 1982 interpretation which stated: 24
The NRC endcrocs Voluntary Entry into tho Acticn Stctoaant Conditions and has structured the [ standard) TS to permit the licensee to exercise judgment viuin the latitude permitted by the Action Statement lainguage in the TS. ' Egg NRC Standard Technical Specification Interpretation, Section 3.0, *W1untary Entry Into Action Statements," dated January 1, 1982; att alig NRC Memorandum from B. K. Grinies to S. E. Bryan, dated June 13, 1979 (both documents are attached as composite Exhibit 24). In December 1990, the NRC notified the Institute of Nuclear Power Operations ("INPO") of a concern it has with licenseas' voluntary entry into Tech. Specs, durisig power operations for purposes of performing preventive maintenance ("PM"). Egg NRC letter from Mr. James H. Sniezek to Mr. Kenneth A. Straha of INPO, dated December 27, 1990, attached as Exhibit 25. This concern had not been addressed in any guidance available co operators prior tc October 1988; moreover, it reflects ths sthte of it.dustry practice as late as December 1990 and the NRC's evolving regulatory position. This perspective is important in assessing the actions of GPC and its operators in 1988. Further guidance regarding voluntary entry into Tech. Spec. Action Statements was only subsequently provided in April 1991 in the NRC Inspection Manual, Part 9900, " Voluntary Entry Into Limiting Conditions For Operation Action Statements To Perform Preventive Maintenance," attached as Exhibit 26. The purpose of this guidance is, "[t)o provide a set of safety principles for guiCng the performance of preventive maint6 nance (PM) at licensed nuclear reactor f acilities when the performance of the PH requires rendering the affected system or equipment inopecable (on-line PM) . " The NRC Staff notes that although these principles primarily apply to PM during power operation, they also apply to PM on equipment that must be operable during shutdown evolutions such as fuel handling or Mid-loop operation. This Inspection Manual interpletation allows intentional entry into an LCo Actior Statement if maintenance is com'leted and operability restored within the time specified in . Action Statement " allowed outage time" ("AoT"). According to NRC, if this criterion is satisfied, "[i)ntentional entry into an action statement of an LCO is not a vdolation of the TS (except in certain cases, such as intentionally creating a loss of function situation or entering LCO 1,0.3)." Sig Exhibit 26 at Section B (emphasis added). Even nis 1991 guidance does not expressly prohibit the voluntary errr/ into LCos with Action Statements requiring immediate action. Also, based on the discussion below concerning the meaning of the term "immediate" as used in the Tech. Specs., one could reasonably conclude that "immediate" is equivalent to an AoT. 25
Th3 NRC-ob0 cry;d in the Inapsetion M0nual that it had not established (official) guidance on taking equipment out of service to perform PM until- 1993. Again, in 1988, the only clear NRC. guidance available to VEGP operators on the question of
- voluntary entry into Tech. Spec. LCws indicated that such entry was permissible provided the Action Statement was followed. The
-NRC had indicated, as early as August 1987, that the voluntary entry into Toch. Spec. 5 3.0.3 is prohibited. San Technical Specification Imprcvement Program Highlights, dated August 1987, attached as Exhibit 27, at p. 2. However, the NRC had not provided any equally clear guidance on an entry such as that considered by Mr.. Kitchens. In light of this silence, the Company considsrs that his good f aith consideration of na intent of 'the Tech. Spec. can only be regarded as reasonable.
A review of the historic development of the use of the term "immediate" in the Tech. Specs. is also enlightening. There has long been a presumption that the term "immediate" aa used in Action Statements inhersntly involves some period of elapsed time. Thus, the difference between a Tech. Spec. Action
-Statement using the term "immediate" and one with an expressed AOT is. not as~ great as the NRC now apparently perceives it to be.
For example, during development of the Westinghouse Standard Technical Specifications ("H-STS") , an ad-hoc committee of utilities (approximately 5 utilitias scheduled to receive the first H-STSs), held discusvions with the NRC in the mid-70's.
- Mr. George Mairston, III, currently GPC's Senior Vice President -
- Nuclecr Operations (then operations Supervisor at Alabama Power Company's Plant Farley), participated in those discussions along with Mr. Charles C. Little, then a project managar for Westinghouse. Both Mr. Hairston and Mr. Little recall- that the definition of the-term "immediate" as used in Action Statements was of concern to the group and the -issue was debated along and hard" with the NRC. Both men remember that-the group recommended to the NRC that the- term "immediate" should be replaced throughout the M-STS with a specific time period of approximately 10 to 20 minutes. "Immediata" was never intended to connote "no time for action" (i.e., no AST). Significantly, Mr. J. M.
McGough, who from 1973 to 1978, conceived, developed and implemented the Standard Tech. Spec. program for the NRC, now recalls those discussions as well. Mr. Little and Mr. McGough
< have provided the Company with written statements concerning those discussions which are attached as composite Exhibit 28.
Mr. McGough recalls that one of the objectives of the Standard Tech. Spec. program was to ensure that operators, faced with a situation on-shif t at 3 : 00 a.m. , had clear and unambiguous l Tech.. Specs. to follow. Toward that end, Mr. McGough recalls, it L was' recognized that the term "immediately" was impossible to L define given the varying degree of severity the Action Statements p were-being required to cover. Therefore, the term "immediately" l 26 I
was rcplaced in occa of tho Stonderd Tcch. Spac. eccticno by a series of time-dependent Action Statements tailored to fit the severity of the particular situations being addressed. This further illustrates that action statements requiring immediat1 ' action are not funde.nentally different from those with ACTS. In 1977, . an internal NRC memcrandum also discussed the meaning of the term "immediate" as used in some Tech. Specs. which required _ immeediate testing of a system upon the failure of its redundant counterpart. ErJa NRC Memorandum from J. H. Sniezek /
-to G. Flore111, data May 20, 1977, attached as Exhibit 29. Mr.
Sniczek advised that a specific time period of four hours could not be generally applied in that case because the term "immediate" could be interpreted differenc.ly depending upon the "cause of the system failure" (i.e. , the " urgency to conduct the test"). Ha concluf.ed -by stating that "for the present, the NRC will rely on the technical judgment of the NRC inspection staff on a case-by-case basis." Mr. Kitchens' actions in 1988 to ansess the intent of Tech. -Spec. $ 3.4.1.4.2 were not
-inconsistent with this conclusion.
Since October 1988, the NRC and industry regesentatives have discussed proposed Standard Tech. Specs. in connection with ths MERITS program. Some of those discussions have focused on the unaning of the term "immediately" and proposals have been made by the Westinghouse Owners Group to further replace the word "immediately" with a specific period of time. Two examples, which are particularly relevant to this enforcement -action, are discussed below. The proposed P.ERITS program Standard Tech. Spec. concerning boron concentration during refueling operations specifies the following LCO: , The boron concentration of all filled portions of the Reactor Coolant System, the refueling canal, and the refueling cavity shall be maintained within the limit provided in the CORE OPERATING LIMITS REPORT. The Action Statement of this Tech. Spec. provides-that with the boron concentration outside the limit specified in the LCO, the following " Required Actions" are to be taken within the specified
" Completion-Times":
' REQUIRED ACTION COMPLETION TIME A.1 Suroend CORE ALTERATIONS -15 minutes and positive reactivity additions.
AHQ 27
A.2.1 Initiato boration to 15 ninutco restore concuntration.
&HD '
A.2.2 continue action as Until boron required in A.2.1. concentration
, is restored The corresponding VEGP Tech. Spec. provides that when the specified boron concentration is not met, "immediately suspend.
all operations involving CURE ALTERATIONS or positive reactivity changes and initiate and continue boration at greater than or equal to ...." Egg VEGP Tech. Spec. S. 3.9.1 (emphasis added) . Therefore, industry representatives have recognized that the tern "immediately" as used in VEGP Tech. Spec. 5 3.9.1 caa and should be replaced with a specific time inter /21, i. this case, 15 minutes. Another particularly relevant example from the MERITS program proposals is the Tech. Spec. concerning Unborated Water source Isolation valve positions during refueling operations. The MERITS Tech. Spec. LCO provides: Tach valve used to isolate unborated water sources shall be secured in the closed position. NOTE: Valves may be r.pened during planned boron dilution or make ..p activities. The Action Statement provides the following Required Actions and Completion Times when one or more valves are not secured in the closed position: REQUIRED ACTION COMPLETION TIME A.1 Suspend CORE ALTERATIONS 15 minutes b8D A.2 Secure valve in closed 1 hour position. I bHD A.3 Perform SR 3.8.1.1. 4 hours L In contrast, the corresponding VEGP Tech. Spec, provides that when the unborated water source isolation valves are not closed and secured in position during refueling operations, "immediately 28
clcco cnd cccuro jp po31 tion." ERA VEGP Tcch. Sp c. $ 3.9.1 (esphasis added). The latest draft of the MERITS Standard Tech. Specs. ' contains the following explanation of the term "immediately" when used as a Completion Time: In some canes "Immodiately" is used as a Completion Time. In this case, the Required Action should be pursued without delay and in a cont?colled manner. As stated earlier, the VEGP Tech. Specs, do not contain a definition of the ters "immediately." The proposed MERITS definition of the term "immediately" is inconsistent with the experiance at VEGP concerning the DRPI Tech. Spec. which was expressly reviewed and appi veed by the NRC Resident Inspector at the time. Egg footnote 20 and accompanying text, above. Further, the above construction appears to conflict with the Tech. Specs. of a number of 1970s vintage operating reactors which already contain a definition of the term "immediate." GPC's Plant Hatch Unit 1 is one of those plante. The Hatch 1 Tech. Specs. state. that the term "immediate" means the required action shall be initiated as soon as practicable, considering the safe operation of the Unit and the importance of the required action. Sea Hatch 1 Tech. Spec. p. 1. 0-2, initially issued in August 1974, attached as Exhibit 30. Identical definitions of "immediate" are also contained in the Tech. Specs, of Dresden 2 (December 1969), Pilgrim (June 1972), Duane Arnold (February 1974) and Browns Ferry 3_(August 1976). The Company considere the datch I definition to be synonymous with an interpretation of 26 The company nderstands that the Westinghouse owners Group proposals discussed above have not been incorporated into the MERITS Standard Tech. Specs. due to NRC's desire to maintain consistency among the various owners groups. This ongoing dialogue between NRC and the industry may be the appropriate forum to address (1) the evolving industry issue of voluntary entry into LCos with Action Statements which do not contain AOTs, ar.:1 (2) the meaning of the word "immediately" as contained in Tech. Specs. I 29
twith:ut undua dolcy undar the circumatenc30,5 and that it d nat mean athe very next action which the operator performs."pps An interpretation that the term "immediate" connotes a short
- duration is consistent with the safoty analyses which form the bases of the Tech. Specs. For example, with respect to Tech.
Spec. $ 3.4.1.4.2, the NRC's Standard Review Plan $ 15.4.6 requires that 15 minutes be available for operator action following a "high flux at shutdown" alarm in order to mitigate a boron dilution event during Mode 5 (30 minutes in the case of Mode 6). 313 Attachment 1, Exhibit D. The present day potential for operatore throuahout the industry to interpret Tech. Specs so as to permit voluntary entry into LCOs sith "immediate" Action Statements (based on the
" intent" of the Tech. Spec.) is demonstraced by a Tech. Spec.
Interpretatl w1 which was made at TVA's Saquoyah facility earlier this year. Ida TVA letter to NRC, dated April 10, 1991, (transmitting LER 50-328/91003) and NRC Inspection Report Nos. 50-327/91-06 and 50-328/91-06, dated April 25, 1991, attached as < composite Exhibit 31. The company understands that, similar to the VEGP chemical addition evolution, a TVA operator construed the term "immediato" in a Tech. Spec. Action Statement to permit l voluntary entry under administrative controls (and by procedure) into the Action Statement for a short period of time (in that case for 13 minutes) to perform maintenance. Although the i particular Sequoyah Tech. Spec. in question contained a phrase allowing Sequoyah operators two options: "either immediately open the isolation vi've or be in HOT STANDBY within one hour and be l in HOT SHUTDOWN within the next 12 hcurs," GPC understands that l the sequoyah operator was applying the "immediate" action opcion. l The company submits that the actions of the Sequoyah operator -- right or wrong -- during this event demonstrate that other operators Fr. Kitchenscan onreach a similar October interpretation 12, 1988, to theenvironment. even in today's one made by' l 25 Conversely, the Hatch Unit 2 Tech. Specs, do not contain a definition of "immediate." The company does not in*erpret the absence of such a definition to imply that a different definition should be applied at Unit 2. Otherwise, such a result would lead to confusion for dual-unit operators at Plant Hatch. 26 The Company nctes that escalated enforcement action was not taken in connection with the Sequoyah event. Likewise, escalated enforcement action is inappropriate in the case of the October 12-13, 1988 chemical additien evolution. Rather, the NRC should provide additional guidance and purposeful revisions of Tech. Specs. to preclude repetitions of activities which the NRC now views as contrary to requirements. 30
)
iTh3 ters 81ma: dicto # has 'not beenL used in tho- Tech. Sp ca. - ' in a purposeful, consistent manner. This can lead to differing Tech. Spec. interpretations due .to . operator- confuslon. The VEGP Tech. Specs. une the term "immediately" in' a -number of - Action
- Statements where ' there is . not otherwise any_ A0T. There are also aEnumber of other VEGc Tech. -specs. , with Action Statements which do.not exprerely previde an ACT, t hyt dg agt use the term "immediately." For example,- VEGP Tech. Spec. - 5 3.9.4 provides an Lco respecting containment penetration . isolation'during core alterations or movemenc of -irradiated fuel -in. conteinment. The associated' Action statement- provides: '
' ~ With' the requirements of the above specification not > a- satisfied, i==ediatelv _ suspend all operations involving
?
CORE ALTERATIONS or movement of irradiated fuel-in the containment ~ building _ [esphasis added) .
- In contrast, - VEGP-- Tech. _ spec. 5 3.fr.9 provides that the
- Containment. Ventilation : Isolation System shal) be. operable during core alterations or movement of irradiated f' el in the containment. Its: associated' Action Statement reads:
With the containment Vancilation Isolatt.on system inoperable,z close._each of the: Ventilation penetrations 4 providing- directraccess from the containment atmosphere
-to tha-outsidecatmosphere.
LThe latter . Tech. ! spec. ' Action Statement does not use the ters .
"immediately" and there is no apparent reason ~ for_ any distinction
.: to be- made between the two Tech. Specs.
The company submits that sucn inconsistentause..of the torn "immediately" can only (and, in
- this casa. did) J1ead to operator confusion.
- Furthermore, GPC : notes the: 0I- li -estigation and this Lproceeding in:themselves Jprovide furtner evidence that reasonable Lainds -can diffor ? and -have differed 'on une interpretation of VEGP
' Tech CSpec. ' 5 f 3.'4 .1. 4 . 2. 4 For example,: GPC is aware that OI isought: guidance. from NRR _'oa theiinterpretive . issue and GPC has' reason; to believe :dif ferences inl professional opinions have _been expressed within - the NRC. : Also,-the duration-between:the
- completion of primary OI field investigatione--(approximately:May, .
1990) . and sisauance. of ? the --Juno', .1991 Demands for Information, GPC R subeits,; reflects- the-. fact thatt the matter is far from clear.
- vin; summary, -the Company believes: that. reasonable minds can _
differ as to whether' voluntary entry into Tech.- spec. - 53.4.1.4.2 1 was;carmissible in the October 1988 time frame. _. The NRC should not bring an enforcementi action .where, as in this case, the 7 , disputed action ' concerns _ an evolving. ganeric industry issue. q
, - Rather, an appropriate method for resolving this-issue would be "
generic guidance..similar to that used by NRC to resolve its other concerns withl voluntary entry into 'LCos,- discussed above. 31
-4 _ , _ -.i.._._ _ . _ _ -
C. Georgia Power Coppany Procedures Relating To The Issuance And Control of Technical specification
-Clarifications.
- 1. The Policins and Procedures in Place at the Time of the Addition of Chemicals on October 12 and 13, 1988.
At the time of the 1R1 outage, VEGP Procedure 10000-C,
" Conduct of Operations," Rev. No. 9, attached as Exhibit 32, was in offect. Section 3.11 of that orocedure orovides guidance concerning the issuance of Tech. Lpec. interpretations. It indicates that when an operator determines an immediate interpretation is necessary, he or she cc'. tid contact any one of four operations Department management personnel for a verbal interpretation, wh! ' would be "followed up by the interpreter with a written requesu forn." Egg Exhibit 32 at pp. 20-21.
On the Day Shift of October 12, 1988, Messrs. Gasser and Hopkins followed Procedure 10000-C by requesting an interpretation of the Tech. Spec. from Mr. Kitchens. Following his review of Tech. Spea S 3.4.1.4.2 on october 12, 1988, Mr. Kitchens provided verbe guidance to Mr. Hopkins concerning the addition of chemicals to the RCS. Mr. Kitchens did not believe it was necessary to follow up with a written Tech. Spec. interpretation since a formal Tech. Spec. amendment would % requested for clarification (and was later requested) and there vould be no need for such an interpretation prior to the next refueling outage, at which time the Tech. Spec. would have been amended.
- 2. Current Policies and Procedures.
Since October 1988, the provisions of Procedure 10000-C governing Tech. Spec, clarifications have been revised. Egg VEGP Procedure 10000-C, Rev. No. 21, ettached as Exhibit 3':, at 5 3.11 and Figure 3. Today, an operator in immediate need of a clarification must contact one of the following three Operations Department management personnel: the Shift Superintendent, the operations Superintendent, or the Manager of operations. The clarification will then be given verbally, and may be followed up with a written request form. Egg Exhibit 33, 5 3.11.1, at p. 20. When an immediate clarification is not necessary, the requestor will completc a request form and send it to the operations l Manager. l Unlike the situation in 1988, after a clarification is made, review and concurrence is obtained from the Technical Supp rt l- Manager, following which final approval is obtained from the Manager of operations. The Technical Support Manager is responsible for obtaining corporate licensing support or NRC consultation, if deemed necessary, prior to final approval of the 32
, , .-- ~ . ~ - _ _ . , . - - - - . - - - -.- -. - ..- - _ _ _
d clarificaticn by thiMonngor of operationo.- Currontly, tho LTechnicalL aupport Manager. position 1s staffed with a licensed Senior; .teactor operator? vho has: also served as the technical-assistant to a former NRC. Commissioner.
- The current < version of tha Tech. Spec. clarification
~
Lprovisions; described above was developed as a- result of an observation- sade :during an NRC _Special Team Inspection ("STI") of VEGP in August of 1990. That observation,-documented in Inspection Report Nos~.- 50-424/90-19 and 50-425/90-19, dated
- January- 11,1991,- attached _ as Exhibit 34, noted that a weakness existed ~ in that one- individual, the Operations - Manager, was responsible for the approval and distribution of Tech. Spec.
clarifications. RAa Exhibit 34, Inspection Details, $ 2.1.1.1, > at:pp.7 7-9. .GPC's February 8, 1991 responseito Inspection Report 90-19; committed to implement 'the- changes described above. During the weeks of June 17 and- 24,- 1991, NRC Region II_ ins ireturned to VEGP to review GPC's corrective actions pectors resulting from-the ST::.- They found :that Tech. Spec. clarifleations were vell performed 'and,, with respect to the Tech. _ Spec. clarification provisions-of1 Procedure 10000-C, GPC's corrective actions were satisfactory.- Theirf: conclusions are documented in Inspection-
; Report-Nos. . 50-424/91-14 and 50-425/91-14, - dated July 19, 1991, 4
? attached;as. Exhibit!9, 5-.3A., at pp.:5-6.
Additionally, NRC Rueident inspectors at VEGP recently _ noted-a strength in'the-conservative approach *aken.by GPC in the , evaluatnon- and clarification of. Tech. Sme a. Specifically, , Inspection-Report Nos.. 50-424/91-05 and D 425/91-05,. dated April = 16, 1991,Jattached:as Exhibit 35, found that on three occasions, where,GPC found11t necessary to clarify the- Tech. -specs. , GPC's
, clarifications were~" safe and conservative" even though'they
" involved _ weighing safety;and~ economic = f actors'. Aas Exhibit 35 at
- p. f 4 ;; ASS AAAA Exhibit: 9, $ 2.c. , at p'.-2.
. Alsof today thereLis greater corporate . office assistance requestedLby:ated< provided _ to VEGP personnel than existed in 1988. - 4
-When_ requested by VEGP plant sanagement, corporate licensing-personnel- are used to- research Tech.ispec. clarifications.
' Additionally, when deemed appropriate, the NRC is contacted
- concerning proposed Tech. : Spec.-- clarifications.- A recommendation
?is then made to VEGP personnel- regarding the Tech. Spec._ ;
. clarification.
Furthes .re, communication. between VEGP management and'ths .
. NRC has, improved as' noted- by the- NRC ;in the most tecent SALP
' . Report for VEGP, covering the period ' October 1, -1989 through t september 30,.1990. 13A NRC; Inspection Report'Nos. 50-424/90-23 andt50.425/90-23, cated December 10, 1990, attached as Exhibit 36;-at'p.-5. - In--many: respects this enhanced. communication reflects the maturation of VEGP and the. recognition that ,
33 1 s 2 4,
discussions with knowicdgsablo NRC repracontativ00 ccnetituto a l valuable resource. D. 2ht_Gapraia Power comoany Ostaae Plannina Proceg32
- 1. Planning for the 1R1 Outage and Development of the Procedures to Add Chemicals to ths RCS at the Mid-loop Condition of Mode 5.
In December 1987, the VEGP Outages and Planning organization ("O&P") first ide,tifi6d that chemical cleaning of the RCS would be performed during the 1R1 outage. Egg Resolution Item ' tracking Master Report, dated December 27, 1987, attached as Exhibit 37, sheet 2, iten 20. However, it was not until April 14, 19u8 that it was decided to perform the chemical cleaning attgr the RCS had been drained down to the "Mid-loop" level in Mode 5. Ens Refueling Outage Meeting Minutes (April 14, 1988), dated April 18, 1988, attached as Exhibit 38, at p. 1. Then, as now, O&p was responsible for planning refueling outages. At that time, O&P was not staffed with a dedicated licensed reactor operator. The VECP Operations Department participated in the outage and planning process by designating a representative, who was a licensed operator, to attend the outage planning meetings and provide "interf ace" between the Departments. The operations Department representatives in the planning process for the IR1 outage did not realize that the proposed chemical addition cf hydrogen peroxide at Mid-loop conditions required the opening of the RMWST discharge valves. As a result, those representatives did not realize, and, to GPC's knowledge, no one else involved in the outage planning y ocess recognized, that'the VEGP Technical Specifications were involved with the chemical addition evolution. _ This is not to imply that the j review' effort was inconsequential. As one example, a Tech. ,pec, i conflict with a containment isolation valve manipulation evolution was identified during the effort. Egg Exhibit 38 attachment entitled " Resolution Item Tracking - Open Items," at
- p. 3, Resolution No. 70.
On April 29, 1948, Lhe VEGP Health Physics and Chemistry Department initiated the review of a new procedura, 49006-C, entitled " Health Physics and Chemistry. Department outage Activities." Egg Procedure Review Request Form ("PRRF") for Procedure 49006-C, dated April 29, 1988 (one sheet) with attached Environmental Evaluation (one sheet) and Safety Evaluation (one sheet), all attached as Exhibit 39. Procedure 49006-C, Rev. No. O, attached as Exhibit 40, expressly nrovided that the chemical cleaninV evolution would be performed sfter the RCS had been cooled down to 110*F and drained down co the "Mid-loop" level. 34
)
1 l l 333 Exhibit 40, SS 6.4.4.c and d, et p. 15. WhGn th3 PRRF was l prepared, however, the initiatcr concluded that the Tech. Specs. l were not involved because, he tnought, "this level of detail is I not in Tech. Specs." Egg Exhibit 39, sheet 3. As a result,
- l Procedure 49006-C was reviewed and approved within t? i Health l Physics and Chemistry Department and was not reviewed by other l departments or by the Plant Review Board. Egg Exhibit 39, shoot l
- 1. '
Tvo other VEGP addition evolution. procedures First, VEGPwere relevant Procedure to the chemical 13007-1, Rev. No. 2, attached as Exhibit 12, provided explicit instructions to the operations Department concerning valve manipulations to add chemicals to the RCS. That procedure did not specify at what RCS vater level the chemical addition was to be performed. Ett Exhibit 12 at pp. 12-13. However, Procedure 13007-1 apparently contemplated application with the RCS in the " Loops Filled" condit!un since it did not require the opening of Valve 177 (a valve which is normally open with Loops Filled) when adding water to thc Chemical Mixing Tank from the RMWST. Second, VEGP Procedure 35110-?. Rev. No. 10, attached as Exhibit 41, provided instructions to Chemistry perscnnel for the addition of chemicals. E2s Exhibit 41, S 4.11, at p. 14. That procedura provided that, af ter filling the Chemical Mixing Tank, the chemistry technician was to request the operations Department to perform the necessary valve manipulations in order to inject the chemicals into the RCS. The procedure did not specify at what RCS vater level chemicals could be added. Bassd .se foregoing, GPC believes that the conflict between Tech. Spec. S 3.4.1.4.2 and the chemical addition evolution, planned for the Mid-loop condition of Mode 5, escaped recognition by VEGP personnel prior to the 1R1 outage. GPC attributes this oversight to (1) insufficient involvement of the operations Department or licensed operators in the outage planning process, due, in large part, to the inexperience of VEGP, (2) inauequate inter-departmental review of the chemistry procedure concernipp outage activities, due to a failure to follow procedures, and (3) failure to adequately consider potential applications of the proceduras in various modes and conditions.
"GPC has recent.ly briefed VEGP procedure writers concerning VEGP requirements for inter-departmental review of procedures they prepare. This training was a corrective action performed to address an operational weakness concerning inter-departmental review of procedures identified by NRC during the August 1990 STI. Egg Exhibit 34 at pp. 16-17.
During the NRC's follow-up inspection of GPC's corrective actions, that item was closed. Sag Exhibit 9, S 3.d., at p. 6. 35
- 2. Current Outage Planning Process.
The operational experience and expertise of O&P has been ' strengthened and the depth of review during the outage planning process for potential operational limitations has been increased. Today, o&P is a multi-disciplined and experienrod group which prepares and maintains up-to-date outage plans /senedules for planned outages, maintenance outages and forced outages, and maintains long-range schedules. VEGP Procedure 29537-C, Rev. No. 5, attached as Exhibit 42, identifies the organizaticns, relationships and responsibilities associated with outage planning knd scheduling. The following paragraphs summarize the ! current outagw planning process for " planned outages." For further details, see Exhibit 42, S 4.4, i at pp. 10-13. When the scope of the outage is determined and the needed work activities are known, O&P personnel use the .ch. Specs. as limitations for scheduling the day to day activit4es of the overall outage schedule, Addition 61 factors considered include risk assessment (beyond Tech. Specs, requirements), budgets, cuatractor support, worklond on control room operators and plant perators, manpower resources and material support. Approximately six months before a planned refueling outage begins, O&P personnel serd a preliminary outace schedule to affected departments for input and review. LicensedSenior Reactor operators from the operations Department now revidw the schedule at a detailed leval to ensure compliance with Tech. Specs. This is on iterative process between O&P and- the operations Department, or between O&P and other affected departments, as the case may be. The end result is a detailed outage schedu3e whose activities have been intensely examined. Reviews are conducted to ensure that needed temporary E modifications are identified, ALARA concepts are incorporated, operability issues are addressed, work areas are not congested, , and Tech. Spec compliance can be demonstrated. Special consideration is given to plant configurations resulting in reduced RCS coolant inventory. As new work is added to the schedule and schedule iterations occur, outage risk management concepts are used to evaluate the overall impact of any reduction of safety . system capability. During the development and review process, priority is given to ensuring compliance with Tech. Specs., avoiding LCos, identifying any mode-constraint LCOs and considering outage risk management concepts (over and above Tech. Spec. compliance) to enhance radiological safety. Prior to final approval by the plant General Manager, the final outage schedule is reviewed and approved by the Manager of 36
p ,
,t
[0;P,J tho- operations -Manag0r, tho Maintenanco Manngsr, the Hsalth
! Physics and: Chemistry Manager, the Engineering Manager, the J Technical; sups rt Manager, the Assistant General Manager-Plant' support, and sae Assistant- General Manager-operations.
- The, NRC's: review of the VEGP March 20, 1990 operational event -is instructive with respect to the pre-october 1988 0&P
. review efforts. =The NRC Incident: Investigation Tema ("IIT")
observed 1that -certain aspects. of outage management was a performance shortcoming.- Following the March 20, 1990 event, GPC made 3 improvements in its outage management and the NRC noted Q those improvements in its December- 10, 1990 SALP Report on VEGP. Age Exhibit.36 at pp. 19-ko. m , E.. Georgia Power Company Policies, Procedures, Practices And Training Respecting Compliance With The VEGP Technical Specifications. 4 Today, VEGP_ operators receive specific training concerning the Tech. - Specs.= including (1) _the legal _ authority requiring Tech. Specs., 2 the five major sections-of the' Tech. Specs. and their : purposes,(: )(3) the detailed format of the Tech. Specs.(4), Tech.L Spec. clarifications - (VEGP - Procedure 10000-C) , and (5) Tech.-Spec._-amendments. Saa VEGP Training Le'sson Plan 14-LP--
~39201-06-C,'" Introduction to Technical Specifications," Rev. Ko.
6, attached to Exhibit 43. The - LCO- and surveillance requirements of Tech.JSpec. 55: 3.0.and_4.0 are explained during the training, and examplea_of each'are provided. Each current Tech. Spec.
. clarification is reviewed with the class. -Ama. Exhibit-43,
- 55;II.C.3. and II.D, ? at pp. 3-11. Hypothetical situations requirint application of :the. Tech. Specs, are often discussed during operator training and encountered during simulator.
exercises.--
.In? addition,oduring requalification training, VEGP coperatorsfare provided with (1) periodic updates of significant
' > plant modifications t and- procedural changes, and (2) information fron_ selected ~ operating events. Sag VEGP-Training Lesson: Plan RQ-LP-63107-00, "Regral Current: Events," Rev. C, attached as
~
-Exhibit'44. :For example,; operators are specifically-trainedLin thatchknges made-to-VEGPLProcedure.12006-C respecting the opening-of f the~ RMWST discharge valves and_ the Tech. Spec. 5: 3.4s1.4 interpretation of-" Loops Not-Tilled." its Exhibit 44, $$ III.C.1 and_III.D.1, sat.pp. 6 and 1, respectively.- -
In early 1989,nthe VEGP " Shift ~ Briefing Book" and "Operstions Reading Book" vere 1 revised:to ensure that all
' Operations Department- supervisors"and all reactor operators are ,
. aware of-the Tech. Spec. requirements for the RMWST discharge valves to:be closed and secured in position _during the-Loops Not Filled condition of Mode 5 and'during Mode 6. Also, in'1989, a -
1 37 1 [k . _ _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - -
- number. cf VEGP proc:durco woro roviced _to add o pracautien and limitation which recited othe Tech. Spec. requirements that the RMWST, discharge valves be closed and s.acured;in position during ;
the Loops Not Filled;condicion ofs Mode 5 and' during Mode- 6,
- 1 including Procedme Nos.12000-c. (Rev. No.14), 12001-C.(Rev. No.
- 13) ,-- 13007 (Rev.- No. 3 ) ,- 13007 (Rev. No. 2) , ' 13701-1 (Rev.
No.~ 10) and 13701-2'(Rny. No. 11 ', LIn cormection with the- specific events of october 12-13, u- ' 1988, GPC Vice President-Nuclear (Vogtle), Mr. C. Kenneth McCoy,
' or the:VEGP General Manager, .Mr. William B. Shipman, _ personally contacted theLthree _ VEGP Operations Department employees shortly t
- after receipt of the NRC's June 3, 1991 correspondence and.
reinforced theirLinJividual obligations to comply with NRC ' regulatory requirements, " including the Tech.- Apocs.
.VEGP operators' . compliance with Tech. Spec. requirements is falsoLaddressed by several other means. First,-VEGP Procedure
- 10000-C, " conduct of operations," attached as Exhibit 33, express 1" charges operations Department personne1'with the responsibility to ensure plant operations are _ conducted, in accordance withithe Technical Specifications and approved ,
procedures. ~333 Erhibit 33, 55: 2. 2. c. , - 2. 3. a. and 2. 5.c. , at pp. 2, L 3 and 5, respectively. Second, licensed operators are encouraged- to ' be thoughtful and: questioning in - approaching their ,_ . day-to-day activities and,-- when unsure, to seek assistance - from t optrations Department line _. management. ' Access to upper line
~# management by plant personnel is a key component of the philosophy. of VEGP management. _ l The plant duty manager (a senior
-,=
manager,on-call'. 24 hours : a day) or-operations Manager are:often f contacted by shift personnel- when. questions concerning equipment -
' operability or other. issues- ariselunderJthe Tech. Specs.- Third, p coaching:and; decision-making through- teamwork is an important technique. used . by . management to-_ ensure l operator compliance with Tech,1 Specs.
D h LThe VEGP Operations - Departrent' Manager alsos seeks assistance fron~ the plant and corporate technical 'andflicensing statfs when
- l. difficult questionn arise.
7 As described-.in'Section III.C above, L ; theLVEGP procedure concerningc Tech.- Spec, clarification- has L recently:been: revised to require - that all Tech. _ spec. L* clanifications t are reviewed by the- VEGP Technica1' Support EDepartment Manager. VEGP Department Managers routinely observe : implementation of : Tech.1 Specs.< and plant procedures through the Management
; "'y 10bservatiori Program and - day-to-day involvement with plant 3 activities. _ AlsoP QA ; audits - and other _ evaluations provide indepe
- complindent-ance'with insights Tech.to . management concerning ; licensed operators' Specs, g
i 38-i L v , m 1
-n -. . - - . . . -
- ~. . . - - - -- . .-.~-
), P A
Additionally,' GPC hao- o *Pocitivo Dicciplino: Policy # ' designed; to stimulate-individual ~ accountability; for all aspects
- of regulatory compliance through the use of -(1)i oral reminders,
.(2) written reminders, and (3) = decision making : leaves,Lwhich are
- n used-in ascending-~ order. ~A copy of=the. current GPC Positiva Discipline Policy is attached as= Exhibit.45. The Company
,currectly~ holds all senior: reactor operators-accountable for comp 11anca with-Tech.-specs. and reporting requirements-through the annual review of each operator's performance. 'This process holds' individuals:as well the collective shift accountable for, ,
-among Tother things, compliance with Tech. Specs. GPC has found :
'this process-promotes:more open. discussions concerning Tech.
Spec. compliance. o
'.In February 1989,:Mr. Kitchens, as Operations Manager,
- issued _an_ operability Policy to all licensed operators which included-- guidance to _ ensure strict compliance _with _ Tech. - specs.
The policy established responsibilities for interpretation and use:of the Tech.sSpecs. -A copy of Mr. Kitchens' memorandum ' distributing;the Operability Policy is- attached as Exhibit' 46.
-Recently, Mri Willian: Shipman, the VEGP _ General Manager, issuod a memorandum to all; operations Department-employees -
designed" to advise . them,. .in a-. positive - way, -of the1importance of compli'nce a with the Tech, specs. and the-Tech.-spec. ._
' clarification procedure. Mr.. shipman's memorandum:also advised
- a. the operators.of certain NRC guidance concerning voluntary entry
- into Tech.- Spec. LCOs ;and plainly stated that NRC does not consideriiti appropriate-to voluntarily enter LCOs which do not
, provide a: specific AoT. A copy -of. Mr. shipman's memorandum is - attached-as Exhibit 47.
--As a generallmatter,.the Company. continuously urges and
-expects Operations-Department personnel'to conform their . '
Jac-tvities at all times:with the NRC operating: license, incihding-the Tech. Specs.,LandLall NRC-rules,.. regulations:-and orders. The Company recognizes that successful plant operations depend on: such: compliance. _ GPC believes this fundamental: philosophy' is well-established in the culture.at VEGP. . . IV. RLASONABLE' ASSURANCE EXISTS THAI GEORGIA POWER COMPAN CURRENTLY CONDUCTS AND WILL IN THE FUTURE CONDUCTTLICENSED- -
-ACTIVITIES IN ACCORDANCE~WITH THE'VEGP TECHNICAL SEECIFICATIONS AND ALL OTHER NRC REQUIREMENTS. '
The, Company firmly believes that none of~the events
;surroundingsthe October 1988 VEGP chemical addition evolution, or ~
any other' events at VEGP,:should give rise to an NRC concern over
- GPC's. compliance with Tech. Specs, or other NRC requirements. No deliberate violation of Tech, specs. has occurred and^no licensed 39 f
g 3; } % 3 ,- , - .-.
Jindividuni ot VECP hostcarolosely:dierogordcd the Tcch. Sp;cs. [ Additionally, the events concerning the October 1989 chemical addition: evolution:were'an: isolated occurrence, the institutional root 'causes- for which -have been identified and addressed.- However, Limprevements have been~ made since 1988 as 'a resulw ' ' ofiveaknesses identified. by GPC sind several identified by NRC. Specifically,. as discussed in- Section. III C,-. above, GPC's current procedure regarding VEGP Tech. Spec. .c1arifications has been improved and NRC inspectors -have recently found that procedure
. acceptable. The:NRC Resident Inspectors have a1so recently:found that-actual Tech. Spec. clarifications 1made by VEGP Operations Department;'personne1~.were safe and conservative. These--
inspectors-have generally expressed their support for the VEGP
-Operations Deoartment. management. In addition,_GPC has improved communicatior. M twenn'VEGP and the NRC, as well as between-VEGP Jand the corpor t e office in Birmingham.
As: discussed . above, GPC has also .made - significant improvenants.in outage planning and management and procedure
. preparation. Ega: Section III.D', above. Those improvements have been noted by NRC inspectors. -
4 _ operator training and guldance has also improved e . considerably'since the'VEGP 1R1 outage as demonstrated in.Section-III.E.and: Attachment.'2, respectively. From a-broad perspective, the:NRC has recently assessed operationsLat.VEGP and found that VEGP is operated-in a safe
. manner.: In August 1990,.the NRC-conducted.aLSpecial TeamL
-Inspectfon-at VEGP,;: including _a' performance-based evaluation of .
3the Operations: Department in order to (1) evaluate the ', operational philosophy, policies, procedures,7and practices of-the!operatingistaff and~ aanagement, and L (2) _ determine. If- the. plant wastbeing operated._in a safe manner-ineaccordance with:the operatingLlicenses.-:The inspection = team used NRC Inspection-Procedures"71707, " Operational Safety Verification," and 71715, , " Sustained Control. Room-and Plant.0bservation." The inspection
- tema found that :the. f acility was. operated tin a sata manner -in L " *accordance with the requirements of the t Facility Operating Licenses.- 133 Exhibit 341st p.xi. . Where specific-weaknesses-
~
p~
- were identified,; GPC planned . and 11mplemented corrective -actions.
Following a' review; of the GPC corrective actions .during the-weeks y of JuneL 17- and 24,.1991,1 the.NRC closed.each one.of the' G
;inspectionLfindings indicating that GPC had adequately! addressed.
l-the; operational. weaknesses. _-133 Exhibit 9, $$ 3.a. through 3.k., ^
< at' ppm 5-9.
g I
~
i l_ L 40 j: [ l: i g ,y, , u.. . . , , .- , = . . . -- --_-______--==_a
V, p,0NCLUSION. The information provided in Section III.8, herein, provides substantial evidence that GPC operations Department personnel did
- not willfully violate VEGP Tech. Spec. $ 3.4.1.4.2 on october 12 rnd 13, 1988.
The first shif t to enter into the Tech. Spec., that of Messrs. Cash and Bowles, was unaware of the applicability of the Tech. Spec. and, therefore, did not have the necessary state of mind requisite to a willful violation. Based on the training, guidance and procedures available to them at the time, it cannot even be said that Messrs. Bowles and Cash should have known that the Tech. Spec. was applicable. (Indeed, in February 1989, different operators on VEGP Unit 2 also failed to recognize the Loops Not Filled condition.) When the issue was raised by the on-coming shif t personnel, Messrs. Bowles and Cash made an appropriate entry in the log, documenting their late realization. Because they did not know the Tech. Spec. was applicable, they could not have either deliberately violated the Tech. Spec. , or carelessly disregarded the requirements of the Tech. Spec., as those taras have been interpreted by the NRC and the courts. With respect to the activities conducted during the following shif t, GPC believes that Mr. Kitcher.s mede a l reasonable, good faith interpretation of the Tech. Spec. under the cit cumstanc=a which precludes a finding that a willful violation occurred. Mr. Kitchens conducted a careful and open reviewf,y halting the evolution, revievir.g the Tech. Spec. Beses ! and F3?.P, and consulting with a more evr.erienced operations
- manager anc others. He reachad a reasonable conclusion that the planned evolution was analyJed and that the valves in question L
could be opened under administrative controls for a short period of time. Additionally, his experience at the time did not tell him that the voluntary entry into a Tech, Spec. requiring inmediate action was prohibited. He knew, as a general matter, ! .veluntary entry into Tech. Specs. was permiscible and that the term "immediately" as used in the Tech. Specs. allowed some time for action. In fact, in connection with the interpretation of a another Tech. Spec. requiring immediate acticn, Mr. Kitchens recalled that, in 1987, the NRC had condoned delaying the initiation of immediate action until the completion of a trouble ~ shooting evaluation. Mr. Kitchens was unaware of any NRC guidance which prohibited the voluntary entry into Tech. Spec. Action Statements vhich require immediate action; in fact, none existed. Indeed, an discussed in'Section III.B.5 herein, there is considerable evidence that reasonable minds can differ as to whether voluntary entry into Tech, Spec. 5 3.c.1.4.2 was permissible in October 1988. In particular, the NRC's actions with respect to this case and another recent enforcement action within Region II suggest 41
. _ _ ,y ..- .
y ., . _ __ .. _ .. , . _ _ _ _ . . _ . _ _ .._. _ _ _ _ _ _ _ ~ , t oth5% NRC Stoff.peretnnal can differ concernin the-issue of
; voluntary entry-into:a Tech. spec. requiring usediate action.- :
' -The Company _ submits that this satter involves a. generic industry , t lissue which shouldtbe resolved in a forum other than an - 4 (enforcement-action
- ago. . for an~ event that occurrad almost three years g- ,
i Mr.' Kitchens was-not activated by.any desire to reduce the
.had the_duration
-outage; oppositeoriffact.:
reduce outage costsF the evolution, in fact, , Also, at the time, Mr. Kitchens determined;that Me evolution woul_d have an ins ~1gnificant etfact Jon boron concentration. After-the fact analyses-have confirmed -
.his conclusion:ond demonstrate that-there was minimalEsafety
-significance asbaciated with the evolution. Notably, the !
evolution. reduceC occupational exposure .during the outage. Enforcement action against Mr. Kitchens is inappropriate under these facts then NRC regulations require that, before bringing _such actions,'NRC find "little' doubt that-the. i individual. .. knew, or. should have known,- the required actions." At a minimum,- the facts presented above raise substantial doubt
' ;that Mr.; Kitchens know:or-should have known-that his actions ,
' violated the Tech, spec. The company belicves Mr. Kitchens ~ acted '
. in good faith and that his conclusions were reasonable-under the-
' -_ circumstances,f.even ifLthe NRC now concludes they violated the Tech. Spoo.-
- GPd has taken definitive _ action to ensure opurators.-
understand and follow-the Tech. Specs, as intended by the NRQ-(See -- Exhibit 47)'. Furthermore,_the Company.has taken. action to
. ensure:that the institutional' weaknesses'in the outage planning process'and in-operaf.or training and guidance-which contributed
- to this event have been addressed. - ,
p
.As demonstrated in Section IV above, reasonable assurance t k exists-- that- GPC_ currently: conducts,- and will 'in. the - future -
V conduct, licensed activities-in.accordance with the VEGP
- v. L. Technical specifications and all:other-NRC requirements.
- n. +
e - 1-l Dated: - August 28,-1991 r) t)
+
42
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UNITTO STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the Matter of GEORGIA POWER COMPANY,
- 11 A1
- Docket Nos. 50-424
- 50-425 (Vogtle Electric
- EA 91-063 Generating Plant,
- Units 1 and 2)
- GEORGIA POWER COPPANY'S RESPLWSE TO THE NRC'S JUNE 3, 1991 DEMAND FOR INFORMATION APPENDIX I EXHIBITS 1 THROUGH 47 i
l l
g f f SIMPLIFIED CVCS / RMWST 5- RMWST E. 380,000 GAL.
~$ @ VOLUME 'G CONTROL 4 TANK g 3,000 GAL.
FV111A
- O 177
- j74 175 * '
TO CVCS = BLENDER AND
'[ 'I r _
VCT CHEM./ ADD 3 FUNNEL Ny
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CHEM ADD 178 TRAIN B - k CCP SUCTION LV-1128 ,g3, A
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ed z- [ LV-112C CO CHEMICAL MIXING 8
$,4 $ [ iga TANK :n o 5 GAL Ed CCP A CHECK VALVE 182 181 TRAIN A RCS h C J # CCP SUCTION V rw !,
- ~ ~ ' ' * ~ ~~~ ~ '
CCP B -
- RMWST DISCHARGE VALVES ADDRESSED BY TECH. SPEC. 3.4.1.4.2 pop -
CHEMICAL ADDITION FLOWPATH NOTE: ONE OF 3-PUMPS RUNNING TO ADD CHEMICALS TO RCS.
l i REACTOR COOLANT SYSTEM COLD SHUTDOWN - LOOPS NOT FILLED LIMITING CONDITION FOR OPERATION 3.4.1.4.2 Two residual heat removal (RHR) trains shall be OPERABLE
- and at least one RHR train shall be in operation.** Reactor Makeup Water Storage Tank (RMWST) discharge valves (1208-U4-175, 1208-U4-176, 1208-U4-177 and 1208-U4-183) shall be closed and secured in position.
APPLICABILITY: MODE 5 with reactor coolant loops nct filled. ACTION: a. With less than the above required RHR trains OPERABLE, immediately initiate corrective action to return the required RHR trains to OPE'lABLE status as soon as possible. b. With no RHR train in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required RHR train to operation.
- c. With the Reactor Makeup Water Storage Tank (RMWST) discharge valves (1208-04-175, 1208-U4-17G, 1208-U4-177, and 1208-04-183) not closed and secured in position, immediately close and secure in position the RMWST discharge valves.
SURVEILLANCE' REQUIREMENTS 4.4.1.4.2.1 At least one RHR train shall be determined to be in operation and circulating reactor coolant at least once per 12 hours. 4.4.1.4.2.2 Valves 1208-U4-175, 1208-04-176, 1208-U4-177, and 1208-U4-183 i shall be verified closed and secured in position by mechanical stops at laast once per 31 days.
*0ne RHR train may be inoperable for up a 2 hours for surveillance testing l providtd the other RHR train is OPERABLE 'nd in ooeration.
I l **The RHR pump may be deenergized for up to 1 hour provided: .(1) no operations are permitted that would cause dilution of the Reactor Coolant System boron concentration, and (2) core outlet temperature is maintained at least 10*F below saturation temperature. V0GTLE UNITS - 1 & 2 3/4 4-6
3/4.4 REACTOR COOLANT SYSTEM BASES 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION The plant is designed to operate with all reactor coolant loops in operation and maintain DNBR above 1.30 during all normal operations and antici-pated transients. In MODES 1 and 2 with one reactor coolant loop not in operation this specification requires that the plant be in at least HOT STANDBY within 6 hours. In MODE 3, two reactor coolant loops provide sufficient heat removal capability for removing core decay heat even in the event of a bank withdrawal accident; however, a single reactor coolant loop provides sufficient heat removal capacity if a bank withdrawal accident can be prevented, i.e., by opening the Reactor Trip System breakers. In MODE 4, and in MODE 5 with reactor coolant loops filled, a single reactor coolant loop or RHR train provides sufficient heat removal capability for removing decay heat; but single failure considerations require that at least two trains / loops (either RHR or RCS) be OPERABLE. In MODE 5 with reactor coolant loops not filled, a single RHR train provides sufficient heat removal capability for removing decay heat; but single failure considerations, and the unavailability of the steam generators as a heat removing component,' require that at least two RHR trains be OPERABLE. The locking closed of the required valves in Mode 5 (with the loops not filled) precludes the possibility of uncontrolled boroa dilution of the filled portion of the Reactor Coolant System. This action prevents flow to the RCS of unborated water by closing flowpaths from sources of unborated water. These limitations are consistent with the initial conditions assumed for the boron dilution accident in the safety analysis. The operation of one reactor coolant pump (RCP) or one RHR pump provides adequate flow to. ensure mixing, prevent stratification and produce gradual reactivity changes during boron concentration reductions in the Reactor Coolant Syste". The reactivity change rate associated with boron reduction will, therefore, be within the capability of operator recognition and control. The restrictions on starting an RCP with one or more RCS cold legs less than or equal to 350'F are provided to prevent RCS pressure transients, caused by energy additions from the Secondary Coolant System, which could exceed the limits of Appendix G to 10 CFR Part 50. The RCS will be protected against overpressure transients and will not exceed the limits of Appendix G by restricting starting of the RCPs to when the secondary water temperature of each steam generator is less than 50*F above each of the RCS cold leg temperatures. l l l V0GTLE UNITS - 1 & 2 B 3/4 4-1
VEGP-FSAR-15
. 15.4.6 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION THAT RESUL7.S TN A DECREASE IN THE BORON CONCENTRATION IN THE REACTOR COOLANT 15.4.6.1 Identification of Causes and Accident Description Reactivity can be added to the core by feeding primary grade water into the reactor coolant system (RCS) via the chemical and volume control system (CVCS). Boron dilution is a manual operation under strict administrative controls with procedures callir.g for a limit on the rate and duration af dilution. A boric acid blend system is provided to perm 1'- O e operator to match the boron concentration'of reactor coola;t makeup water during normal charging to that in the RCS. The CVCS is designed to limit the potential rate of dilution to a value which, after indication through alarr.s and instrumentation, provides the operator sufficient time to correct the situation in a safe and ,
orderly manner. The opening of the primary water makeup control valve provides makeup to the RCS which can diluta the reactor coolnTt. Inad 'ertent dilution from this source can ba readily terminated by closing the control valve. In urder for makeup vator to be added to the RCS at pressurn, at least one charging pump must - be running in addition to a reactor makeup water pump. Normally, only one primary grade water supply pump is opsrating while the other is on standby. The boric acid from the boric acid tank is blended with primary grade water at the mixing tee, and the cctpneition is determined l by the preset flowrates of boric acid and pt mary grade water , on the control board. Information on the status of the reactor coolant makeup is continuously available to the operator. Lights are provided on the control board to indicate the operating condition of the pumps in the CVCS. Alarms are actuated to warn the operator if
\
Amend. 3 1/84 Amend. 30 12/86 15.4.6-1 Amend. 35 3/88
q i VEGP-FSAR-15
' boric acid or demineralized water flowrates deviate from preset values as a result of system malfunction.
This event is classified as an American Nuclear Society Condition II incident (an incident of moderate frequency) as defined in subsection 15.0.1. 15.4.6.2 Analysis of Effects and Consequences 15.4.6.2.1 Method of Analysis To cover all phases of the plant operation, boron dilution during refueling, startup, cold shutdown, hot standby, and power operation are considered in this analysis. 15.4.6.2.1.1 Dilution During Refueling. An uncontrolled boron dilution accident cannot occur during refueling. This accident is prevented by administrative controls which isolate the RCS from the potential source of unborated water. Valves 175, 176, 177, and 183 in the CVCS will be locked closed during refueling operations. These valves will block the flow paths which could allow unborated makeup water to reach the RCS. Any makeup which is required during refueling will be borated water supplied from the refueling water storage tank by the low head safety injection pumps. 15.4.6.2.1.2 Dilution During Cold shutdown, Hot Standby, and Hot Shutdown. An analysis was performed to evaluate boron dilution events during cold shutdown, hot shutdown, and hot standby. Failure modes and effects analysis, human error analysis, , and event tree analysis were used to identify credible boron dilution initiators and to evaluate the plant response to these events. 'For the ' initiators identified, time intervals from alarm to loss of shutdown margi? were calculated to determine the length of time available for operator response. These calculations depended on dilution flowrates, boron concentrations, and Reactor Coolant System volumes specific to ! the event and mode of operation. The technique modeled realistic plant conditions and responses, including both mechanical failure and human errors. The analysis identified four events which were considered to be the most likely initiators:
- 1. Demineralizer outlet isolation valve open during resin.
flushing.
- 2. Valve 226 open following BTRS demineralizer flushing operation.
15.4.6-2 Amend. 17 7/85
. . . , .--. .-- - - - ~ . - - . . - - - - - -- - - .-.. . ~ . . . .. ._ -
- VEGP-FSAR-15
-i
. 3 .- Failure:to secure chemical addition.
- 4. Boric acid flow control valve (FV-110A) fails closed -i during make-up.
Initiator 4 was found to be the most limiting event for modes 3, 4, and 5. The parameters used in the calculation of time. available for operator response are listed in table 15.4.6-1. . Conservative values of boron worth (pcm/ ppm), as a function of RCS boron concentration, wars assumed in the analysis. , , Since the activa volumes considered are so small in cold i shutdown with-the reactor coolant loops drained, it was determined that the same valves. locked out in refueling would need to be locked out in cold shutdown when the reactor coolant loops are drained. t a f
'\
l~ rc Amend. 17- 7/85 Amend. 30- -12/86 15.4.6-2a Amend. 35 3/88
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f VEGP-FSAR-15 J T t 1
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(This page has intentionally been left blank.) 1 s 15.4.6-2b Amend. 17. 7/85 l-
. ~- .-
4 1 VEGP-FSAR-15 : 17 9 15.4.6.'2.1.3 Dilution-During Full Power Operation, ..
-Including Startup.
15.4.6.2.1.3.1 Dilution During Startup. Conditions at_startup E 17 ' require the reactor to have available at least 1.30-percent ' Ak/k shutdown __ margin.- The maximum boron concentration required to meet this shutdown margin is conservatively - estimated.to be 1704 ppm. The following conditions are assumed: for an uncontrolled boron dilution during startup: A. Dilution _ flow is assumed to be the combined capacity of the two primary water makeup pumps (approximately 242 gal / min). " B. 'A minimum water-volume'(9757-ft*) in the. reactor
~
coolant system is used. 'This volume corresponds to the active volume:of the RCS minus.the pressurizer
. volume.-
15.4.6.2.1.3.2 - Dilation During Power Operation. During pewer. l17
- operation, the plan *. may be_ operated two ways,.under manual -
operator control o under automatic Tavg/ rod control. While- ' the plant _is in manual control, the dilution flow is assumed to-
- be a maximum of-242. gal / min, which is the combined capacity of-the two: primary water makeup pumps. While in automatic -
control, the dilution flow is limited by the maximum letdown flow-(approximately 125-gal / min).
- Conditions at power operation require the reactor-to have available at least 1.30-percent'Ak/k shutdown margin. The maximum-boron. concentration required to meet this shutdown-margin is very conservatively estimated to be 1704 ppm.
15.4.6-3 Amend. 17 17/85
VEGP-FSAR-15 , A minimum water volume (9757 ft') in tce RCS is used. This volume corresponds to the active volume of the RCS minus the pressurizer volume. 15.4.6.2.2 Results The calculated sequence of events is shown in table 15.4.1-1. 15.4.6.2.2.1 Dilution During Refueling. Dilution during refueling cannot occur due to administrative controls. (See paragraph 15.4.6.2.1.1). 15.4.6.2.2.2 Dilution During Cold Shutdown. For dilution during cold shutdown, the Technien1 Specifications provide the required shutdown margin as a function of RCS boron concentration. The specified shutdown margin ensures that the . operator has 15 min from the time of the high flux at shudown - alarm to the total loss of shudown margin. 15.4.6.2.2.3 Dilution During Hot Standby and Hot Shutdown. For dilution during hot standby and hot shutdown, tbs Technical Specifications provide the required shutdown margin as a - function of RCS boron concentration. The specified shutdown margin ensures that the operator has 15 min from the time of the high flux at shutdown alarm to the total loss of shutdown l margin, 15.4.6.2.2.4 Dilution During Startup. In the event of ar. unplanned approach to criticality or dilution during power escalation while in the startup mode, the operator is alerted to an unplanned dilution by a reactor trip at the power range neutron flux high, low setpoint. After reactor trip there is at least 19.0 min for operator action prior to loss of shutdown margin. 15.4.6.2.2.5 Dilution During Power Operation. During full- , power operation with the reactor in manual control, the' operator is alerted to an uncontrolled dilution by an overtemperature AT reactor trip. At least 19.0 min are available from the trip for operator action prior to loss of shutdown margin. During full-power operation with the reactor in automatic control, the operator is alerted to an uncontrolled reactivity insertion by the rod insertion limit alarms. At least 36.8 min are available for operator action from the low-low red insertion limit alarm until a loss of shutdown margin occurs. Amend. 17 7/85 Amend. 30 12/86 15.4.6-4 Amend. 35 3/88
i
- VEGP ~'AR-15 t
-15.4.6.3 conclusions hhe-resultspresentedaboveshowthatadequatetimeisava'ilable ll'a I
.i for the operator to inanuall; terminate the source of dilution flow.; .Following termination of the dilution flow, the operator can initiate reboration-to recover the shutdown margin.
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. 15.4.6-S Amend. 17 7/85 ,: ,- r--+ t-r-;+--.- *.+rm-.:m-, -
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VEGP-FSAR-15 TABLE 15.4.6-1 PARAMETERS Dilution Flowrates: Initiator Flevrate (qpm) 1 63 2 120 3 3.5 4 4 130 Volumes: Mode Volume ( f t' ) Volume (gal) 3, 4 9972 74593 Sa (filled) 5239 39188 s 0150V Amend. 17 7/85 Amend. 30 12/86 Amend. 35 3/88
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,e o.i. [h LEA 3 OeuMTIONS p, , ,, 9 2 unit coMM Geo wer an. ~. AW ut.W ORD Q -Oblav, Pt 1 *' 41 UNIT NO. [) .% 6 ' DATE (O /// UNIr COOLDOWN TO COLD SHUTDOWN MANUAL SET 1.0 PURPOSE NO. !?. This procedure provides instructions for maintaining hot standby following reactor trip, maintaining hot standby following reactor shutdown, taking the unit from hot standby to cold shutdown. Instructions are provided ior maintaining conditions stable at points between. 2.0 PRECAUTIONS AND LIMITATIONS - 2.1 PRECAUTIONS 2.1.1 If this procedure is terminated prior to completion, the. Unit Shift Supervisor (USS) should note the reason for the termination in the comments section.
) 2.1.2 The Reactor Coolant System (RCS) ressure and temperature shall be maintained w thin the operating region of Figure 1.
2.1.3 Do not add positive reactivity by more than one controlled method at a time while the reactor is suberitical. 2.1.4 Whenever RCS temperature is above 160'F, at least one RCP should be in operation. Preferably Pump 4 to ensure-best spray capability. 2.1.5 The hydrogen concentration in the RCS must be reduced to less than See/kg prior to opening any RCS component. 2.1.6 The boron cos xration the pressurf zer should not be different O m the RCS y more than 50 ppm. Pressurizcz sckup Heaters may be energized as necessary r- qualize the buron concentration. 2.1.7 The Control i.od Drive Mechanism (CRDM) Cooling System shall be operating when RCS temaerature is greater then or equal to 350'F or when any C:tDM is energized. m .. _ lfbh %
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2.1.9 The Residusi Heat Removal (RHR) Pump Suction Line ! should not be isolated from the RCS unless there is a i steam bubble in Presaurizer. 2.1.10 One Reactor Coolsh. rump (RCP) should be tunning anytime RCS temperature is changed by more than 10'F in one hour. 2.1.11 Spray flow into the Pressurizer should not be initiated AF the temperature diff arance betyden the Pressurizer
- . seam space and the spray fluid exceeds 12$'T.
. 1.12 Before r.uxiliary spray is initiated with a tenperature difference between the pressurizer steam space and the sp.ay fluid exceeding 320*F, notify the USS.
(Technical Specification 5.7.1) 2.1.13 While in Hot Standby, feeding Steam Generators should
e continuous to minimize thermal stresses on the Feedwater Nozzle.
2.1.14 Vecuum should be maintained on the Main Turbine following unit shutdown until the Turbine coasts down to approximately 66% rated speed (1200 rpm) unless an emergency dictates rapid coantdown of the Turbine Rotor. 2.1.15 The Main Turbine should be kept on Turning Ge.r unti? metal casing temperatures have returned to ambient. Bearing lube oil circulation must also be maintained. 2.1.16 During periods of operation with the RCS level below the Ksactor Vessel Flange elevation (194 feet elevation), ongoing work activities should be closely scrutinized and any work activity limited that has the potential for reducing RCS inventory.
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- IMITATIONS 2.2.1 The RCS pressure and temperature shall not exceed 425 psig and 350'F when open to the RHK system.
2.2.2 While in Modes 3 and 4. shutdown margin shall be greater than or equal to the lirnit specified in Technical Specification 3.1.1.2. Figure 3.i 1. 2.2.3 While or equal in Mode to the 5, limit specified in Technicalshutdown margin shall Specification 3.1.1.2 Figure 3.1 2. 2.2.4 While in Mode 3, at leas
- two RCS loops shall be in operation with the Reactor Trip Breakers closed and at least one in operation with the Reactor Trip Breakers open. (Technical Specifications 3.4.1.')
2.2.5 While in Mode 4, at least two RCS loc.,6 a.id/or RHR trains shall be operable and at least one of the RCS loops and/or RHR trafna shall be in operation. (Technical Specifications 3.4.1.3) 2.2.6 While in Mode 5 with the RCS loops filled, at least one RRR crain shall ba operable and in operation and either one additional RHR train operable or the secondary side water level of at least two steam generators shall be greater than 17% wide range. (Technical Specification 3.4.1.4.1) 2.2.7 While in Mode 5 with the RCS loops not filled, at least two RHR : rains shall be operable and at_least one RHR train shall be it, operation. (Technical Specification 3.4.1.4.2) 2.2.8 While in Hudes 4, 5, and 6 with the Reactor Vessel Her.d on, at least one of the following cold overpressure protection systems shall be operable:
- c. . Two PORVs with lift settings which do not exceed the lioits established in Figure 1,
- b. Two RHR succinn Relief Valves each with a r,etpoint of 450 psig *3%, or
- c. The RCS depressurized with an RCS vent capable of ralieving at least 670 gpm water flow at 470 psig.
(Technical Specification 3.4.9.3) 2.2.9 While in Modes 5 and 6, at least one Charging Pump in the required boron injection flow path shall bs operable. (Technical Spec &fication 3.1.2.3)
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<. 41 2.2.10 The primary to secondary pressure differential shall not exceed 1600 paid or a secondary to primary pressure differential of 670 paid during unit operations or leak tests.
2.2.11 The maximum cooldown of the RCS shall be limited to 100'F in any one hour period. (Technical Specification 3.L 9.1) 2.2.12 The maximum cooldown of the aressurizer shall be limited to 200'F in an (Technical Specification 3.4.9.2)y one hour period. 2.2.13 The maximum temperature differential between auxiliary spray water and pressurizer steam space is 625'F. (Technical Specification 3.4.9.2) 2.2.14 The temperature of both the primary and secondary 1 coolant in the Steam Generators shall be greater than ' 70'T when the pressure of either coolant in the Steam Generator is greater than 200 psig. (Technical Specification 3.7.2) 2.2.15 While in Modes 3, 4 and 5, both channels of Source Range Nuclear Instrumentation shall be operable. (Technical Specifications Table 3.3 1, 6.B) 2.2.16 While in Modes 3. 4, and 5 at least one channel Source Ra,te Nuclear Instrumentation should be selected to Recorder NR-45 and the CONTROL ROOM HI FLUX LEVEL AT SHUTDOWN alarm operable. 2.2.17 While in Modes 5 and 6, with the RCS level below Reactor Vessel Flinge elsvation (194 feet elevation), the RWST will be operable with a minimum volume of 70,832 gallons (51 of instrument span) of water at a boron concentration between 2000 and 2200 ppm. 3.0 INITIAL CONDITIONS 3.) The reactor is shut down either following normal shutdown or withdrawn or inserted. reactor trip with Shutdown Rods either 3.2 RCS temperature is stabilized at no load Tavg under control of the team dumps in Steam Pressure mode or by operation of the Steam Generator Atmospheric Relief Valves. 3.3 RCS pressure ic< stable at normal operating pressure. l I L
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'.' E C P 12 C 9
] $ vi 41 3.4 At least one RCP is operating.
1 3.5 Pressurizer level is at ap3roximately or returning to ! the program level with eitler the Positive Displacement I (PD) Pump or a Centrifugal Charging Purp (CCP) ! operating to supply norr.a1 charging and RCP ste.1 ; injection flow. : 3.6 SG 1evels are at 45% to 55% NR level with Auxiliary ' Teedwater (AFW) operating. 3.7 The e.ain Turbine is tripped and either coasting down or on the Turning Gear. 4.0 INSTRUCTIONS NOTES
- a. This procedure is divided into sections which permit either cooldown or maintaining stable conditions within a specified mode. Section E may be performed concurrently with Sections A.B.C.D.
- b. Aster'sk (*) steps beside INITIAL steps indicatus steps that generate additional documents.
- c. This procedure is written using Train A designations. Train B component designations are shown in parenthesis.
The sections of this procedure are A. Hot Standby Following Reactor Shutdown or Trip. B. Cooldown to not less than 350'r.
- c. Cooldown to not less than 205'r.
D. Cooldown to Cold Shutdown (less
- than 200'r).
E. Secondary Plant Shutdown. l sw
~oc t 0V Liviss;N *act No l
SECTION A: Hot Standby Following Reactor Shutdown or Trip A4.1 OPERATING IN HOT STANDBY FOLLOWING REACTOR SHUTDOWN OR TRIP: INITIALS A4.1.1 If this procedure has been er.tered from a reactor trip, then perform the following
- a. INITIATE 10006-C, " Reactor Trip NA Review", L4 M- * ,
- b. If entering this )rocedure from SI termination, then perform 11886, " Recovery From ESF Actuation", bib
- c. If required, INITIATE STARTUP of the Auxiliary Boiler per 13760-C, " Auxiliary Steam Boiler .
System", Lw , NOTIFY Chemistry Deparrment, , f
- d. If ap licable, ENSURE that TDATW Pump $asbeenstoppedper13610, !
" Auxiliary Feedwater System" and i returned to STANDBY per 13610, ,V j Checklist 2 .[/k\
y
- e. When Source Range channels '
indication stabiliae PLACE CONTROL ROOH HI FLUX LEVEL AT SHUTDOWN alarm in operation by performing the-following (1) NOTIFY I&C and RESET the HI TLUX AT SHUTDOWN alarm satpoint per 24695 and 24696 "N.I. System Source Range Channel Calibration". Lf# r (2) ENABLE THE HI FLUX AT SHUTDOWN alarm by placing the HIGH FLUX AT SHUE0W NORMAL / BLOCK gpy switches to the NORMAL, _
)...
L % ~ ~ .. - - . , . - - _ __, _ __
---_.--_.s
- 1
~
, f -( N ii gf,i
~
eact No lb C a[yisioN i j VEGY 9 O 7 of ci INITIALS _ f
- (3) VERIFY annunciator SOURCE RNC F HI SHUTDOW FLUX ALARM BLOCKED d
ALB-10 B01 re se ts , LlY _ ) (4) SELECT both channels of Source
- Ran e indication on Recorder } }MO)j,-
I bR 5, l ANNOTATE chart to reflect channels selected,
- f. CALCULATE SHUTDOW MARGIN per 14005, " Shutdown Msrgin 2 / A( '
- l Calculations", '
///T _
l I g. If necessary, BORATE the RCS per > l 13009, "CVCS Reactor Hekeup V i Control System", ' N'b i h. SHUT DOWN the CVCS BTRS System by performing the followings l l (1) PLACE the CVCS BTRS SELECTOR ! l Switch HS-10351 in the OFF ;
/,a /,
l position, //' (2) CLOSE the BTRS Demineralizer i Flow Control HV-0387 to the 1 1 FULLY CLOSED position, 3,8'4,, l l ;
- 1.
- RECT Chemistry to sae.ple the RCS i i hydrogen, gas activity
- concentrations and PERFORM an RCS Iodine sample analysis per the '
i
- required frequencies of Technicel / :
I Specifications Table 4.4-4, i
/
Person Contacted n. & [c o ve ! , Datelv 7 T Time M 4'00
- j. MAXIH1ZE CVCS letdown nucification flow rate per 13006 " Chemical
- t And Volume Control System Startup And Normal Operacion ', MIN emW ddh Date Timti '
M , , b. R q3 ,s,. 7% t. r> 'O <- ' 4 e u \ J5 - i 1, . . . . f
ucci:.ut so Ltvisio8 nc.tso
. , RG P
. 1. .C 9 b-)) 8 of 41 INITIALS,
- k. MONITOR Main Turbine coastdown, (1) ENSURE that the Turning Gear / ,<
Motor Control Handswitch is hM in AUT0/ PULL-TO-LOCK position, 147 i (2) k' hen Turbine Rotor reaches zero speed, VERITY all Lift Pumps. , Turning Gear Oil Pumps ON and Turning Gear engagement. /p//_(/
,7j f
- 1. STOP both Heater Drain Pumps, l[N.
- m. STOP all but one Condensate Pump, I
- n. REDUCE in-service Condensate Demineralizer Powdex Vessels as applicable per 13616. " Condensate Filter Demineralizer System",
- o. PLACE the Condensate and Feedwater f System on Long cycle recire per /
13615. " Condensate And Feedwater - X./ Systems",
- p. NOTIFY Chemistry to initiate -
placing condensate and feedwater te l into proper chemical wet layup, I A- _
- q. If 1ecessary, SHUT DOVN all but one Cirediating Water Pump, ,/jj
/d f/
- r. If necessary, SHUT DOWN all but one River Makeup Pump and RECORD time I',[/b in the Unit Control Log Book,
- s. ENSURE SC Blowdown Isolation Valves 1-HV-7603A(B, C, D) open, jC, A4.1'.2 If Ho-Load Tavg cannot be maintained dite O to excessive steam demand REDUCE steam demand by perfoming the following s
- a. ENSURE MSR Heating Steam Supply Valves HS-6015 and HS-6030 closed, ///R[ -
- b. TRANSFER the Auxiliary Steam System e
steam su per1376$pivtotheAuxiliaryBoiler
. Auxiliary Steam System", //h'/,l
E Y.ca wo ctvmou not no VECP 12 h C 9 0 9 or 't INITIALS
- c. TRANSFER the Turbine Steam Seal supply to the Auxiliary Steam Supply ,
per 13825 " Turbine Steam Seal ..j ,y System", #-
- d. TRANST2R the SJAE steam supply to the Auxiliary Steam Supply per 13620 W
" Condenser Air Ejection System".
- e. If Main Generator is to be shut down for more than two days, then to prevent overheating relay 360A, OPEN links TBR 28, 29 and 30, located in Protective Relay Panel Bay 4, per 00306-C, " Temporary Jumper And I /
Lifted Wire Control", % A *.)6
- f. If the Generator Regulator Panel (1328-P5-CRC) is to be de-energized for maintenance, then OPEN links TBR 56 and 57 and TBS 4 and 5 located in Protective Relay Panel Bay 4, per 00306-C,
" Temporary Jumper and Liftad Wire Control". This will prevent tripping Lockout Relays 386 C9 and 4 386 G10 which trip Cenerator output /
Breakers, s. '. -
?)'gj
- g. At the Main Transforcer Control Cabincca, de-energize the Tranaformer Oil Pumps and Tans per 13800, " Main Turbine Operation" Sub-subseetion 4.3.1. //i 6 A4.1.3 Either OPERATE unit systems as necessary to maintain the unit at Hot Standby, or PROCEED to either Section B to initiate unit cooldown or 12003-C, " Reactor Startup" to return to power.
END OT SECTION A 4 lC ' (') .( f+ '$e 8. 4 9 % ,. gj , , g' ,
,e ,,,g*g, f .',
14 < ** *
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- l N # '
p-^ Mr* % J. .e , f, e, , fa re b e' h ** ed 0"
.,,e
l - . -- . . . - -
.--..,..nw.- , . . . .. ,. . .. ,.. . . . . . . . ..
Uwl: vat No LivistoN PAGt No
* . . VECP 12 -C 9 10 of 41 SECTION B: Cooldown to not less than 350' F NOTE This section directs cooldown to 375'T or any point between without crossing the boundary for Mode 4 at 350'F.
34.1 PREPARATION FOR UNIT C001DOWN INITIALS B4.1.1 If required to cooldown secondary systems, then INITIATE Section E of this procedure, B4.1.2 If Condenser vacuum is being maintained, then INITIATE placin a steam blanket on the MSR's per 13800,g" Main Turbine d Operation". B 4 .1. 3 - INITIATE pressurizer and RCS boron equali:ation by energizing Pressurizar <\ Backup Heaters. % __-/- 4 B4.1.4 MAXIMIZE CVCS letdown pu, yification NR flowrate. date/ time
~
N /'\ L B4.1.5 INITIATE Borating the RCS to the cold shutdown boron concentration ser 13009, .d "CVCS Reactor Makeup Control System". wF u If applicable, PERFORM 14835, " Boric - Acid Injection Check Valve Cold Shutdown
- Inservice Test" during the boration. C <. -
B4.1.6 DIRECT Chemistry to sample the RCS and eJ INI Pressuriser boron c centration. If withdrawn, INSERT all Shutdown B4,1.7 Banks to the fully inserted position. Ml a B4.1.3 OPEN the Reactor Trip breakers. s W] r i L a..,
, - _ ~ . . ,_ . . - _ , _ . , . . . . - _ . . ~ . _ . _._ . . . _ - . . . _ _ . _ - _ _ _ _ . . _ . - _ - - . _ - . . _
^
cameow not No l'
]
O
*-oct:.*t No
,, VEGP 12h".C 9 li or 42
< i INI'"I ALS .
B4.1.9 If not currently in progress, ; INITIATE RCS gaseous activity degas by performing the following
- a. ENSURE that the Pressurizer Steam Space Sample line is in operation by verifving that ,
the FRZR STM SAMPl.E IRC/ ORC Valves HV-3513/HV-3514 are . open, -t -s MO !
- b. NOTITY Chemistry to adjust the pressurizer steatn space sample t' t .
n Jw rato to maximum, /t/ M -
- c. While maintaining hydrogen cover gao, DEGAS the RCS by raising t VCT gas purge flow rate to the Caseous Waste Processing System to approximately 1.2 scfm using HIC-1094, as limited by the Hydrogen Recombiners. #y/A_ A E4.1.10- Vhen notified by Chemistry that the l RCS gaseous activity has been reduced to an acceptable level. TPMSFER VCT :
cover gas to Nitrogen and INITIATE RCS Hydrogen degas per 13007, "VCT Gas Control And RCS rhemical Addition". &g M NOTE Prior to opening the RCS to containment the hydrogen concentration shall be less than 5 cc/kg. M .1.11 START both Containment Pre-access Tilter Units FAN HS-262 usinh/2621.WC
- 2 CTB PREACCESS TLTR UNIT-1/2M '-c o ^ m * ' ' g'""'
p ' date/ time D4.1.12 If it is planned to cool devn to Cold Shutdown, and if not perforced in the revious three months, COMPLETE 14748, p'AW Check Valve Shutdown Inservice Test". _ k X (f(j y, g ( cf/A% (w /?h )4'i , n .. ,. ., , ,, , , . . , . ,,,-a ,+-,,._...,...,-.._.-.,.,--e . - - , - . , , , . , - , . . , , , - - , . - , , . ~
E, M9 ract evo w, ;t;. St to
* 'EG P 1."thI.C 9
() 12 of 41 j INITIALS B4.2 RCS C00LDOWN TO 375'r B4.2.1 COMMENCE RCS/ Pressurizer pressure and temperature trending at 30 minute intervals using Data Sheet I and ERT computer. (Technical Specification 4.4.9.1) Data tsking and plotting may be suspended during holds in the cooldown if the duration is expected to exceed one hour. NOTE It is recommended that the RCS temperature be maintained between 75' F and 125' F less than aressurizer temperature. (See figure 1.) B4.2.2 COMKENCE the cooldown to 375'F and 540 psig at a recommended rate of approximately 50*F per hour by performing the followings
- a. REDUCE the number of operating RCPs to two per 13003, " Reactor Coolant a Pump Operation", evM T- .ps 4 and 1 are the preferred running pumps,
- b. INITIATE Pressurizer cooldown and f depressurization by slowly opening , ,[n;'
the Pressurizer Spray valves. If necessary, selectively DE-ENERGIZE Pressurizar Back-up Heaters by alacing
. Control Switches to PULL-TO-LOCT, CAUTION RCS temperature and pressure shall be maintained within the acceptable operating region of Figure 1.
- c. Slowly ADJUST the Steam Dump Controller setpo:.nt or if applicable the Atmospheric Relief Valves to initiate '
RCS cooldown. (D
. .n
._-_m.m.--m ,a, e ..m.,%.,~,,,%m w e , ,._.,,_,,,.,_,,_.,__.,..__m . _ , . - . . , - _ , . . - . - - - . - - - - , . - -
" '~ ~
' .' ac:tc at u 9" wos not No
.,. . VEGP 12klh-C i
9 (") 13 of 41 ) INITIALS B4.2.3 At approximately 2185 psig, OBSERVE PRZR PORV BLOCK VALVES HV-8000A and HV-8000B auto close. NOTE Depending on the rate of RCS l cooldown and depressurization, 1 Step B4.2.5 may occur before Step B4.2.4 ! B4.2.4 At aparoximately 550'F RCS temperature l PERFO.(M the followings
- a. VERIFY status light LO LO TAVG TRAIN [
A STEAM DUMP INE P12 illuminated, x ;
- b. BYPASS the LO LO TAVG interlock by momentarily placing the Train A and B Staam Dump Interlock Selector :
Switches to the BYPASS INTERLOCK a A, position, .)N If o:serating on Steam Dumps, then VERITY Steam Dump Cooldown Valves , PV-0507A,B and C are open by 4Q observing ZLB-2 on QMCB, '- CAUTION If the RCS is allowed-to prussurize above P11 and SG : pressure is below 585 psig, -
-Safety Injection and Steam Line Isolation will occur.
84.2.5 At approximately 1970 psis, manually BLOCK Pressuriser Pressure and Steam Line Pressure Safety Injection and Steam Lina Pressure Steam Line Isolation signals by performing the following
- a. It is is planned to cool down for refueling, then PERFORM 14710
" Remote Shutdown Panel Transfer Switch And Control Circuit 18 Honth -
Surveillance Test" Data Sheets 3A and 3B in lieu of the following p g substeps, p-
- b. VERITY Block Permissive Status Light PRZR LO PRESS SI BLOCK PERM P11 illuminates, ~M .
- m,
= -. .. . . - --
,% .m NoCthct No G(villoN 84GLNo .
9 14 of 41 VEGP 12((>C ({} INITIALS i
- c. BLOCK the Low Pressurizar Pressure !
Safety Injection signal using , PRZR PRESS SI BLOCK / RESET A and B handswitches HS-40012 and 40013, : 4
- d. OBSERVE Status Lights PRZR TRAIN A/B ' pf" SI BLOCKED illuminated, [
- e. BLOCK the Low Steam Line Pressure !
Injection si SafetbSSSI/SLIBLhnalusingLOW STM P handewitches HS-40068 and 40069, CK RESET ** '$~h : t
- f. OBSERVE Status Lights STMLINE ISO .. bj i
TRAIN A/B SI BLOCKED illuminated. .-_. B4.2.6 CHECK that Pressurizer level is between ogk : 20% and 40%. B4.2.7 As RCS pressure lowers 0 PEN additional i Lcedown Orifice Isolation Valves and ' ADJUST PIC-131 setpoint to maintain desired letdown flowrate. B4.2.8 During RCS depressurization, MAINTAIN all - RCP seal injection flow rates botveen 8 and 13 gpm by adjusting the Charging Header Flow Controller HC-0182. B4.2.9 At approximately 950 psig ISOLATE ECCS , Accumulators by performing the following: ,.
- a. REMOVE TAG, UNLOCK and CLOSE the '
Accumulator Discharge Isolation Valve 480V HCC Breakers: UNIT 1 UNIT j[ ACCUH-1 1ABE-19 2ABE-19 _
- ACCUH-2 1BBC-19 2BBC-19 . k! ~
ACCUH-3 1ABC-19 2ADC-19 / L ACCUH-4 1BBE-19 2BBE-19 ,, f __ l I i L
- L ,
'nen l
, , , , , - - ~ ~ . . m._.-. .
. ~ . = . ,
WoGthCE No KEYllioN P5t id i
-*- "EGP 12 C 9 15 of 41 l 1
INITIALS , I
- b. CLOSE the Accumulator Isolation Valt s.
ACOUM-1 HV-8808A, /N ACCUH-2 HV-8808B, ll'V f ACCUM 3 HV-8808C, #V ACCUM-4 HV-8808D. 4// -
- c. VERITY annunciators ACCUM TANK '
1(2,3,4) ISO VLV 8808A(5,C,D) NOT FULLY OPEN in alarm. x ALB06-A05,505,C05,D05. -- J. N j
- d. OPEN, LOCK and TAG the Accumulator Discharge Isolation Valves 480V HCC ;
Breakers, i UNIT 1 UNIT 2 ;
/ .
ACCUM-1 1ABE-19 2ABE-19 TD ;v ACCUM-2 1BBC-19 2E3C-19 . t w
'TO -
t j AccVM-3 1ABC-19 2ABC-19 m l'I Iv' ACCUH-4 IBBE-19 2BBE-19 . l q
, zy
.B4.2.10 When steam pressure-falls too less '
than 550 psig. at the USS's. discretion the Steam Generaters may be supplied ... by the running Condensate Pump per i~ Section E4.2 of this procedure. t
**1est
- . . . _ - - , - _ , _ , _ , _ _ _ . _ . _ . . , , , ~ . _ .,..._.._..,-..._.s...-....,_ -
rec.; t :,, a t No at vision pact .o
. 4 VECP !? C 9 1( of 41 INITI ALS, B4.2.11 Either OPERATE unit systems as necessary to maintain RCS within the following parameter values or PROCEED to either Section C to continue the cooldown or 12002-C, " Unit Heatup to Normal Operating Temperatur( and Pressure" to com: ence a heatup. ,
RCS te:nperature 375*F *10'T RCS pressure $40 psig *25 psig Pressurizer level at program level END OF SECTION B r...
esGt No ~~l esccip.a t Nm VTCP 12()C ntvisioN 9 () 17 of 41 SECTION C: Cooldown to not less than 205'r fl0TE This section directs cooldown to 225'T or any point between without crossing the boundary for Mode 5. C4.1 PREPARATION FOR CONTINUING UNIT C00LDOWN. INITIALS C4.1.1 If required to cooldown secondary systems and break condenser vacuum, then INITIATE SECTION E of this procedure. CAUTION Maintain pressurizer cold L calibration level greater ' than 171. C4.1.2 If it is planned to cool down to cold shutoovn, then ALLOW pressurizer level to rise duririg the cocidown to not steater than 801 cold calibrate, C4.1.3 C0KKENCE RCS/Pressuriter pressure and temperature trending at 30 minutes intervals using Data Sheet 1 and ERF computer. (Technical Specif :Ation 4.4.9.1) _ Plotting may be suspended during holds in the cooldown if the duration is expected to exceed one hour. e t!
. 33;;td.otNo giv$ sos Pact No f** . VECP 12[c_)' - C 9 (-) 18 of 41 4
INITIALS C4.2 RCS C00LD0VN To 225'F. NOTE It is recommended that the RCS temperature be maintsined between 75'T and 125'T less than pressurizer temperature. (See Figure 1.) C4.2.1 COMMENCE the cooldown to 225'T and 250 psig at a recommended rate nf approximately 50 F per hour by performing the following:
- a. CONTINUE the pressurizer cooldown and depressurization by slowly opening the Pressurizer Spray Valves, llh/
If necessary, selectively DE-ENERCIZE Pressurizer Backup Heaters by placing Control Switches to PULL-TO-LOCK, CAUTION RCS temperature a :d pressure shall be maintained within the acceptable operating region of Figure 1.
- b. Sieuly ADJUST the Steam Dump Ccntroller .etpoint or if applicable the Atmospheric Rs11ef Valves to initiate RCS cooldown, ZOk' ,
C4.2.2 If it is planned to cool down for refueling, then prior to reaching 350'F, EQUEST confirmation from Engineering /Haintenance that actions have been taken to preclude Reactor Vessel Seismic Tie Rod Binding. < C4.2.3 Prior to reaching 350'F. NOTIFY Chemistr to isolate PERHS CVCS Letdown onitor RE-48000, 48V
~
_ _ _ _ . . _ _ _ . _ . _ _ _ . _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - ' '-"'J
m L. 0;t cV-( Ne Lt vision P GENO r] 3 19 of 41
. VECP 12C J C 9 (j INITIALS C4.2.4 Priot' to reaching 350'F, PLACE the Cold overprusure Protection System (COPS) in operation by performing the following:
- a. If not performed in the previous three months, PERFORM 14860 V Cold Shutdown Inservice
- b. ARM the A and B COPS by placing the PRZR PORV BLOCK VLV COLD OVERPRESSURE CNTL handswitches HS-80000 and 8000H to the ARM position, /f "
- c. VERIFY the following annunciators alarmed upon arming COMS:
A COLD OP ACTU VLV HV-8000A NOT
' FULL OPEN (ALB12 E06), UT' B COLD OP ACTU VLV HV-8000B NOT FULL 02EN (ALB12 F06),
gy,
- d. ENS!T4i ?R2R PORVs PV-455A and 1-PV-456A are closed and the 20, handswitches in AUTO, ,
- e. ENSURE OPEN PRZR PORV BLOCR 4N, Valves HV-8000A end 8000B, _
NOTE Step f satisfies Technical Specification surveillance 4.4.9.3.1.,:
- f. VERIFY the following annunciators reset:
A COLD OP ACTU VLV HV-8000A NOT lly FULL OPEN (ALB12 E06), ,_ B COLD OP ACTU VLV HV-8000B NOT FULL OPEN (ALB12 F06). _
/[V C4.2.5 At 350'F, LOG time and date of entry into Mode 4 in tne Unit Control Log Booh.
(jf/Pt / /S30 llV date/citre I m.o l
" #act No
---~oC L D4 t t N ot r LtusioN YEGP 12(j, C 9 20 of 41 INITIA1.S C4.2.6 Within 4 hours after entering Mode 4 and prior to reaching 325*F PERFORM the following
- a. RACK OUT and TAG both safety Injection Pump Breakers, UNIT 1 UNIT 2 S1 PMP-A 1AA02-16 2AA02-16 Tb ,
S1 PMP-B 1BA03-17 2BA03 17 Th NOTE ATWAS should be defeated to the 6G Blewdown Valves Sample Valves and MDATW Pump Discharge Valves to acconanodate HTP activities and/or 50 draining / filling operations without resulting in impacting those activitias,
- b. At the USS's discretion, REMOVE and TAG the following fuses:
i (1) Train A .. (a) Auxiliar Panel - Fuse Blo k $fovsfull use of SG Blowdown valves), , UNIT 1 UNIT 2 1ACPAR 6.i.'U-2 u ms s j 7.,,,.e 2ACPAR6-FU-2 Y[ -
~ .Ic .' 4 < 4 <e e. r. ..o /0 0 T-' l
. . , d IV A :-
(b) Auxilji y Relay Panel - Fuce h 3 ck (Inhibits feed pump t!.hprignalto initialN AFVAS), ' tmIT 1 UNIT 2 INCPAR-2-FU-4 2NCPAR-2-FU-4 TO
&~ . I y I'1 tee /
th! IV
.w/, ,
!* ft . 34 3 n..,
N '"*"T N "' N m . .. , .- ._
W.;t;.Ct No t.tyision pact no
.. . VECP 12(~ -C 9 21 of 41 .- i INITIA1.S (2) Train B (a) Auxiliary Relav Panel -
Fuse Block ( Allows l'111 une of SC Blowdown valves), UNIT 1 UNIT 2 /% 2BCPAR7-FU-6 ' IBCPAR7,-FU-6
,..... . . . i. . s..,. * ,, . 3 IV (b) Auxiliary Relay Panel -
Fuse Block (IMitbits feed pump trip signal to initiate ATWAS), UNIT 1 UNIT 2 INCPAR-4-FU-1 2NCPAR-4-FU-1 O[ L'l'," # ^ ' w< f ^:ll:L I w ye y zy
- c. PLACE standby MDAFW Pumps handswitch in PULL-TO-LOCK. g
- d. If the TDAFW Pum) is not being utilized, CLOSE IV-5122, 5125, 5127 and 5120. /_14
* :ent
+ * 'd
*C t .8t 4 & Ltvist0N PAGE No
, , VEGP I W 6-C 9 22 of 41 4
INITIALS C4.2.7 When the RCS pressure is less than 377 ; psig, and RCS temperature is less than l 340 F. PLACE at least one RHR Train in ! operation per 13011. " Residual Heat I Removal System". Mf l
- a. OPERATE RHR HX Outlet Valves HV-0606(0601) and Bypass Valves TV-0618(0619) to control RCS temperature as necessary and RHR flow at a minimum total flow of 3000 gpm,
- b. If applicable, PERFORM 14896, "ECCS Check Valve Cold Shutdown )('
Inservice Test". FJ h *
- c. ENSURE RHR Suction Isolation surveillance is initiated each shift per 14000, " Shift And Daily Surveillance Logs".
CAUTION While in Mode 5 with the Reactor Coolant Loops filled, with 1 RHR Train inoperable, the secondary side water level of at least two Steam Generators shall be greater than 17% WR. r C4.2.8 If desired, REDUCE the number of operating RCPs to one per 13003, " Reactor Coolant . f. /l;,j Pump Operation", Pump 4 is the preferred running pump to ensure best spray capability, C4.2.9 When SG pressure falls to 25 psig INITIATE aligning Nitropen to the SG's per 13601, " Steam Generator And Main Steam System Operation" with regulators set at 2 to 5 psig. C4.2.10 If it is intended to serform maintenance on the RAT's during tie outage, then NOTIFY Haintenance to initiate work towards backfeedin TransformerandUAh'throughtheMain
- s. N
,k ie 'y qu .M ;~ M o M- S l
.-N .g' 4g oAy.%cc-'d) s\ .-
I ma vu u c t-y hb. p ,,p.19
P-QC[ * ,ct No VECP
/
12v-[+ - C Givi58oN 9 w PAGL No 23 of 41 ' INITIALS C4,2.11 Either OPERATE unit systems as necessary to maintain RCS within the following parameter values or PROCEED to either Section D to continue the cooldown or 12001-C. " Unit Heatup to Hot Shutdown" to commence a heatup. CAUTION Ensure running RCP seal differential pressure is maintained greater than 200 psid. RCS temperature 225 F *10*F RCS pressure 250 psig A25 psig END OF SECTION C men 99muuuuuuuuuuuuuuuuume .-.e -
._. _ _ m _ . ___ -
~
'. Paoc tl:v-t No ]
If-,6-C CfVill0N / \ PAGEtwo
. VEGP 9 U 24 of 41 SECTION Dr Cooldown to Cold Shutdown (less than 200*F).
NOTE This section directs cooldown
. to Mods
- and maintains temaera._re between 130'T and 80'?.
D4.1 PREPARATION FOR CONTINUING UNIT C00LDOWN INITIALS D4.1.1 If required to cool down secondary systems and break condenser vacuum, then INITIATE ' Section E of this procedure. D4.1.2 COMMENCE RCS/ Pressurizer pressure and temperature trendinF at 30 minute intervals using Data Sheet 1 and ERT Computer. (Technical Specification 4.4.9.1) Plotting may be suspended during holds in the cooldown if the duration is expected to exceed one hour. D4.1.3 ENSURE RHR letdown is in operation with flow rate greater than or equal to 75 gpm. 4/' V D4.2 RCS C00LDOWN TO BETWEEN 130*F and 80*F D4.2.1 COMMENCE the cooldown at a recommended rate of approximately 50*F per hour by perfor.ning the following
- a. Slowly ADJUST the RNR Outlet Valves NV-0606(0607) to reduce RCS tetaperature , Ll'V CAUTION Ensure running RCP seal differential pressure is maintained greater than 200 psid. ,.
- b. MAINTAIN Pressurizer pressure at 250 psig by selective use of
*25 Pressurizer Bac psig,kup Heaters. /l'V h.
~~
, H ~ . p:cctTJt ~o h not no dr
. VECP I U 6-C ! cim.oN 9 25 of 41
= I INITIALS, D4.2.2 at 200*F, LOG time and date of entry i into Mode 5 in the Unit Control Log Book. 4A l 192*/ tolo2ftf time /date l l'
D4.2.3 RACK OUT and TAG the Containment Spray pump breakers. UNIT 1 UNIT 2 CS PHP A 1AA02-14 2AA02-14 dd CS PMP B 1BA03-14 2BA03-14 M D4.2.4 As directed by the USS, PLACE the Conesinment Pre-access Purge System in operation ?'- Purge System"per 13125, " Containment
. /
- I' D4.2.5 To facilitate personnel ingress and egress, during cold shutdown, NOTIFY Haintenance to bypass the Containment Personnel Lock Interlock System.
If desired the Containment Equipment , Hatch 'Aissile Shield may be moved at ' this time. D4.2.6 NOTIFY Work P19nning Group to schedule ! and initiate mode dependent Fire f , Protection Surve111ances. M/CN' ' i D4.2.7 When the RCS tem >erature is lean than 140*F, PERFORM the followings
- a. If withdrawn, INSERT all Shutdown Banks to the fully inserted position. _,
g
- b. OPEN the Reactor Trip Breakers, db
- c. STOP the CRDM Cooling Fans using the following handswitchess CRDM UNIT - FAN 1 HS-12273A. ~,,,
CRDM UNIT - FAN 2 HS-12274A, l CRDM UNIT - FAN 3 HS-12275A, i CRDM UNIT - FAN 4 HS-12276A. WT l. ,-
- d. If it is intended to remain in cold shutdown PLACE theforSG' s greater than 4per in wet layup days, 13601,then
" Steam Generator and Hain Steam System fI Operation", VL
'"" l
<r Al y% &t J:~f6{.
s - ~ ,
p:ces:,et 80 ctvisivw a not ho j
, VECP 1.f_,a
%,-C @ 26 of 41 l INITIALS NOTE The RCP(s) shall be run for one or more hours after reaching the desired RCS temperature plateau to enhance SG and RCS temperature equalization. ZPv __
D4.2.8 Vhen RCS temperature is less than 110'F, ped por the remaining 13003. " Reactor RCPs mayPump Coolant be stobperation". //'j D4.2.9 If it ie desired to collapse the pressurizer bubble and cooldown the pressurizer, then PERFORM the following
- a. ENSURE all CVCS Letdown Orifices are ,g,/
in operation, uv CAUTION Expect rapid pressurizer pressure rise with charging flow greater than letdown flow at the point of going solid. Be prepared to reduce charging flow or raise letdown flow to prevent extreme pressure fluctuations.
- b. RAISE pressurizer level by raising charging flow rate and/or lowering RHR letdown flow rate, ,
/['k'
- c. When the pressurizer is solid as indicated by risin g RCS pressure or if PIC-131 is in A JTO rising letdown flow rata, then PERFORM the following (1) BALANCE charging and letdown flow rates using HV-0128 and/or PIC-131 to ma'arsin RCS pressure at 250 psig *25 psig, //
n.n i 4 . , e .
- - -- - , . _ - --.a
~~ ~ '*
Ploctht!No LtvisiON 40 "O VECP 1 m 6-C 9 27 of 41 l
^
INITI A1.S l NOTE Charging flow may remain greater than letdown flow as a result of i coolant contraction during the co.31down. (2) Charging /RHR letdown flow rate should be adjusted so that R!R letdown purification flow is maintained greater than or equal to 75 spm, t.O' (3) OPEN Pressurizer Auxiliary Spray valve HV-8165 [li, (a) INITIATE AUX SPRAY /PRZR DELTA-T surveillance per 14915. "Special Conditions Surveillance Loss". (Technical Specification . 4.4.9.2), ( '< A (b) If pressurizer auxiliary spray water delta-T exceeds 320 F, then LOG the spray valve operation in the Unit Control Log and NOTIFY Engineering to log the cycle per 50040-C, " Component
- Cyclic or Transient Limits". D1 *
(4) CLOSE the open Charging Isolation Valve HV-8146 or HV-8147, i fu _ (5) Continue CHARGING through the pressuriser auxiliary spray line until pressurizar steam space ,s temperature is less than 190'F. L D' 04.2.10 MAINTAIN RC3 temerature between 130*F and 80*F using RiR HX Outlet Valves HV-0606(0607), ( Os _ NOTIFY Engineering to log the unit , cooldown per 50040-C " Component (3-
\gJ*
Cyclic or Transient Limits '. . hLID (, tdCD2 Li 400t il s10(- i f0M t Fic O l 1010 M GNW t w.,
re au.. ' t no ctvnsac8
. . . . VEGP 12()-C 9 lhP 28 of 41 INITIALS CAUTION Ensure all RCP's are shutdown.
D4.2.11 If it is desired to depressurize the RCS, then PERFORM the followings
- a. INITIATE Lovering RCS pressure to atmospheric (50 psig as indicated i on PI-408, 418, 428 or 438) Jaing i letdown pressure control PIC-131, _['ilt !
- b. When RCS pressure reaches 100 psig (150 418, psig 428, as indicated 438) CLOSEon PI-408, cil RCP Seal Leakoff 1:elatI on valvss !!V-8141A, B, C D. (h
- c. ENSURE PRT nittogen pressure is maintained greater than 0.5 psis. [0,>
NOTE St Pop Cold Leg Isolation valves are closed to preclude inadvertent draining of RWST to the RCS while the RCS is depressurized and partially drained. D4.2.12 ISOLATL che Safety Injection Cold legs by performing the followlngi
- a. CLOSE SI PHP-A TO COLD LEG ISO VLV HV-8821A, (33s
- b. CLOSE SI PHP h TO COLD LEG ISO VLV ' '
KV-88211, /A
- c. OPEN and TAG the following SI Cold Leg Isolation Valves HCC breakers l
UNIT 1 tutIT 2 (1) SI PHP-A TO COLD LEO ISO ,. l VLV HV-8821A, 1ABD-15 2ABD-15 ( (\- _ s (2) SI PHP-B TO ! COLD LEG ISO VLV HV-88215. 1BBD-15 2BBD-15 / Os l . w.s
'.. t .
9 -
. Y atvisiow 841 No l
*-ec c.
- g l
P' INITIALS CAUTION ; Frior to opening the RCS to the contAiament atmosphere, the RCS hydrogen concentration shall be less than 5 cc/kg. D4.2.13 When required, INITIATE RCS draining by perfoming the following
- a. If it is intended to drain down to 1-perform maintenance on Reactor Head, SO's or RCP seals, then the following RCS level controls should be placed into effect (1)
If it is intended to operate at one foot above mid nozzle level, the preferred RHR configuration is one train operating with a flow of 3000 Ps, di (2) If it is intended to operate et one foot above mid nomale level, a minimum of two incore thermocouples should be available during periods where the Reactor Head is installed, ,-- l (3) I&C should be notified to install temporary remote RCS level monitoring in the Control Room, 3T, (4) Tyson tube watch is require' any time the RCs level is beina changed while the RCS level is below 171 - (approximately 207 feet elevation) pressuriser level, Ms (5) Periodic comparison checha should be made every 4 hours between the Control Roc,a ,. Tennorary RCS Level McY tors and' the T',,;on tube, #I (6) The Control Room Honitors should agree within 2 percent of scale with the Tyson tube, ' l o . .. l L - _ r.____.__-- .--- _.
* ~~^
.4&ct0WENo P*Qt No 9 jl h l 0.tyttioN
- . .. , VEGP 12 k-C 30 ot 41 INITIALS (7) Two .st of three Level Monitors must agree before draining RCS below the top of the hot leg (188 feet 3 inches),
(8) If neither Control Room RCS Level Monitor is available, then a conttnuous Tyson tube watch should ba established while RCS level is below 171 pressuriser livel, 8"T'__ (9) While operating with Steam Generator Nozzle Dams installed. ENSURE one Safety Injection Pump is capable of being racked in and operated if needed, (10) While level to in the region of the hot legs, TREND RER Pump Parameters on ERF for early detection of possible RHR Pum degradation due to vortexing.p (11) Minimum RCS level is one foot above mid-nozzle (188 feet
. O inches elevatica) except for Steam Generator burp.tp,g during initial drain down. cor effective SG tube draining RCS level should be lowered to 187 feet 6 inches. Upon completion of 50 burping RAISE RCSlevelto188 feet-binches '
and MAINTAIN at this level i) jg thereafter. N' (12) INITIATE draining the RCS per l 13005, " Reactor Coolant
. System Draining".
4
,P
'unes
~
_ li ~~.
, , PCIG;[;.C6 h5 'lg yrgidh~ C&G[ pio INITIALS D4.2.14 If it is intended to drain the RCS to less than 25: cold calibrate crassurizer level, then prior to reaching 25% ISOLATE ' potential dilution flow paths by performing the following
- a. CLOSE, LOCK and TAG the following valves (1) UNIT 1: CVCS ISOLATION RMW TO BA hEND, 1-1208-U4-175 M UNIT 2: CVCS ISOLATION RMW TO BA BLEND, 2-1208-U4-175 [,//-
(2) UNIT 1: CVCS ISOLATION RHW TO CVCS 1-1208-U4-1f7 ,, Ji h UNIT 2: CVCS ISOU. TION RHW TO CVCS, 2-1208-U4-177 A)/d be ENSURE CLOSED, LOCKED and TAGGED the following valves (1) UNIT 1: CVCS OUTLET CHEM MIXING TK -- 1-1208-U4I181 .I)y\ UNIT 2: CVCS OUTLET CHEN HIXING TK, 2-1208-U4-181 /\k I (2) UNIT 1: CVCS SUPPLY RHW TO CHEM HIXING TK, 1-1208-U4-176 s.) h, UNIT 2: CVCS SUPPLY RML' TO CHEM VI" .G TK , yl 2-1208-Ut.-1: 6 * - , i i wo se
m l .
.. .. ,- #' HEN 12h-C 9 h "
32 of 41 INITIALS (3) UNIT 1: CVCS FLUSH RMW
- TO TRN A EKERG BORATION ,
1-1208-U4-183 JNik UNIT 2: CVCS FLUSH RMW TO TRN A EMERG BORATION 2-1208-Ud-181 PJl/b (4) UNIT 1: RMWST TO BTRS ISO, , 1-1208-U6-226 Td i UNIT 2: RHWST TO BTRS ISO, 2-1208-U6-226 rd'[F
- c. makeup to the VCT by
. When performingnecessary,followingi the (1) OPEN RWST YO CCP A & B SUCTION Valves LV-0:12D and LV-0112E, (2) CLOSE VCT OUTLET ISOLATIONS, LV-01128 and LV-0112C, (3) ENSURE Letdown to VCT or Hold-up Tank Valve LV-0112A is in the VCT position, ,
(4) When VCT level has been returned
,to normal, OPEN LV-0112B and LV-0112C then CLOSE LV-0112D and LV-0112E.
D4.2.15 OPERATE unit systems as necessary to maintain the-above conditions,
- a. If required to break condenser vacuum, then PROCEED to Section E. (
l
- b. If it is intended to proceed to :
Moda 6, then Go to 12007-C.
" Refueling Entry",
- c. If it is intended to commence unit heat up, then Go to 12001-C, " Unit Heatup to Hot Shutdown".
END OF SECTION D
,$30$
- - - .,._u
' **C;f;,. a f No I fit vi5 ton PAGE ho s.
'JEGP l h 6-C 9 O 33 or 41 l.,,., SECTION E. Secondary Plant Shutdown NOTE This section directs secondary plant activities during unit shutdown and can be used in conjunction with primary system coc1down operations.
/
6 The subsections of this section are: E4.1 Transfer From Steam Dumps to
/ ,
Atmospheric Relief valves. E4.2 Feeding Steam Generators With Condensate Pump.
- E4.3 Breaking Condense.c Vacuum.
E4.4 Secondary Systems activities. E4.1 TRANSFER FROM STEAM DUMPS TO ATMOSPHERIC RELIEF VALVES - l INITIALS E4.1.1 TRANSFER to the SG Atmospheric Relief Valves by performing the following
- a. Slowly OPEN each atmospheric p l
i relief while verifying a reduced , sham dump demand signal on 1 / UI-507, yIV f
- b. VERIFY that.the Steam Dump
! Control Valves close if PIC-507 is in AUTO or if operating c in MANUAL, slowly CLOSE the - l Steam Dump control Valves - f while opening each atmospheric L relief, \,6 I1d L ! c. When all Steam Dump Control e i Valves ree closed ENSURE ,(
/,.) ( I/
PIC-507 is in MANUAL, L
- d. BALANCE the positions of each .
atmospheric relief while '1; maintaining Tavg as desired. ! i l l c= pn
act 9,[ g Ar.Ect. j t . 1 INITIALS E4.2 FEEDING STEAM GENERATORS WITH CONDENSATE ' PUMP E4.2.1 At the USS's discretion, INITIATE I feeding Steam Generators with the running Condensate Pump by performing the following:
- s. VERIFY SG pressure is less than 550 psig,
.)) r A///q_ i b VERIFY that tube oil pressure to the reset HFP and MFP Turbine Fearings is 10 to 12 psig by local indications, U'lh
- c. OPEN the reset MFP Discharge Valve by placing the Control Switch in OPEN-PULL-To-LOCK at the Main Control Panel QMCB: b.JIl4 SGFP A HS-5208, SGFP B HS-5209.
- d. If not previously performed, RESET both trains of Feedwater Isolation:
(1) HS-40049 for Train A, b h (2) HS-40050 for Train B. d' 4
- e. OPEN all PFIV's, bf4
- f. CONTINUE maintaining desired SG 1evel utilizing the BFRV's. bk l
l
- ..t
~~ '
. . & LEE; 4E No g. CEyl54oE~ T # AGE 4 ~
1.g)6-C
' T'ECP 9 [V ~ 35 of 41 INITIALS E4.3 BREAKING CONDENSER VACUUM E4.3.1 If necessary, TRANSFER the Auxiliary Steam System steam supply to the Auxiliary Boiler per 13761, " Auxiliary Steam System" j
E4.3.2 TRANSFER the Turbine Steam Seal supply A "toTurbine the Auxiliary Steam Steam Supp per 13825, 1 Seal System,1y . W [() E4.3.3 TRANSFER the SJAE steam supply to the Auxiliary Steam Supply per 13620, J
" Condenser Air Ejection System". V) __
E4.3.4 CLOSE the HSIVs and Bypasses. t k CAUTION Breaking condenser vacuum will result in a MFPT Low Vac Trip. If AFWAS has not been defeated, then both MFPs tripped will result in a AFWAS initiation. E4.3.5 PLACE the standby HDAFW Pump (s) Handswitches in PULL-TO-LOCK. l' Dj E4.3.6 BREAK condenser vacuum and SHUT DOWN the Steam Jet Air Ejectors and the Condenser Vacuum Pumps per 13620
" Condenser Air Ejection. System".
E4.3.7 PERFORM the following to reset the AFWAS signals
- a. RESET the AFWAS by resetting one MFPT Low Vacuum Trip by
. , momentarily placing the MFPT-A(B)
VAC TRIP BWASS Handswitch to RESET position and MFPT A(B) TRIP RESET HS-3169 (3170) to the ,)/
~
RESET position, ,
/V/
- b. If running a MDAW Pump, then THROTTLE- the AW Flow Control Valves to the pre-initiation A l i f, flow rate, JUI P l
i d
n,c iso . .. m.oe, not no 36 of 41
,- 'a V E ".*' 1.Y. 6-C 9 hec INITIALS
- c. If applicable, ENSURE the SG Blowdown Isolation Valves HV-7603A(B C.D) open. M/A E4.3.8 After the condenser pressure reaches atmospheric, SHUT DOW the Turbine Steam Seal System per 13825. " Turbine Steam
. Seal System". fj.D5 E4.3.9 MAINTAIN the main Turbine and MFPTs on Turning Gear per 13800, " Main Turbine Operation" and 13615. " Condensate and Feedwater Systems".
E4.4 SECONDARY SYSTEM ACTIVITIES E4.4.1 If condensate and feedwater cleanup is not anticipated, then when condensate and feedwater metal temmeratures are less than 200*F, SHUT DOWN the Condensate and Feedwater System per And Feedwater Systems,1,3615, Condensate ITCCb E4.4.2 NOTIFY Chemistry and SHUT DOWN the Condensate Filter Demineralizer System ber13616,"CondensateFilter emineralizer System". (3$h) E4.4.3 If the secondary outage is planned to exceed 10 days, then PERFORM the following
- s. When condensate and feedwater metal l temperature is between 90*F and 200 F, COORDINATE with Chemistry and PLACE the Feedwater Heaters in wet layup, (h 5 I b. When Turbine metal temperatures reach ambient, REMOVE Turbine from Turning Gear per 13800, " Main Turbine Operation",
d(og
- C-
- c. During the unit outage, once a week, PLACE the Turbine on Turning Gear for 4 to 6 hours.
1 I l h$
*
- I;octDWE No ~divistoin 8 AGE No
,' 9O VECP b%)06-0 37 or 't INITIALS E4.4.4 If required, PLACE a steam blanket on the MSRs per 13800, " Main .
Turbine Operation". kb E4.4.5 If required, for condenser Waterbox or Circulating Water System maintenance, SliUT DOWN the Circulating Water System per 13724, " Circulating Water System". D If required for maintenance or inspection, then INITIATE draining of the Condenser Waterboxes per 13724 " Circulating Water System". [7% E4.4,6 If main generator maintenance or inspection is planned, then INITIATE the main generator per , purging" 13810 Generator Cas System". cs If hydrogen atmosphere is to be maintained, then HINIMIZE usage during the outage by reducing hydrogen pressure to not less than 5 psig. E4.4.7 SHUT DOWN the Isophase Bus Duct Cooling System by performing the following:
- a. At 4BOV AC SVGR NB03, OPEN Isophase Bus Duct- Heater Breaker UNIT li 1NB03-16, bb UNIT 2: 2NB03-16. h
- b. At local Panel PLCB, STOP the running fan using HS-16550 for Fan No. 1 and/or HS-16551 for Fan No. 2.
- Comp 1cted & %YtA 51gnitu e
/tl)9/(( f10 ?)
Uath/ Time ~ l
~~
Reviewed // !O'/[ /,'26(2 ytnatu're Date/ Time Coments l
~ ~ ~ ~ '
moet; et wo ct6sTE~' ~ ~ +4: t no ,. [. , VEGP 1h6-C 9 h T 38 of 41
5.0 REFERENCES
5.1 PROCEDURES 5.1.1 10006-C, " Reactor Trip Review" 5.1.2 12001-C, " Unit Heatup To Hot Shutdown" 5.1.3 12002-C, " Unit Heatup To Normal Operating Temperature And Pressure" 5.1.4 12003-C, " Reactor Startup" 5.1.5 13003, " Reactor Coolant Pump Operation" 5.1.6 13005, " Reactor Coolant System Draining" 5.1.7 13006, " Chemical And Volume Control System Startup And Nomal Operation" - 5.1.8 13007, "VCT Gas Control And RCS Chemical Addition" 5.1.9 13009, "CVCS Reactor Makeup Control System" 5.1.10 13010. " Boron Thermal Regeneration System" 5.1.11 13011, . "Residual Heat Removal System" 5.1.12 13120, " Containment Building Cooling Systems' I 5.1.13 13125, " Containment Purge System" 5.1.14 13601 " Steam Generator And Main Steam System Operation" 5.1.15 13605, " Steam Generator Blowdown Processing System" 5.1.16 13610 " Auxiliary Feedwater System" 5.1.17 13612 " Condensate And Feedwater Systems" 5.1.18 13516 " Condensate Filter Demineralizer System" 5.1.19 13617 "Feedvater Heater Extraction Vent And Drain System" 5.1.20 13620 " Condenser Air Ejection System" 5.1.21 13724, " Circulating Water System" u.n v .
- s .
'.,y , -r .
p' m :.t:.'t wo arvaion < oct no VEGP 11w6-C 9 m@i 39 of 41 5.1.22- 13760, " Auxiliary Steam Boiler System" 5.1.23 13761, " Auxiliary Steam System" 5.1.24 13800, "Hain Turbine Operation" 5.1.25 13810 " Generator Gas System" 5.1.26 13825, " Turbine Steam Seal System" 5.1.27 14000, " Operations Shift and Daily Surveillance Logs" 5.1.28 14005, " Shutdown Margin Calculations" 5.1.29 14748, "AFV Check Valve Cold Shutdown Inservice Test" 5.1.30 14915, "Special Conditions Surveillance Logs" 5.1.31 24695, "N.I. System Source Range Channel Calibration" 5.1.32 24696, "N.I. System Source Range Channel Calibration" END OF PROCEDURE TEXT ya
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. (,. , VEGP 12 _c) c 9 h[- 4: nt 41 Sheet 1 of 1 UNIT NO. 00C DATE te/3 / 7 "6 [
RCS/PRZR TEMPERATURE AND PRESSURE DATA SHEET 1 Lowest Channel of TI-0413B TI-0423B TI-0433B PI-438LR or TI-0443B TI-0454 PI-405WR PRZR/hCS TIME RCS TEMP PRZR TEMP PRZR PRESS DELTA T o3q f 5'T Y C3( o 2 ~5[ Tb oq i C S~T'6 (3( :: 22e TT o44C T4O C., 3 T ' 22. .< 97 p cviT' 90 C3T .a i L o i o T' ncy e .fb se G 8 S' t 'I o & Th b(., o C Gas C2O I9oo El 069[ 5 30 G20 19 w 90
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. TI-0443B TI-0454 PI-405WR PRZR/RCS TIME . RCS TEMP PRZR TEMP PRZR PRESS DELTA T lllS 42 .r 5~28 89.C' /03 fjgf 400 SOO _ OS lou i z i c- 37D #Sy7a 5~35 : )oo par 370 490 S30 lo0
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to -(? v'ir [ /q / 7 oete m me j Rn. core Reviewed - O 'I /o//1 36 8OSY nature / Dhte/ Time Comments MM
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man
289 P02 1 l - * * ' ' JLt4-12 ' 91 11: 27 IDtSOtOPCO-V0GTLE TEL to 1-205-977-TBM 1 . . , PROCEDumt No. AtyiseON PAQt NO. VEGP 10000-C 12 26 of 26
PLANT VOCTLE UNITS 1 & 2 ,
TECH SPEC INTERPRETATION RdS CnD SHuTDcAM - LsC?$ f HWb TECH SPEC i: ___3.5f,;.4 QUESTION OR AR'.".A NIEDING CLARIFICATION: _ M a l- do .e s u w.+h n ac4ar cocIsn4 loops F. ited " m e a n ? INTERPRETATION: Ws A.Il conside r loops filled w h en pe ssu ti ke+ de.ld cal le v e.1 J S m4inIAined ) -2F% and Rc5 is Nended tier 13co l. - Lt. tAsc, Lco 3 4. q . 4,1. fo MoDii 9 wifh reacity coolani locp5 noi filled _ when Rd5 is d&ained below 2FL presruriter cold cal ~ le v e. l or 5 leam gencer.de k Me $ have. n.1 kee n venfed . _ Approved By: N Y- 2/r.a. /gq Manager Operacions Data xc Managog. Operations Nuclear Safety E. Compliance Manager Engineering Support Manager Plant Training 4 Emergency Prepardness Manager Rcquired Rsading Book l _ _ _ - _ - - - _ _ - _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ' - - - - - - - - - - - - ' - ' - - - ' - ^ ^ - - - " ~ ~ '
),,
. o J4NT4AT'7; , ;, 4 t/Si/gg g (X9tHON , pg , ,,,,
, . uw , .; & i .
h T CONTROL OF 8AFETT RETATED LOCKED VALVES VOID 1.0 PURPOSE This procedure identifies the administrative controle ) - for valves which are ortant for Safety Related Systems that shall be 1 cken in a specified position. ! 2.0 DEFINITIQR3 2.1 LOCKED VALVE A valve whose operation is prevented by a chrein and Padlock arrangement or other positive locking device. 2.2 KEY CONTROL ! Keys required for plant oration are controlled in accordanes with 00008 0 , Plant Lock And Key, control". 3.0 RESPONSI51LITIES 3-The Shift Ou>ervisor shalt maintain seministrativa control e tse keys d for Inckf ng of Safoty blated - 8 sten va vos. crt. Rhift rupervisor normatty leasats this p(The ro we for the Unit shift pery g .) , g"3 4.0 PRECAUTIORE The status of looked valves shsti r.ot be changed without prior authorisation by the shift tupervisor. 9
7 - ,
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"* f' ~ i M E , q . ..u h . . Wi . .. . i
- VEGP -10019.Q' . ' 3 'f r_ _@. f.
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s.1 BASIC CONTR03. OF 14CK50 VALVE 8 - ~ 5.1.1
% h devices initial status of y IVeypositions to established systen valve andlineups lockin$at t are 1 Performed followtag an eutage. Si 5.1.2 " Locked Valve Thevalveslistedinljl670[belockedinthe Ver1fication Check 11et shal l
< specified sosition wist the spoetfied padlocks usins l lengths of'shain or otter posttive lockins devices. __ 5.1.3 Locks should be placed on the remote operator for those : l manual valves that have resets operators such as reach .. rode. Sy- l Jn- s. 5.1.4 Inth6seseswhere1813mei. seasible to ph
- lock the apparatus, a Beld. fag asy be used.ysically 5.1.5 ilhan a los son 8.18 enlooked for operational i'
- purposes. Le chain should if possible be 3 looked to e esent easponents so as to preolude loss. J wwu . Q,'
i 5.1.6 If the lost fee senset be affiaed at the i I soaponente.1 e N be< returned to the shtte . .... . Superviser I r tspoststaan w :.;. . w s 5.1.7 status e ta the nos tons of locked valves shall 7 be d Manipu attes "use
. q 48.la " Locked Valva er.1 f;
1 a 5.1.8 g po'e g and leek 58 85s-of ejah loghed valve wilt gr mw. - grd per 1867ac, " Looked m ],i 3 5.1.9 Padlocks sad eba e 'not normally be removed to ' ! verify attles e 1 Valves. If locks must be M l removed then ree nata tien must be independently '{ l verifle . 7' 4 _ m 7
, 4*%
ggmas
i
. 'c"r@!;$4T%k &'*
5.2 HISPOSITIONED VALVES /Df0PERABLE LOCKING DEVICES nort - Valves in position other than ' the required position due ro ! S - the provisions of sub-subsection 5.1.5 are not considered I 1 mf,spositimod. ' 5.2.1 If any locked valve is discovered in a position other than the requf. red position or a' valve locking device is found inoperable, the operator shall NOTIFY the Shift Supervisor, i 5.2.2 The Shift Supervisor shall: l
- a. PTJtFORM an evaluation to determine if the valves current position has resulted in any adverce system conditions, 9
- b. PERFORN an evaluation to determine whether.
repositioning the valve to its correct configuration will result in any adverse system conditions,
- c. Resed on an ascentable evaluation DIRECT the -
repositioning an4 looking of the a.ffected velve or if unacceptable, shall IRITIATE placing the component i valve can/be systems restored affected to itsincorrect a position where the configuration, d. Control" has been :Aitiated. ENSURE a Deficianor Card pet 001 - 5.O REFER 8M3( 5.1 FROCEDURES v -
. :- ~.
3.1.1 00008 0, " Plant Los Control"
. g. .
5.1.2 00130 c e "Deficione ' trol" y- 3.1.3 003080.{" tai [? . . , tion Policy" ,}- i:
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' z 5.1.5 11888 1, WLeeked ation tos" E.p;
. 5.1.6 11867 0 4^ #Loeked.
satton checklist" 'i ' . 1
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UNIT Eu E1 Alaa
' [' ne, NUCLEAR RECULATORY COMMtsslON es! ION ll
- y 101 &nARitTTA STREET.NM, l*' ATLANTA, GEORGI A 38333 JUL 191931 l
'coe.. .
Docket Nos.'50-424, 50-425 License Nos. NPF-68, NPF-81 Georgia Power Company ATTN: Mr. W. G. Hairston, Ill S5nior Vice President - Nuclear Operations P. D. Box 1295 Bimingham, AL 35201 Gentlemen: asJECT: NRC INSPECTION REPORT NOS. 50-424/91-14 AND 50-425/91-14 This refers to the inspection conducted by Steven Vias and Scott Sparks of this office on June 17-21, 1991, and June 24-28, 1W1. This inspection included a review of activities authorized for your Vogtle facility. At the conclusion of the inspection, the findings were dis. cussed with those members of your staff identified in the enclosed inspectiun report. Areas' examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative cacordt, interviews with personnel, and observation of activities iw, progress. Within the scope of the inspection, 'no violations or deviations were identified. In accordance with Section 2.790 of the NRC's " Rules of Pra:;tice " a copy of this letter and the enclosure will be placed in the NRC Public Document Room. Should you have any questions concerning this letter. please contact us. Sincerely. Y W Alan R. Herdt, Chief Reactor Projects Branch 3 Division of Reactor Projects
Enclosure:
HRC Inspection Report . cc w/ enc 1: (See page 2)
. f,l i !) Cv,avv s
l{. (3 ' 1
,e
..~
JUL 191991 a Georgia Power Company 2 cc-w/ enc 1: R. P. Mcdonald-F.xecutive Vice President-Nuclear
- Operations-Georgia: Power Company.
P. D. Box 1295 81mingham, AL 135201 ~ C. K. McCoyc LVice President-Nuclear Georgia Power Company P. 0.-1295-Birmingham, AL 35201
.W. B. Shipman
- General Manager, Nuclear Operations -
- Georgia Power _ Company
.P. 0. 1600-Waynesboro,_GA 30830 J. A. Bailey:
Manager-Licensing-
-Georgia Power Company-P. O. Box 1295--
-Birmingham,AL-L35201-D. Kirkland. III, Counsel 10ffice of:the Consumer's ,
-Utility Council _ _
. Suite M S :32 Peachtree Street, NE
_ Atlanta, GA .-30302- , Office'of-Planning and Budget Room 6158 , 1270 Washington Street,- SW Atlanta.:GA- 30334
. Office of the County Cassiissioner-1 Burke County Commission Waynesboro, GA 30830
' Joe D." Tanner, Commiissioner -
Department of. Natural Resources, 205 Butler Street.- SE,-Suite 1252 - . Atlanta, GA_- 30334' Thomas Hill, Manager . Radioactive Materials Program ' Department of Natural Resources-
!878 Peachtree-St., NE., Room 600 Atlanta,_ GA -3030g i(cc w/ encl cont'd - see page 3) 4
Georgia Power Company -3 JUL1s1991-ccw/ enc 1s: .(Continued). Attorney General Law Department 132 Judicial Building
' Atlanta, GA - 30334 Dan Smith,-Program Director
- of Power Production.
Oglethorpe Power Corporation ' 2100 East Exchange Place P. O. Box-1349. Tucker, GA 30085-1349 Charles A. Patrizia, Esq. Paul, Hastings, Janofsky & Walker 12th Floor
- 1050 Connecticut Avenue, NW Washington, D. C.- 20036 w - +- -,,---y .,y- w e ge p-- , y ...~. gwa ,v.,e-t-, p-e ., ,-,--e-ce- y .. -- ---r, . ,. , . -- c,, a- wc-,..wa.-- - - , . . , , + , .~, .- -#v, -
usetTED STATts neog% NUCLEAR RE"ULATORY COMMisslON n RealON 11 f 101 MARIETTA STREET.NM. g- [ ATLANTA.StORGI A P3223
*...+
Report No.: 50-424/91-14 and 50-425/91-14 Licensee: Georgia Power Company _.P.O. Box 1295 Bimingham, AL 35201 Docket No.: 50-424 and 50-425 License Nos.: NPF-68 and NPF-81 Facility Name: Vogtle 1 and 2 Inspection Conducted: June 17-21, 1991, and June 24-28, 1991 Inspectors: b*\ NS Y #4 bl Date Signed S. J. Vias Project Engineer 5hM1
. E. Sparks Project Engineer
?liqlat Date Signed Approved.By:
- Y/f/f/
P. Skinfier, Chief Date Signed Reactor Projects Section 3B Division of Reactor Projects
SUMMARY
Scope: This routine inspection entailed review of open items and concerns from the NRC Inspection Report 424.425/90-19 and other management directives. I- -Results -In- the areas inspected, violations or deviations were not identified. l f05(50*
DETAILS
- t. Persons Contacted Licensee Employees
*S. Allison, Shift Supervisor
*H. Beacher, Senior Engineer
*J. Beasley, Manager Operations S. Chestnut. Manager Technical Support
*C, Christiansen, $afety Audit and Engineering Group Supervisor
*C. Coursey, Maintenance Superintendent
*T. Greene, Assistant General Manager Plant Support M. Hobbs, IAC Superintendent
*W. Kitchens, Assistant General Manager Plant Operations E. Kovinsky, Shift Superintendent (Training)
~P. Johnson, Health and Safety Coordinator
*R. Legrand, Manager Health Physics and Chemistry W. Lyon Quality Concern Program Coordinator
*R. Mansfield, Plant Engineering Supervisor
*M. Sheibani Nuclear Safety and Compliance Supervisor - Acting
*W. Shipman, General Marager Nuclear Plant
*C, Stinespring, Manager Plant Achinistration C. Williams, Shift Superintendent Other licensee employees contacted included technicians, supervisor, engineers, operators, maintenance personnel, quality control inspectors, and office personnel.
NRC Resident Inspectors
*B. Bonser *D. Starkey '*P. Balmain
- Attended Exit-Interview An alphabetical list of acronyms and abbreviations is listed in the last paragraph of the inspection report.
- 2. Review of Administrative Directives
- a. 10 CFR 50.59 Review Process Related to Procedures and Procedure Changes.
Licensee Administrative Procedure 00056-C, Safety and Environmental Evaluation, requires that 10CFR50.59 evaluations must be prepared for new procedures, procedure revisions and procedure deletions. Standsed foms are provided to perform these reviews. The inspectors reviewed a sample of revised and new procedures and found that a
- - .. ._ _ _ . _ - _ _ ._. _ ~_ _ _ _ . _ _ _ . _ _ . _
r 2 50.5gf evaluation was perfom in each case and that the guidelines
]
were being adhered to. b.- 0perator Guidance.for Entry into TS Conditions. During the OSI it was noted that there was a concern regarding the level of guidance provided to operators on TS entry conditions.
~
knowledge of. TS bases. .and overall management-philosophy toward TS : entry and TS violations. To address: the areas of TS. guidance and knowledge 'of TS bases. .the inspectors verified through training-department interviews that specific- training is dedicated to TS and
-their bases.. A~ separate week in traii n ng is devoted entirely to TS ,
review. . Additionally, the licensee recently.. revised the method in Administrative Procedure 10000-C. Conduct of Operations, by which
' licensee TS clarifications are reviewed and approved. -TS clarifi-cations now require review and concurrence of the Technical Support Manager and approval by the Manager Operations.
The inspectors have not detected any weaknesses in operator-knowledge or use of TS.
- c. Management Philosophy on TS- Action Statemen' ts.
Management philosophy for: entry into TS LC0' actions are routinely
. discussed with resident inspectors concurrent with various levels- of plant management when unusual plant conditions which necessitate
' .this action occurs. The inspectors have observed several examples of conscientious. deliberate efforts by 'the licensee to adhere to the intent ~ of :TS: usas. - Three; specific examples were not' ' in
~ March 1991.1 and d< scussed;inL detail' in Inspection Report 50-424
= 425/91-05 where the- licensee : found it- necessary: to clarify or evaluate TSs for continued operation. These-three evaluations were all associateC with a cloak; on n a Unit- 2 steam generator. In - all three cases the licensee's clarifications were assessed as_ safe and conservative.- 1These examples were particularly. noteworthy because-they. all involved weighing safety factors against economic factors.-
The licensee has- also revised their TS clarification document. This document which provides - guidance ~. to operators - on TS that - require furtLer interpretation ;is now~ reviewed by the Technical-Support
. Manager in ~ addition toithe review and approval by the Operations Manager. This additional' review provides independent review by a licensed individual.
p. i s d.- The Deficisney Card Process. x 1 When a suspected deficiency has been identified, a DC is submitted to % the control room within one hour. The unit shift supervisor then
'eviews the DC to determine the need for inmediate reporting -and c
L r. =--L .-------,..--.,.dn .ne, , , + ~ , aw n ,
i 3 Tother reviews. The DC is then submitted to Engineering Technical ; Support where it is also reviewed for reportability and to determine whether a deficiency exists. If Engineering _ Technical _ Support determines the identified deficiency is reportable then Engineering Technical Support is designated as the lead' department responsible for dispositiening :-the deficiency. If the DC does not require a written report, then it is forwarded to the responsible department for actior. The responsible department screens the DC .in accordance with guidance on root cause determina-tion- and: provides a _ brief explanation to indicate why a RCCA evaluation is or is not required.. There are three categories of events detailed in Administrative Proc 2 dure 00150-C, Deficiency Control. The first two. categories of events are more serious type events and require a melti-disciplined "
- review to ensure a complete, thorough, unbiased investigation.
Included in-these two categories of events are: unplanned reactor trips, unplanned . ESF- actuations, significant radiological events, unplanned turbine trips, diesel generator- valid failures, discovery of- significant; damage to a major plant component, and other events identified by site management. The third category of- events could be
. considered.a precursor to_ a more significant event but, due to its
.less: significant nature, would not typically require a multi-disciplined review.
For' Category 1 events -a ~ multi-desciplined Event Investigation Team investigates 'the event:and prepares a report which includes a root cause determination. For category 2 and :3 events the. responsible - department- manager will assign an appropriately qualified individual 4 within the department to; perform the root cause determination. For category 2 events the responsible department -manager will also-
' identify additional departments _ to perform a simultaneous root cause detemination.. The additional departments will return their results.
L to - the--lead ' department; for preparation of - a - combined final root
- cause detemination.
Forfcategory 2 or 3 events the individual assigned by the department
-manager to perform the root cause determination, may be the:same individual who dispositions the DC. The lead responsible department F manager is: required to concur 'with the identified root causes and p
correctiveJactions. After completion = by the department manager, the o Engineering Technical Support department will review the DC to ensure-an adequate investigation and that- corrective actions detailed are - appropriate. .The inspectors did not find any examples where this p process was not properly' followed. , i l
1 I 4
- e. Availability of Control Documents for Scheduling Activities in t9 Control Room.
The inspectors have found that during outage and non-outage periods, a Plan Of The Day is available in the control room which details planned activities for the day. The infonnation in the POD is accurate. The POD provides a weekly surveillance schedule for both units.- time lines for significant work to be accomplished, a listing of the work orders to complete and other useful information. Also infonnation on detailed work scheduling is disseminated through several meetines held during the day which the shift superintendent attends. This information is then passed on to the control room personnel .
- f. Direction of R0s and SR6s from Management.
In the area of managenent direction of RO's and SRO's, the inspectors have questioned a number of licensed operators about their perspective toward having a questioning attitude. It was detennined that operators are encouraged by management through fonnal training and on the job activities to have a questioning attitude and not to arbitrarily accept the directive of a supervisor or manager if there is a question as to tht correctness of that directive.
- g. Independent Review Process of " Functional Tests".
A functional test is defined in the Vogtle administrative procedure, Equipment Clearance and Tagging, as a test of a component or subsystem to verify satisfactory operation of the component or subsystem, after the component or subsystem has been placed in a configuration that assures plant equipment and personnel safety. A functional test is performed by qualified craft personnel for certcin maintenance activities such as troubleshooting, fan balancing, M0 VATS testing, and valve operational checks, etc. Before any functional test can be authorized, all other individuals that need to use the clearance for maintenance, must sign a release acknowledging the functional test is being performed. At this point the unit shift supervisor m:Jst ensure that 1.11- signatures are obtained before authorizing the functional test. During the review of the process l by the inspectors, it was observed through the procedures in place, that the functional test to be perfonned gets adequate independent
- review.
- h. Method of Making " Clearances" by Control Room Operators.
l Equipment clearances and tagging are handled by the SSS, who is a licensed SRO and is part of the Operations shift. The SSS works with the control room / unit shift supervisors and keeps them infonned of l any clearances being worked. The clearance / tagging responsibilities l of the SSS include: reviewing the impact of a clearance on plant operations; authorizing clearance installation and removal; and preparing and/or authorizing Functional Tests and Partial Releases.
5 The SSS may perform all clearance and tagging functions as designee for the USS as long as the SSS is cognizant of the unit configuration. The SSS must notify the reactor operator that a safety related system is being removed from service. The inspectors in reviewing the clearance logs found no indication of problems in this area.
- 3. Follow-up on Previously Identified Items (92701) (92702)
- a. (Closed) VIO 50-424,425/90-19-01: Failure to Perform Calibrations of Surveillance Requirement 4.2.5.3 Resulting in Incorrect RCS Flow Measurements.
This violation was issued due to a failure to calibrate feedwater temperature instrumentation used during the performance of the precision heat balance required by TS 4.2.5.3. The information from the heat balance is used in the detennination of RCS flow measurements. As stated in the licensee's response dated February 8, 1991, the violation occurred due to ' heir incorrect interpretation that the TS did not require calibration of permanently installed instrumentation when performing a precision heat balance. The inspectors verified the licensee's corrective actions, which included a revision of procedure 88075-C Precision Heat Balance, to require calibration of feedwater temperature computer points. In addition, RCS flow rates were re-calculated and determined to be acceptable. Based on a review of the above ccrrective actions, this violation is closed.
- b. (Closed) VIO 50-424,425/90-19-02: Inadequate Surveillance Procedure Results in a Failure to Maintain Containment Isolation as Required by TS 3.6.3.
This violation was issued due to failure to comply with an LCO when CIVs were opened and, thus inoperable during surveillance testing of the hydrogen monitor system. The inspectors verified the licensee's corrective actions as stated in their response dated February 8, 1991. These included a revision to procedures 24551-1 and 2 Containment Hydrogen Monitor Train A Analog Channel Operational Test and Channel Calibration, and procedures 24552-1 and 2 (Train B), to eliminate the need to open the subject CIVs. In addition, the licensee submitted a TS amendment, which if approved would allow the subject valves to be opened periodically under administrative control without entering the LCO. The inspectors consider the licensee's corrective actions to be satisfactory.
- c. (Closed) IFI 50-424,425/90-19-03 (Weakness No. 1): Review Licensee's Method for TS Interpretations.
This item was identified due to the licensee's method of allowing the Operations Manager to be solely responsible for the approval and distribution of the TS interpretations. The inspectors reviewed the l licensee's response to this item, dated February 8,1991. The l 1
- ~
6 l
^
l licensee agreed ' hat it would be beneficial to perform additional l revd ews of TS W upretations to ensure that the intent of TS do not I change. The ip. aste revised procedure 10000 C. Technical Specification Clarifications, to include the concurrence of the Manager, Technical Support, on all TS Clarification requests. In addition, the Manager, Technical Support is responsible for obtainin the appropriate departmental reviews, including licensing personnel.g The inspectors verified that recent TS Cla1fications received multiple department reviews, and that controlled copies of TS Clarifications were complete and distributed in a controlled manner. The inspectors verified that the licensee also prfonned a review of all current TS interpretations to ensure a change of intent did not oCCuP.
- d. (Closed)IFI 50-4"4,425/90-19-04 (Weakness No. 2): Review Licensee's Method for Interdepartmental Procedure Review.
This weakness was identified due to a lack of Operations De)artment review of Surveillance Procedure 24551-2, Containment Hyc rogen Monitor Analog Operability Test and Channel Calibration. The licensee's method for interdepartmental procedure review appeared to rely on the procedure writer's judgment. The Itcensee't response to this item stated that Administrative Procedure 00051-C, Procedure Review and Approval, requires that the department procedure coordinators obtain intra- and interdepartmental reviews, as necessary, for technical content, accuracy, and completeness. Cootnts are solicited from department managers. Procedures which affect areas of resporsibility of other departments are req:Jired co be reviewed by the affected departments. Yerifica-tion is also required to be obtained from all departments affected. The inspectors reviewed procedure 00051-0, and determined that l_ requirements and responsibilities for procedure review were defined, i Review of recent LERs, and discussions with the Resident Inspectors did not identify any recent procedural problems which could be I attributed to a lack of or improper interdepartmental review. The inspectcrs also noted that the licensee held departmental briefings on the tvent concerning proccdure 24551-2 and emphasized the importance of obtaining a proper review. The inspectors concluded that the lack of review for procedure 24551-2 was an isolated incident,
- e. (Closed)IFI 50-024,425/90-19-05(WeaknessNo.3): Voluntary Entry in
! TS LCO. This weakness was identified due to a concern that the liccesee was voluntarily entering into LCOs unnecessarily to reduce the scope of the subsequent refueling outage, The insnectors reviewed the LCO entry log book in the main control room,'which contains a brief sumary of each TS LCO entered, the reason for the entry, and entry and exit times. In addition, the main control room Design Change
4 l 7 i package ?og book was also reviewed by the inspectors. These reviews ' i did not identit'y any LCOs which were entered to reduce subsequent ! work scopu or for other inappropriate reasons. The it.spectors ! discussed this . issue with an Operations Shift Sumrvisor, who : indicated a heightened sensitivity to thir type of issue. This issue l was also discussed with the resident inspector staff, who stated that , voluntary entry into an LC0 is closely evaluated by the residents and : the licensee. Based on the above actions, this item is closed. l
- i. (Closed) IFI 50-424,425/90-1g-06 (Weakness No. 4): Licensee Interpretation of TS LC0 Shutdown Action Time. -
This weakness was ident!fied due to the licensee's position that T5 ' 3.0.3 allowed a subsequent reduction in power three hours efter entry into the LC0. This position was based on the abilit_y to go from i Mode 1 to- Mode 4 within four hours. During the 05I in August 1990, .the team identified that certain actions discussed in Generic ; Letter 87-03 were not fully implemented, i.e., notification of the i load dispatcher within the first hour and's controlled shutdown within the next six hours.
. l The licensee's response included a clarification of their position on entry into T5 LC0 3.0.3. In suunary, the licensee's position states i
that upon entry in T5 3.0.3, the Unit - Shift Supervisor should evaluate plant conditions and fomulate a course of action including actiens to prepare for and complete a safe and controlled shutdown. ! In cases where a high degree of confidence that the technical 1. sues can be resolved or repairs made promptly to restors component-operability, an immediate power reduction is not advisable. However. : actions are te be taken to ensure that an orderly shutdown will be 1
-completed within the allowable time while repairs or attempts to resolve operability are underway. Within the first hour.- -
- notifications to the 1 cad dispateur and management should be made. ,
e If the condition still exists, power reduction should begin no later . than four hours into the action (three hours of the allowable time remaining). In those cases where-it is apparent that resolution of the condltion will not occur within the allowable time, an orderly L shutdown will begin ismediately. . 1 i L The licensee's clarification of T5 3.0.3 entry is issued as a T5 Clarification, and maintained in the main control room. - This issue was dia ased with Operations personnel .who indicated a heightened awareness to activities due to entry into T3 3.0.3. In addition, this area is followed by the resident inspector staff during-nomal ' operational safety verifications, who indicated no recent problems associated with entry in TS 3.0.3. Based on the above actions, this > item is closed. - .
- g. (Closed) IF150-424,425/90-19-07 (Weakness No. 5): Certificat1un of a
Qualifications for Plant Equipment Operators. This wenkness was identified due to the licensee's practice of training evaluators delegating the responsibility for evaluating 1 a- _ _ = .- . . - . - - - . - . - - . - - . - - .
.. l l
performance of trainee PE3 rounds to a qualified PEO. In addition. l i it was noted that the licensee does not perfom a mana of the implementation of en the-job training for PE0s. geml t The inspectors detemined from discussions with the licensee and from -! their response to the weakness that their pelicy is to have evaluators accompany trainee PEOs on rounds. Evaluators won also ! reminded of their responsibility in these areas as a result of the i identified weakness. The inspectors also verified management involvement in the review of on-the job training for Ptos. As part of the Management Observation Program, a specific module was recently : added 'n which the trainee and tw evaluator are observed by line t managoo nt at all levels. Results of these observations are proeided to tw Assistant Plant Manager, Operations. The inspectors concluded 4 the licensee actions in these areas were satisfactory, Procedures for
- h. (Closed) !F1 -50 424.425/3013 08 (Weakness No. 6)
Defining Minimum Acceptable Perfomance of Plant Equipment Operator l l General Inspections. l This item was identified due to observed inconsistencies in the i perfomance of pt0 general inspections. The licensee revised i procedure 10001-C, Lopkrsping, to provide guidance on minimum - acceptable standards for PE0 rounds. Discussions with-the licensee indicated this area was reviewed as part of the roquaf ffication where minimum acceptable standards are specffied. , training for PE0s, In add' tion, the licensee added an additional Support Shift Supervisor to:each operating shift whose responsibilities include observation conditions. material of rounds perfomed by PEOs,- This program enhancement will- plant minimizewalkdowns, inconsistencies with PLO general inspections. Based on this action, this item is closed.
- 1. IF1 50-424,425/90-19-03 (Weakness A. 7): Nethod for '
-(Closed)ingOvertime.
Authoriz The inspectors reviewed the licensee's activities - to address Plant
. weaknesses identified in the authorization of evertime.
menseement reemphasized the adherence to Admir.istrative Procedure Overtime- Authorization, through a menerandum from the . and 00005-C Seneral Manager to all department managers - superintendents, , supervisors. The insMM: tors reviewed overtime authorisations
- recent Unit 1. refuel'ng- outage and verified that time in excess- of
.the- guidelines was properly authorized by the department manager and reviewed by the plant manager or designee. In assition, evertime did i
piscussions with plant manapement not an.4ar to become routine.- ,10wed indicated - that = tighter controls were imposed on evertime a , prior to the recent Unit 2 outage. An additional concern identified l i in the 414.425/g0 13 Inspection Report was that the non-supervisory staffing policy had the potentialPlant to result in management unbalanced experience levels on the night shifts. ' indicated a sensitivity to this issue, and agreed that the potential
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existed. However, staffing is frequently reviewed to ensure that the proper number of qualified personnel are on site at all times. In addition, management stated that any potential or actual problems attributed to unbalanced experience levels would be identified and corrected. Based on this review, this item is closed,
- j. (Closed)IFI 50-424,425/90-19 10 (Weakness No. 8): Review Licensee's Method of Holding Periodic Mini-Safety Meetings for Operations Personnel.
*dninistrative procedure 00250 C, Safety Comittee and General Safety deeting, provides guidance on mini-safety meetings. The inspectors verified the licensee distributes a bimonthly safety newsletter to all department managers with a list of selected topics for discussion. Each department utilizes a signoff on the back of the newsletter to list the names of personnel who attended the mini-safety meetings. This information is trended to ensure individual managers periodically hold mini-safety meetings. The licensee stated that the Operations Department usually holds mini-safety meetings as a part of shift turnover. The inspectors considered the licensee's actions in this area to be satisfactory.
- k. (Closed)IFI 50-424,425/90-19-11 (Weakness No. 9): Review Licensee's Method for Implementing the Quality Concern Program.
This concern was identified due to the licensee not performing an exit interview with each exiting employee to solicit quality concerns. In addition, a concern was identified in that the assignment of investigations to parties directly involved was a potential conflict of interest. Discussions with the Quality Concern Coordinator indicated that effort is made to perform an exit interview with each employee. However, if this is not possible, an employee is requested to complete a confidential Quality Concern fonn as part of the normal termination process. This form is then forwarded to the Quality Concern Coordinator for review. In addition, attempts are riade to contact each employee by written correspondence or by telephone if an exit interview cannot be performed. The inspectors also discussed the potential conflict of interest with the Quality Concern Coordinator, who stated that the review cycle minimizes the potential for any conflict of interest. After a quality concern has been identified and investigated, the Coordinator reviews the documentation to ensure a thorough review. This documentation is then forwarded to the Assistant Plant Manager, Plant Support, for an additional review. Based on the above review, the inspectors concluded the licensee's Quality Concern Program adequately addresses 'he previously identified concerns. Based on this action, this it e is closed. l L
10
- 1. (Closed) V10 50-424.425/90 05-01, failure to Mechanically Secure Valve 1-1208-U4-176 During Mode 5 As Required By TS 3.4.1.4.2.C.
On February 26, 1990. while Unit 1 was in Mode 5 with reactor coolant loops not filled, the inspector discovered that RHWST discharge valve, 1-1208-U4-176, was closed but was not mechanically secured as required by TS 3.4.1.4.2.C. Instead of a chain and lock, the valve had a clearance hold tag which provided only administrative control to preclude valve operation. The locked valve procedure,10019-C, was revised to uliminate utilization of a ' hold tag" on valves that are required by TS to be secured in position. The licensee conducted a review of valves which are required by TS to be secured to ensure that a mechanical locHng mechanism was in place. The licensee conrnitted in their responie dated May 24, 1990, to provide an appropriate locking mechanism for those valves, if any, which are secured by hold tags and are required to be secured by TS. The review identified no other valves which fell into that category. For the specific valve discussed in this violation, a steel cable was routed through drilled holes in the valve handle then mechanically secured to prevent operation of the valve. No violations or deviations were identified.
- 4. Exit Meeting The inspection scope and findings were sumarized on June 28,1991, with those persons indicated in paragraph 1. The inspector described the areas inspected and discussed in detail the inspection findings listed below.
No dissenting consents were received from the licensee. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection. S. Acronyms and Abbreviations CIV Containment Isolation Yalve DC Deficiency Card ESF Engineered Safety Features IFI Inspector Follow-up Item LCO Limiting Condition for Operation LER Licensee Event Report M0 VATS Motor Operated Valve Analysis and Testing System OSI Operational Safety Inspection PE0 Plant Equipment Operator RCCA Root Cause and Corrective Actions R0 Reactor Operator SRO Senior Reactor Operator SSS Shift Support Supervisor TS Technical Specifications VIO Violation
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m VuD VCT CAS CONTROL AND RCS CHEMICAL ADDITION
. 0,1 1 :0.R Y A T' O 1.0 PURPOSE Y0%y This procedure provides instructions for. Volume Control Tank (VCT) gas control operations and for Reactor Coolant System chemical addition. Instructions are included in the following sections:
4.1 Aligning VCI Hydrogen Purge - Normal Operation 4.2 Establishing A Nitrogen Blanket In The VCT 4.3 Transferring From A Nitrogen To A Hydrogen Atmosphere In The VCT 4.4 Transferring From A Hydrogen To A Nitrogen Atmosphere In The VCT - Nitrogen Supplied From N2 l Supply Header 4.5 Transferring From A Hydrogen To A Nitrogen Atmosphere In The VCT - Nitrogen Supplied From The l GWPS 4.6 0xygen Or Ammonia Removal From VCT Gas Space 4.7 Reactor Coolant System Chemical Addition 2.0 PRECAUTIONS AND LIMITATIONS 2 .1. Do not smoke, strike sparks or allow open flames in che vicinity of hydrogen lines. 2.2 When a Reactor Coolant Pump is operating, maintain a ( minimum backpressure of 15 psig on the No. I seal by maintaining a pressure of at least 18 psig in the Volume Control Tank. 2.3 Explosive mixtures of oxygen and hydrogen in the Volume Control Tank must be avoided at all times. The oxygen concentration must not exceed SI by volume when hydrogen is present.
PROCEDUME No. CEVISION PAoL No, 3 of 14 VrGP 13007-1 2
- 2.4 The reactor coolant temperature rust be less than 180'F when adding hydrazine. For oxygen scavenging, the l reactor coolant temperature should be between 150*F and l 180'F.
2.5 When adding hydrazine the Demineralizers should be bnassed and letdown flow diverted directly to the i Volume Control Tank. 3.0 PREREQUISITES OR INITIAL CONDITIONS 1 3.1 A level is established in the VCT and makeup is available. 3.2 The Gaseous Waste Processing System (CWPS) is available for waste processing. 3.3 The Auxiliary Gas Systems - Nitrogen and Hydrogen - are availablo to supply cover gas to the VCT. 3.4 The Nuclear Sampling Systems - Liquid and Gaseous - are available for sampling the VCT. 3.5 The Reactor Makeup Water System is aligned to supply
, water to the Chemical Mixing Tank.
3.6 The Nuclear Sampling Panel 1-1215-P5-NSP has been
, aligned by the Chemistry Department.
4.0 J_NSTRUCTIONS 4.1 ALIGNING VCT HYDROGEN PURGE - NORMAL OPERATION CAUTION If the VCT oxygen concentration limit is approached, the oxygen content should be lowered per Subsection 4.6. NOTE If a nitrogen atmosphere (
- exists in the VCT, align the tank for hydrogen purge operation per Subsection 4.3.
- l. 1.1 sample analysis , that REQUEST Chemistry-to the oxygen concentration in the verify, by VCT gas space.is less than 5% by volume.
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EOdni Jo. LEVl5loN ' PAGE No, CP 13007-1 2 3 of 14 4.1.2 VERIFY
- that a hydrogen atmosphere exists in the VCT as I follows: i
- a. VCT Hydrogen Manifold Isolation 1-1208-U4-107 is j OPEN, I i
- b. VCT Nitrogen Manifold Isolation 1-1208-U4-108 is CLOSED, ;
- c. Waste Gas Decay Shutdown Tank Supply To VCT, .
1-1208-U4-352, is CLOSED. ! 4.1.3 ENSURE that VCT Hydrogen Regulator 1-PCV-8156 is set to 18 psig or greater ! 4.1.4 ENSURE the Gaseous Waste Processing System in i operation, aligned to a Normal Gas Decay Tank, per 13201-1, " Gaseous Waste Processing System". 1 4.1.5 ENSURE that the VCT Purge Flow Controller 1-HIC-1094 is set at zero.
.4.1.6 -OPEN the VCT T0 GWPS ISO-VLV 1-PV-115.
4.1.7 ADJUST the VCT Purge Flow Controller 1-HIC-1094 to 0.7 scfm. 4.1.8 VERIFY that VCT pressure is 18 psig or greater on 1-PI-0115. 4.2- ESTABLISHING A NITROGEN BLANKET IN THE VCT , NOTE This subsection should be used to establish a nitrogen blanket if the VCT has been opened to atmosphere. 4.2.1 C'.0SE the VCT Hydrogen Manifold Isolation 1-1208-U4-107. 4.2.2' VERIFY that VCT Nitrogen Regulator 1-PCV-8155 is set to ( 20 psig. , 4.2.3 OPEN the VCT Nitrogen Manifold Isolation 1-1208-U4-108. Independent Verification required. 4.2.4' REQUEST Chemistry to verify, by sample analysis, the VCT oxygen concentration. , l'
- mn
IPmoCEDu.CNo. LEVI $loN PAGF fio. VEGP 13007-1 2 4 of 14 4.2.5 If oxygen concentration is greater than 5%, PERFORM the followings l a. CLOSE VCT NITROGEN MANIFOLD ISOLATION 1-1208-U4-108,
- b. REMOVE cap and OPEN GWPS Vent Header Sample Line Vent 1-1208-X4-374, CAUTION Do not exceed VCT pressure of 65 psig.
- c. START manual makeup to the VCT per 13009-1, "CVCS Reactor Makeup Control System",
- d. RAISE level in the VCT to 95 - 100%, then STOP makeup,
- e. CLOSE GWPS Vent Header Sample Line Vent 1-1208-X4-374,
- f. OPEN VCT NITROGEN MANIFOLD ISOLATION 1-1208-U4-108,
- g. OPEN Chemical Volume Control System (CVCS) Drain VCT To Recycle Holdup Tank (RHT) 1-1208-U4-123 and LOWER VCT level to 45 - 50% then CLOSE drain,
- h. REPEAT Sub-subsection 4.2.4 and 4.2.5 until the VCT oxygen concentration is less than SI by volume, L. VERIFY 1-1208-U4-123 is CLOSED. Independent verification required, J. VERIFY 1-1208-X4-374 in CLOSED and cap installed.
Independent verification required. 4.2.6 SET the VCT Nitrogen Regulator 1-PCV-8155 to at 18-20 psig. 4 4.2.7 PLACE the CVCS Reactor Makeup System in AUTO per 13009-1, "CVCS unactor Makeup Control System".
PMoctoOME No.
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f.EVl5loN , F AGE No. VEGP 1300 - 2 5 of 10 4.3 TRANSn:RRING FROM A NITROGEN TD A HYDROGEN ATMGSPHERE IN THE VCT CAUTION If the VCT oxygen concentration limit is approached, the oxygen content should be lowered per Subsection 4.6. NOTE This procedure should be performed in conjunction with unit heatup. 4.3.1 ALIGN a Shutdown Gab Decay Tank (S/D GDT) to receive VCT purger
- a. If a S/D GDT is not in service, ALIGN the system per 13201-1, "Gaaenus Waste Processing System",
- b. If the S/D GDT in in service supplying Unit 2.,
ALIGN the Unit 2 sy" stem to receive Unit i VCT purge p'er 13201-2, Caseous Waste Processing System . CAUTION VCT pressure must be maintained at greater than 18 psig to maintain adequate backpi* essure on Reactor Coolant Pump seals. 4.3.2 MONITOR VCT pressure indicated by 1-PI-ll5.
- a. If VCT pressure approachos 18 psig, CLOSE VCT TO GWPS ISO VLV l-PV-115,
- b. INCREASE the setpoint on the inservice VCT Nitrogen Regulator 1-PCV-8155 or A-PCV-7891 prior to re-establishing flow. ,
s 4.3.3 OPEN the VCT TO GWPS ISO VLV 1-PV-115. 4.3.4 ADJUST the VCT Purge Flow Controller 1-HIC-1094 to establish a purge flow of slightly less than 1.2 scfm. wn .
~ emociousen;. "TA. ' e no. VEGP 1300'/-1 2 6 of 14 4.3.5 RAISE VCT level to approximately 951 as follows:
- a. If Reactor Coolant System heatup is in progress, ALLOW the reactor coolant expansion to raise the VCT level by placing Letdown To VCT or Holdup Tank Valve 1-LV-112A in the VCT position,
- b. If Reactor Coolant System heatup is not in progress, PLACE Letdown To VCT or Holdup Tank Valve 1-LV-112A in the VCT position and RAISE level in the VCT by operation of the Reactor Makeup Control System in MANUAL per 13009-1, "CVCS Reactor Makeup Control System".
4.3.5 When VCT level reaches approximately 951, STOP makeup to the VCT if applicable and PLACE 1-LV-112A to the Holdup Tank (HUT) position to lower level, and ESTABLISH a hydrogen supply to the VCT as follows: I
- a. ENSURE that VCT Hydrogen Regulator 1-PCV-8156 is set to at least 18 psig,
- b. OPEN the VCT Hydrogen Manifold Isolation 1-1208-U4-107: independent verification required,
- c. CLOSE the VCT Nitrogen Manifold Isolation 1-1208-U4-108: independent verification required,
- d. CLOSE the VCT Waste Gas Decay Shutdown Tanks Supply To VCT 1-1208-U4-352: independent verification required.
4.3.7 LOWER the VCT level to 30 - 50% while maintaining a cover gas pressure of at least 18 psig as indicated on 1-PI-115. 4.3.8 RAISE the VCT level to 95I as follows:
- a. If RCS heatup is in progress, ALLOW the RCS expansion to raise level by placing 1-LV-112A to the VCT pocition,
- b. If RCS heatup is not in ?rogress, PLACE 1-LV-112A (
to the VCT position and RAISE level 13009-1, "CVCS Reactor Makeup Control System"per . 4.3.9 When VCT level reaches 951, STOP Reactor Makeup System if applicable, and PLACE 1-LV-112A to the HUT position. 4.3.10 LOWER VCT level to 30 - 50% while maintaining a cover gas pressure of 18 psig as indicated on 1-PI-115. 4.3.11 REQUEST Chemistry to sample the VCT gas space.
1
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PRoClount No. mgyd,iht: PAGE No. VEGP 13007-1 2 7 et 14 l 4.3.12 REPEAT'Sub-subsections 4.3.8 through 4.3.10 if necessary, until the VCT gas concentration is in specification. 4.3.13 ESTABLISH normal VCT level ands
- a. PLACE 1-LV-112A in AUTO,
- b. PLACE CVCS Reactor Makeup Control System in AUTO per 13009-1, "CVCS Reactor Makeup Control System".
4.3.14 ALIGN the Gaseous Waste Processing System for operation using a Normal Gas Decay Tank per 13201-1, " Gaseous Waste Processing System '. 4.4 TRANSFERRING FROM A HYDROGEN TO A NITROGEN ATMOSPHERE IN THE VCT - NITROGEN SUPPLIED FROM N2 SUPPLY HEADER NOTE This subsection should be used
&f VCT nitrogen purge gas cannot be supplied from the Shutdown Ges Decay Tank.
4.4.1 ALIGN a Shutdown Gas Decay Tank (S/D GDT) to receive VCT purge as follows:
- a. If a S/D GDT is not in service, ALIGN the system per 13201-1, " Gaseous Waste Processing System",
- b. If the S/D CDT is in service supplying Unit 2, ALIGN the Unit 2 system to receive Unit i VCT purge p'er 13201-2, " Gaseous Waste Processing System .
4.4.2 ADJUST VCT Purge Flow Controller 1-HIC-1094 to raise the hydrogen purge flow to the Gaseous Waste Processing System to slightly less than 1.2 scfm. 4.4.3 ENSURE that VCT Nitrogen Regulator 1-PCV-81.35 is set to 18-20 psig. ( 4.4.4 OPEN the VCT Nitrogen Manifold Isolation 1-1208-U4-108. Independent verification required. 4.4.5 CLOSE tha VCT Hydrogen Manifold Isolation 1-1208-U4-107. Independent verification required. 4.4.6 VERTFY that the VCT pressure is being maintained at 18 psig or greater as indicated by 1-PI-115. L
PRoCEDU~ E N J. LEYlSloN
- PAGE No, VEGP 13007-1 2 8 of 14 NOTE Continue the purge flow through the VCT until sample analyses indicate the hydrogen concentration in the reactor coolant has been decreased to less than 5 cc/kg. .
4.4.7 When the Reactor Coolant System hydrogen concentration is below Sec/Kg, DISCONTIWE the purge flow through the VCT as follows:
- a. ADJUST VCT Purge Flow Controller 1-HIC 1094 for zero flow,
- b. CLOSE the VCT TO GWPS ISO VLV l-PV-115.
4.4.8 If required, ALIGN the Gaseous Waste Processing System for operation using a Normal Gas Decay Tank, otherwise SdUT DOWN the system per 13201-1, " Gaseous Waste Processing System". 4.5 TRANSFERRING FROM A HYDROGEN TO A NITROGEN ATMOSPHERE IN THE VCT - NITROGEN SUPPLIED FROM THE GWPS NOTE This procedure should be performed in conjunction with unit cooldowns when the VCT nitrogen purge gas is being supplied from the GWPS. 4.5.1 ALIGN a Shutdown Gas Decay Tank to receive VCT purge as follows:
- a. If a S/D GDT is not in service, ALIGN the system per 13201-1, " Gaseous Waste Processing",
- b. If the S/D GDT is is service supplying Unit 2, ALIGN the Unit 2 sy"atem to receive Unit 1 VCT purge per 13201-2, Gaseous Waste Processing <
Sys tem '. 4.5.2 ADJUST l-HIC-1094 to raise the hydrogen purge flow to the Gaseous Waste Processing System to slightly less than 1.2 serm. I. 5.3 ENSURE that Shutdown Gas Decay Tank to VCT Regulator A-PCV-7891 is set to 18 20 psig. ( b --- .WE464md
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VEGP 13007-1 1 9 of 14 4.5.4 OPEN the GWPS ISO N2 PURGE FROM WASTE DECAY S/D TK TO VCT A-1902-U4-128. Independent verification required. 4.5.5 OPEN the CVCS VCT WGD S/D TArL9 SUPPLY TO VCT 1-1208-U4-352. Independent verification required. 4.5.6 CLOSE the VCT Hydrogen Manifold Isolation 1-1208-U4-107. Independent verification required. 4.5.7 VERIFY that the VCT pressure is being maintained at 18 psig as indicated on 1-PI-115. NOTE i Continue the purge flow through the VCT until sample analyses indicate the hydrogen concentration in the reactor coolant has been lowered to less than 5 cc/kg. 4.5.8 When the Reactor Coolant System hydro;jen concentration is below 5 cc/Kg, DISCONTINUE the purge flow through the VCT as follows:
- a. ADJUST VCT Purge Flow Controller 1-HIC-1094 for zero flow,
- b. CL7SE the VCT TO GWPS ISO VLV 1-PV-115.
4.5.9 ALIGN the nitrogen supply regulator to the VCT and discontinue the purge from tie Shutdown Gas Decay Tank as follows:
- a. ENSURE rhat the VCT Nitrogen Regulator 1-PCV-8155 is set to 18-20 psig,
- b. OPEN the VCT Nitrogen Manifold Isolation 1-1208-U4-108. Independent verification required,
- c. CLOSE the CVCS VCT WGD S/D TANKS SUPPLY TO VCT l-1208-U4-352. Independent verification required,(
- d. If not required for Unic 2 operations, CLOSE the GWPS ISO N2 PURGE FROM WASTE DECAY S/D TK TO VCT j Isolation Valve. A-1902-U4-128. Independent i Verification reqvired.
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4.5.10 VERITY that the VCT pressure is being maintained at l
, 18c20 psig as indicated on 1-PI-115. ;
4.5.11 If required. ALIGN the Gaseous Waste Processing System ! for operation using a Normal Gas Decay Tank, otherwise shutdown the system par 13201-1, " Gaseous Waste Processing System". ! 4.6 OXYGEN OR AMMONIA REMOVAL FROM VCT GAS SPACE ! CAUTION i If the .:hutdown Gas Decay, ! Tanks are being used as the ; purge supply for the Unit 2 ; VGT, shift purge supply to- ' the nitrogen regulator per 13007-2, VCT Gas Control And RCS Chemical Addition", prior to performing this : procedure. 4.5.1 ENSURE the following valves are CLOSED:
- a. GWPS VCT WGD S/D TANKS SUPPLY TO VCT 1-1208-U4-352,
- b. GWPS VCT WGD S/D TANKS SUPPLY TO VCT 2-1208-U4-352,
- c. GWPS ISO N2 PURGE FROM WASTE DECAY S/D TK TO VCT Isolation Valve.A-1902-U4-128.
4.6.2 . ALIGN a Shutdown Gas Decay Tank to receive VCT purge as follows:
- a. If a S/D GDT is not is service, ALIGN the system per 13201-1, " Gaseous Waste Processing System",
l b. If the S/D GDT is in service supplying Unit 2, > ALIGN the system to receive Unit 1 purge per 13201-2, " Gaseous Waste Processing". < - l 4.6.3 ENSURE that VCT Nitrogen Regulator 1-PCV-8155 is set to 18-20psig. ! 4.6.4 ENSURE the VCT Nitrogen Manifold Isolation i 1-1208-U4-108 is OPEN. 4.6.5 ENSURE that VCT Purge Flow Controller 1-HIC-1094 is set for zero flow.
PMoCEou.mE No- LEVI $lON P AG f. No. r VEGP lJ007-1 1 11 of , 1 l CAUTION VCT pressure must be greater than 18 psig to maintain adequate backpressure on Reactor Coolant Pump Seals. 4.6.6 MONITOR VCT pressure indicated by 1-PI-115.
- a. If VCT pressure approaches 18 psig, CLOSE the VCT !
To CWPS Isolation Valve 1-PV-115,
- b. RAISE the setpoint on VCT Nitrogen Regulator PCV-8155 prior to re-establishing flow.
4.6.7 OPEN the following valves:
- a. VCT To GWPS Isolation Valve, 1-PV-115,
- b. VCT Purge Flow Controller 1-HIC-1094 to establish a purge flow of slightly less than 1.2 scfm.
4.6.8 RAISE VCT level t) 90 ,. 9S% as follows:
- a. PLACE Letdown to VCT or Holdup Tank Valve, LV-112A to the VCT positicn,
- b. RAISE level in the VCT by oaeration of the Reactor Makeup Control System in MA3ULL per 13009-1, "CVCS Reactor Makeup Control System".
CAUTION Do not allow VCT level to decrease below 30%. 4.6.9 When VCT level reaches 90%, PLACE Letdown to VCT or Holdup Tank Valve 1-LV-112A to the HUT position to decrease level, and isolate the purge to the Caseous Waste Processing System as follows:
- a. CLOSE the iCT TO GWPS ISO VLV 1-PV-115, 4 ,
- b. Continue to divert water to the Recycle Holdup Tank until VCT level is 30 - 50%.
4.6.10 When VCT level reaches approximately 50%, PLACE Letdown to VCT or Holdup Tank Valve 1-LV-112A to AUTO. 4.6.11 REQUEST Chemistry to sample the VCT gas space. g -._ . . , , 9 y
rao'crougtp uo. "" ""' 13007-1 - 2.' 12 of 14
. CAUTION Do not exceed a Shutdown Gas Decay Tank pressure of 80 psig.
4.6.12 REPEAT Sub-subsections 4.6.8 through 4.6.11, if necessary, until the VCT gas concentration is in specification. 4.6.13 If the Unit 2 VCT purge supply was transferred from Shutdown Gas Decay Tank to nitrogen regulator at the beginning of this subsection, then PERFORM the followings
- a. REQUEST Chemistry to sample Shutdown Gas Decay Tank and if acceptable for Unit 2 VCT purge supply,
- b. TRANSFER the Unit 2 VCT purge supply from nitrogen regulator to Shutdown Gas Decay Tank per 13007-2, "VCT Gas Control And RCS Chemical Addition".
4.7 REACTOR COOLANT SYSTEM CHEMICAL ADDITION NOTE To ensure thorough mixing, at least one Reactor Coolant Pump should be in operation while chamicals are being added to the system. 4.7.1 ISOLATE the Chemical Mixing Tank by verifying the following valves are CLOSED:
- a. Chemical Mixing Tank Supply From RMWST l-1208-U4-176,
- b. Chemical Mixing Tank Outlet Valve,1-1208-U4-181.
CAUTION When adding chemicals, a face shield, gloves and protective ( clothing must be worn. Inhalation of, or skin contact with chemicals such as lithium hydroxide or hydrazine should be avoided. 4.7.2 COORDINATZ with Chemistry to add the chemicals to the Chemical Mixing Tank per 35110-C, " Chemistry Control of The Reactor Coolant System". w
FDCEDURE No. LEVI &loN , SAGE No.
'3007-1 13 of 14 VEGP 2 CAUTIO!!
. Tank filling should be performed slowly to prevent I the overflow of chemicals l from the tank vent. l 1
4.7.3 OPEN Chemical Mixing Tank Supply From RMWST 1-1208-U4-176, approximately one eighth turn, to slowly fill the tank. l 4.7.4 When water starts to flow out of the tank vent, CLOSE Chemical Mixing Tank Vent 1-1208-U4-179. 4.7.5 Fully OPEN Chemical Mixing Tank Supply From RMWST 1-1208-U4-176. CAUTION When adding hydrazine, the Demineralizers should 've bypassed and letdown flow diverted directly to the VCT. 4.7.6* If adding hydrazine, PLACE Letdown to Demineralizer/VCT Valve 1-TV-0129 to the VCT position. 4.7.8 OPEN Chemical Mixing Tank Outlet Valve 1-1208 U4-181T w,
)
4.7.9 ALLOW flow through the Chemical Mixing Tank fo N. -san # minutes, then ISOLATE and DEPRESSURIZE the tank as follows:
- a. CLOSE Chemical Mixing Tank Outlet Valve 1-1208U4-181. Independent verification required,
- b. CLOSE Chemical Mixing Tank Inlet Valve 1-1208-U4176. Independent verification required,
- c. Slowly OPEN Chemical Mixing Tank Outlet Drain 1-1208-U4-180 and RELIEVE the tank pressure, then CLOSE the valve.
4 4.7.12 After aparoximately one hour, REQUEST Chemistry to sample tae Reactor Coolant System and REPEAT the chemical addition if necessary. l
! i
- Pmocaouma wo. naviseow PAos wo, ,
VEGP -13007-1 - 1 14 of 14 l I f i
-5.0 -REFERENCES
-5.1 PROCEDURES 4
5.1.1 13006-1, "CVCS Startup And Normal Operation" t 5.1.2 13009-1, "CVCS Reactor Makeup control System" l t 5.1.3 13012-1, " Nuclear Sampling System - Liquid" 5.1.4- 13013-1, " Nuclear Sampling System - Gaseous" ' t 5.1.5 13201-1, " Gaseous Wasta Processing System" l l 5.1.6 13707-C, " Auxiliary Gas System - Nitrogen" !
'5.1.7 13708-C, " Auxiliary Gas System - -Hydrogen" !
i 5.1.8 .13733-1, " Reactor Makeup Water System" ! r
- 5.1.9 35110-C, " Chemistry Control of The Reactor -
I Coolant System" ' 5.1.10 13007-2, "VCT Gas Control And RCS Chemical i Addition"
-5,2 P&ID's ,
m . . ! 5.2.1 1X4DB115,- Chemical & Volume control System l 5.'2 ; 2 1X4DB116-1, Chemical & Volume Control System 5.2;3 1X4DB128, Wasta Processing System-Cas
- 5.2.4 1X4DB129,; Waste Processing. System-Gas j 5.2.5 1X4DB140, Nuclear Sampling __ System-Liquid i 3.2.6 -1X4DB141, Nuclear Sampling System-Gaseous -f 5.' Alvia W. Vogtle Units l'& 2 Precautions Limitations I and;iatpoints Document for Nuclear Steam-Supply ;
Systems. ( , h END OF PROCEDURE TEXT
1 ion.
* - .,lM 37I EQUIP $ENTTOBETESTED Ger rQd b ,cucf ;
Adht hEQUESTE'D By/ 'C REASON FOR TEST Add 14o) /Unx,'th_ TEST DOCUMENT NO. ed /,4 CLEARANCE POINTS TO BE RELEASED CLEARANCE RESTORATION Req'd. Tag No. Equipment No. P s. JAft. Sequence Pos. Init. In,it. 74tV _ 7 L. C. lW) fle L. l-tas P 04- 191 32 ?, W Ad / - K. r - r1.onok-UH a d . vu . t3rh6 &RA f_ n? . t SUBCLEARANCE RELEASE CLEARANCE ALIGNMENT 0 TEST E,0R T*ME DATE N TIME N VE I E BY D/.TE f A ' A- ,
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/3CL n4 . I - l tce -ud -17to c_Lggy, f M-- _L f?L Dftv cLcc. f M I g v,.L L. I-t w8 668 SUBCLEARANCE RELEASE CLEARANCE ALIGNMENT FOR TEST TIME DA RESTORED TIME DATE (MA/C 5 unv' <o .o y /
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T he:toun No- nt wv4~~ ' ' eact so VEGP.. 00304- 3 36 of 43 FUNCTIONAL TEST FORM
*.- '.'..* CLEARANCEi_f.M$'37/
44., ,, EQUIPME TO BE TESTED, SIl41L/ d d ebV C I. kEQUESTEb BY.' ' REAS,N-FOR 0 TEST ti/f kr B/Ur' ( t., . TEST DOCUMENT NO. A//A CLZARANCE POINTS TO BE RELEASED CLEARANCE RESTORATION Req'd. ment No. Pos. Init. Sequence Tag No. _ Equip /-/77 fd(_ L Pos. c., Igit;6. Init. L(7 ' O. 6__. /-/ZM'u h ka' t-3 c c. Lj k cu d . _1 11m > ud. I'1h L
? . 1-11Be -u 4- le t L cli' I a L. C btX M uw ,
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EXHIBIT 14 i 4'temical Addition Evolution Chronology of signiLL9?nt Events October 11. 1981 (all times are in Central Time) About 5:30 p.m. Tne Night Shift crew began duty with Mr. Jimmy Paul Cash as osos and Mr. John Bowles as Unit Shift Supervisor. . About 7:00 p.m. Preparations for (or the initiation of) nitrogen injection into the steam generators began. October 12. 1988 1:50 a.m. Nitrogen injection into the steam generators was completed. About 3:00 a.m. The Support Shift Supervisor, Mr. Tom Ryan, authorized and completed a Functional Test Form to release Clearance No. 1-88-371 from RMWST discharge Valves Nos. 176, 177 and 181. About 3:30 a.m. RCS water level was at 1898 10". 4:00 a.m. Mr. Ryan supervised plant personnel who added
-hydrogen peroxide to the chemical Mixing Tank and then filled up the tank with water from the RMWST (the chemicals were D2t injected into the RCS). Mr. Bowles recorded the "0400" entry in the Shift Supervisor Log.
4:15 a.m. Clearance No. 1-88-371 was restored to RMWST discharge Valve Nos. 176, 177 and 181. Between 5:07 a.m. The Day Shift arrived in the Control Room, and 5:33 a.m. Mr. John Hopkins was the OSOS and Mr. Jeffrey Casser was the Unit Shift Supervisor. A discussion of the applicability of Tech. Spec. S 3.4.1.4.2 occurred and Mr. Bowles recorded the "LE 0400" late entry in the Shift Supervisor Log. 1
Between 5:07 a.m. Mr. Hopkins and Mr. Gasser discussed Tech. and 6:00 a.m. Spec $ 3.4.1.t 2 with Mr. W. F. Kitchens, tho operations Manager, in the control Room. Mr. Kitchens instructed Mr. Hopkins to - suspend the chemical addition evolution. 6:00 a.m. Tho OSOS/ outage status meeting took place, attended by the OSOS, the Outage & Planning Manager, Mr. Kitchens and numerous others, at which the status of the outage in general was discussed and the fact that the chemi ' . addition evolution was on hold pendin; . review of Tech. Specs. About 6:10 a..a. Following the OSOS/ outage status meeting, Messrs. Kitchens and Hopkins reviewed the Tech. Spec. and che FSAR and spoke with Mr. Walter Marsh, the Deputy Manager of Operations. 6:25 a.m. Messrs. Hopkins and Gasser authorized the "elease of Clearance No. 1-88-371 on RMWST discharge Valve Nos. 176, 177 and 181 and directed shift personnel to open the valves for er more than five minutes. 7:05 a.m. through RMWST discharge Valve Hos. 176, 177 and 181 7:09 a.m. were in the open position. 7:22 a.m. Clearance No. 1-08-37) was restored to RMWST , discharge Valve Nos. 176, 177 and 181. October 13, 1988 9:37 a.m. Messrs. Hopkins and Gasser authorized the release of Clearance No. 1-88-371 on RMWST discharge Valve Nos. 176, 177 and 181 and directed shift personnel to open the valves for no more than fivo minutes. 10:30 a.m. through RMWST discharge Valve Nos. 176, 177 and 181 10:34 a.m. were in the open position. 10:34 a.m. Clearance No. 1-88-371 was restored to RMWST discharge Valve Nos. 176, 177 and 181. 3:59 p.m. Messrs. Hopkins and Gasser authorized the release of Clearance No. 1-88-371 on RMWST disenarge Valve Nos. 176, 177 and 181 and 2
\
l directed shift personnel eo open the valves for no more than five minutos. 4 40 p.m. through RMWST discharge Valve Hon. 176, 177 and 181 4:44 p.m. were in the open position. l l
}
4153 p.m. Clearance flo. 1-88-371 was restored to RMWST i discharge Valvo Nos. 176, 177 and 181. i Y
)
k e r a 3 .__ _ . . _ - . ~ - _ . . . - - , _ - - _ - _ - _ _ _ _ _ , - . _ - _ - . . - - - - . .
.-e , -. 3 3 UNITE 3 STATES
} NUCLEAD GECULAT03Y COMMISSION
. I caaow n
.,,,e *[
\' 101 MARIETTA ST., N w
&?LANTA, GEORQ4A 30333 JUN 1s ing-Docket Nos. 50-424 and 50-425 Lic N e-Nos._MPF-68 and NPF 81 Georgia Foser Company ATTN: Mr. W. G. Hairston, 111 Senior Vice President -
Nuclear Operations P. 0. Box 1295 Oirminghan, AL 35201 Gentlemea.: SU6 JECT: NOTICF 0F VIOLATION (NRC INSPECTION REPORT N05. 50-424/89-14 AND 50-425/89-15) This refers to the Nuclear Regulatory Commission (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 indica *,e that certai'i 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 Vichtion. The enclosed Inspection Re,, ort also identifies activities that appeared to violate NRC requidv ents but are not_ beif.9 cited; therefore, no response is required for these items. In accordance with Sectior. *PO of the NRC's " Rules of Practice," Part 2 Title 10. Code of Federal 6991 .fons, a copy of this letter and its enclosures will bk placed in the NR( PtM 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 A;:t of 1980, Pub. L. No. 96-511. 4
/
a s; LGeorgia P,.;er Company 2 5 063 Should you have _any questions concerning: this letter. please contact us~. ' Sincerely, N 44 Alan R.- Herdt, Chief Reactor Projects Branch 3 Division of Reactor Projects-
Enclosures:
1.. -Notice of Violation
- 2. Inspection 3eport cc w/encls:
. R. P. _ Mcdonald. Executive Vice-President - Nuclear Ooerations LC. K. McCoy. Vice Preticent - Nuclear G. R. Fredrick. Quality. Assurance Site Manager .
G' Bockhold.:Jr.. General: Manager
~ Nuclear. Plant-J. A.c kiley, Manager s 1.icensing7
~ G. !W; Co ' chill .LEsquire, Shaw, 91 fa n. otts,'and Trowbridge J.ir Jc w: . Esquire.;Troutman, t irari, : ackerman. and Ashmore D . - A " A '< a r e !!!. Counsel..
~ Oft ist of he Consumer's Utility. <
' Covec n LState ot-usorgia-r -
i i l- I s e i , _)
ENCLOSURE 1 c NOTICE OF VI0t.ATION
" Georgia Power Company Vogtle. htts 1 and 2 Docket Nos. 50-424 and 50 425 License Nos. N9F-68 and NPF-81 -
During the Nuclear Regulatory Comission (NRC) inspection conducted on March 18 - May 5,1989, a violation of NRC requirements was identified. In accordance with the " General Ststement of Policy alad Procedure for NRC Enforcement Actions," 10 CFR Part 2 Appendix C (1988), the violation is listed
-below.
10 CFR Part 50, Appendix B, Criterion V, states that activities affecting quality shall be prescr ' Ad by documeated instructions, procedures, or
' drawings, of a type appropriate to the circumstances and shall be
~ accomplished in accordance with these instructions, procedures, or drawings.
Technical . 5pecification 6,7.1.a requires that written procedures be established, implemented, and maintained covering activities-delineated in Appendix A of Regulatory Guide 1.33, Revision 2,-February 1978. Contrary to the above, six examples were identified where the licensee. failed to appropriately establish or implement prccedures 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 administrative procedure 00101-C, " Drawing Control," Step 3.4.4, and
. engineering procedure 50009-C, . "As-Bu11t Notices," Step 4.6.3, were not implemented in that the primary safety-related drawing's as-built notices were not ensured of drawing legibility' prior to distribution.
- 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-implemented - in that ' the licensee . failed to open all four- Unit 2 bypass -feed isolation - valves and failed- to stabilize #3 -Steam Generator level prior to placing the - bypass feed regulation
' valve in automatic.
- 3. On April 3.1989, 'following a feedwater isolation, the licensee identified that startup test procedure.2-6AB-01, " Dynamic Automatic Steam ' Dump Control ." was not adequately established in that
. attachment 10.5 incorrectly specified the wrong polarity for a - test-
[ 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. Y 0f $
-Georgia Power Company 2 Vogtle, Units 1 and 2 Docket Nos. 50-424 and 50-425 License Nos. NPF-68 and NPF 81 4
On April 7,1989, following a feedwater isolation on Unit 2 the licensee identified that a failure to impiement procedure 12004-C,
" Power Operation," Step 4.1.3, had occurred in that long-cycle feedwater recirculation cleanup was not secured which resulted in all four steam generators being cross connected.
This condition lasted until a level imbalance resulted in a feedwater isolation. 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
-operation.
of the safety injection flow path during Mode 3 This procedure was utilued on nine occasions on Unit i and one occasion on Unit 2.
- 6. On December 8, 1988, with Unit 1 at 100% power, the inspector identified that the licensee had failed to establish an adequate procedure 12004-C, " Power Operation," Step 4.1.37, for placing AMSA(
equipment in operation in that the procedure specified the equipment in service at 60% when the design basis specif'es 40%. AMSAC equipment is required by 10 CFR 50.62 to automatically initiate the auxiliary feedwater system and initiate a turbine trip under conditions indicative of an anticipated transient without scram. This is a Severity level IV violation (Supplement I) Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company is hereby required to submit a written statement or explanation to the Nuclear Regulatory Commission. ATTN: Document Control Desk, Washington, D.C. 20555, with a copy to the Regional Administrator, Region 11, and a copy to the NRC Resident Inspector, Vogtle, within 30 days of the date of the letter transmitting this Notice. This reply should be clearly marked as a " Reply to a Notice of Violation" and should include: (1) admission or denial of the violation, (2) the reason fcr the violation if admitted, (3) the corrective steps which have been taken and the results achieved, (4) the corrective steps wnich will be taken will to avoid further violations, and (5) the date when full compliance be achieved. extending the response Where good cause is shown, consideration will be given to 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 action as may be proper should not be taken. FOR THE Nutt. EAR REGULATORY COMMISSION 7) Alan R. Herdt, Chief Reactor Projects Branch 3 Division of Reactor Projects Dated at Atlanta, Georgia t this 15 day of June 1989 i i
g* - e i .,
,8
- U +is -#Afts f, NUCLEAN ffECULi.' GGY CDZCISSIGN At440N ll
\' j/ 101 MamlETTA ST, N W
.,,,. ATLANTA. GEORCIA 30323 Report Nos.: .
50-424/89-14 and 50-425/89-15 Licensee: Georgia Power Company P.O. Box 1295-Birmingham, AL 35201 Docket Nos.: 50-424 and 50-425-License Nos.: NPF-68 and NPF-81 Facility Name: Vogtle-1 and 2 Inspection Conducted: March 18 - May 5, 1989
. W Inspectors: d./ - , / e- .- M- /V: .' /
J. E,d ogge, Sanjor Resident Inspector Date 51gneo ~
// . . < /- f./J'~f.f R. K Aiello, Resident Inspector Date Signed C.
W . .
/-~ f /f-??
A.' Patterson, Project Engineer (April 3-6) Date Signed _ s .-
/ !. '/?- '* /
J. K Menning, Haten Sent'or Resident (April 1-2) Date Signec
/ / . D .. /L R. t! Prevatte, Sumer Senior Resident-(April 1-2)
/-E *'
Date Signed P. C.4pkins, Sumer Resident ( April 1-2)
, f. /-/ .' * !
Date Signeo Accompanied By: Rick Mc hort r (March 27-30) Approved By: [ r , e Mu d' M. V.'/51nkule, Stat 16n chief */5 D / Diviston of Reactor Projects Date signed /
SUMMARY
Scope: 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. ha A/bb
2 Results: In the areas inspected, fourteen violations were identified. violation was cited, and thirteen violations were non-cited pursuantOf these, to the one discretionary was identified inprovisions of the NRC Enforcement Policy. The cited violation failure to establishthe area of operations, or implement and it involved six examoles of procedures. One of the six examples pertained to Unit 1 only (paragraph 5.f), three pertained to Unit 2 only (paragraphs units (paragraphs 4 b(3)(q), 2.b(1) a.b(3)(r), and 3). and 4 b(3)(s)), and two pertain to both pertained to Unit 1: one in the Of the tnirteen non-cited violations, five area of radiological controls (paragraph and 4.b(2)(d}}, 4.b(2)(b)), and twotwo in the area of surveillance (paragrap/ chemistry hs 4.b(2)(a) in graphs a.b(2)(c) and 4.b(3)(h)).the area of emergency technical support (para-pertained to Unit 2. The remaining eight non-cited violations Three were identified in '.he 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)(i), and 4.b(2)(,j)), (k)), and one one was was idetified in the area of maintenante (paragraph 4.b(2) identified (paragraph 4.b(2)(e)). in the area of engineering technical support Two inspector followup items were also identified involving the adjustment of 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 of operations noted and startup testing (Unit 2) were noted as strengths with the area as a weakness. Maintenance (paragraph 2.b(7)) was considered a strength primarily due to the planning and execution of the work schedule. Unit I and short plant outages on Unit 2 were effectively conducted.Short Most syste Unit 2 test program due to this proficiency.notewortr.y was the e Startup Testing on Unit 2 (paragraph 3) was a Second strength even though one procedure error resulted in a preventable transient. The transient was preventable because the identical error was identified during Unit I test program. _ of the Remote Shutdown Test and the Loss of Offsite Power Te Operations evidenced weakness in the area of procedure establishment and implementation Examples includedof the basic operating procedure 12004-C " Power Operation " . l in the cited isolation valves (paragraph 3),violation are failure to open bypass to secure from long-cycle cleanup (paragraphs 3 and 4.b(3)(s)), to main feedwater (paragraph 3). and to perform the transfer from auxiliary ' the LERs (paragraphs 4.b(2) and 4 b(3)).Other operations errors were noted in expressed to licensee management. This concern has been verbally i
REPORT DETAILS '
- 1. Persons Contacted Licensee Employees
*G. Bockhold, Jr., General Manager Nuclear Plant
*A. L. Mosbaugh, Plant Support Manager
*R.
M. Odom, Nuclear Safety & Compliance Manager / Plant Engineering Supervisor
*J. E. Swartzwelder, Manager Operations W. F. Kitchens, Assistan* :eneral Manager Plant Operatiuns R. L. Legrand, Manager C *emistry and Health Physics
*H. M. Handfinger, Manager Maintenance G. A. McCarley, ISEG Supervinor
*G. R. Frederick, SAER Supervisor W. E. Mundy, Quality Assurance Audit Supervisor C. k Coursey, Maintenance Superintendent
'Other licentes employees contacted included craftsmen, technicians, supervision, control engineers, inspectors, operations, and office maintenance, chemistry, quality personnel.
' Attended Exit Interview An alphabetical list of acronyms and initialisms used throughout this repart are listed in the last paragraph.
2. Operational Safety Verification - (71707)(93702);71715) Unit 100t 1 operated reactor this inspection period in Power Operations (Mode 1) at power. Unit 2 - began this inspection period 'in Mode 4 (Hot shutdown). 10n
. 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.
Unit 2 experienced a CVI due to 2RE 2565 radiation monitor.On - March - 19, fo Additionally, on March 19, (night shift caused by personnel error.), On March 28 Unit 2 experienced a FWI due to P-Unit 2 entered Mode 2 (Startuo), went critical, and commenced low power p,hysics testing. On-April 5, MFp "A" tripped- resulting in a MDAFW pump actuation. On April 7, Unit 2
-entered SG level.Mode 1. Later that same. day, a FWI occurred as a result'of a Hi-Hi The unit later entered Mode 2. The unit reentered Mode 1-on April 8. On April- 9. MFP "A" tripped resulting in a MOAFW 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 L 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 l l l
2 , 1 l with subsequent entry into Mode 1. On April 14, the unit conducted a LOSP test with subsequent entry into Mode 3. Following the LOSP test, the unit 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 l l 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 turbine was returned to service and tied to the grid. On April 22, a unit 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 April 23, the main generator was tied to the grid. On April 24 with all of the 30% plateau testing complete, the unit commenced 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 with the plant at 63% from a turbine trip following a test of the 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 period,
- a. Control Room Activities Control Room tours and observations were performed to verify that facility operations were being safely conducted within regulatory requirements. 'These inspections consisted of one or more of the following attributes as appropriate at the time of the inspection.
Proper Control Room staffing Control Room access and operator behavior Adherence to approved procedures for activities in progress Adherence to technical specification limiting conditions for operation Observance of instruments and recorder traces of safety-related and important to-safety systems for abnormalities Review of annunciators alarmed and action in progress to correct Control Board walkdowns Safety parameter display and the plant safety monitoring system operability status Dis:ussions and interviews with the On-Shift Operations Supervisor. Shift Supervisor, Reactor Operators, and the Shift Technical Advisor twhen stationed) to determine the plant status, plans, and to assess operator knowledge Review of the operator logs, unit logs and shift turnover sheets 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 licensee personnel, indepercent verification of safety system status
3 and LCOs, licensee meetings and facility records. During these inspections, the 'ollowing objectives were achieved: (1) Safety System Status (71710) - Confirmation of system operability was obtained by verification that flowpath valve alignment, control and power supply alignments, component conditions, and support systems for the accessible portions of the ESF trains were proper. The inaccessible portions are confirmed as availability permits. An additional indeptn inspection of the Unit 151 system was performed to review the system lineup procedure with the plant drawings and as-built configurations and to compare valve remote and local indications. Walkdowns were expanded to include hangers and supports and electrical equipment interiors. The inspector observed that the lineup was not in accordance with license requirements in that the 51 RCDT pump discharge to RWST isolation (1-1204-U4-002), SI RWST INL FI-092BA and F1-092BB isolation valves were found open. DCs were properly issued by the SS to correct these deficiencies. These valve misalignments did not render the SI system inoperable. Several valves were noted to have missing lubel plates. Rooms A9 and A10 need a great deal of attention from a Health Physics and cleanliness 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 l and TSC drawings were inspected. This inspection included a detailed walkdown of the 51 system (discussed above) and a l review of the following drawings to determine legibility, current revision verification and verification that procedure valve lineups were appropriate: 1X4DB119 Rev 20 1X408130 Rev 22 1X4DB129 Rev 23 1X40B133-1 Rev 23 1X40B136 Rev 22 1X408161-1 Rev 22 1X4DB170-1 Rev 23 1X4DB120 Rev 14 1X40B138-2 Rev 15 1X4DB136 Rev ?2 1X408121 Rev 24 1X4DB131 Rev 19 1X4DB139 Rev 18 1X4DB138-1 Rev 16 1X4DB122 Rev 26 1X4DB132 Rev 14 1X408133-2 Rev 26 1X408135-1 Rev 21 l 1X4DS137 Rev 15 1X4DB161-2 Rev 22 1X408161-3 Rev 20 1X40B170-2 Rav 22 1X40B116-2 Rev 15 IX40B117 Rev 18 1X4DB118 Rev 20 CX408173-557 Rev 1 CX40B173-558 Rev 1 CX4DB173-553 Rev 1 The inspector determined that the procedures for controlling tne distribution of drawings were satisfactory. The drawings adequately represent the plant's current configuration. Three drawings IX4DB133-1 Rev 23, 1X40B122 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 IX4CB161
4 Rev. 22,1X408121 Rev. 24 and 1XaDB122 Rev. 26 ( AW, 51, end ? RHR respectively). Adminis trative precedure 00101-C " Drawing Control." Step 3.4.4, reoutres that drawing legibility be ensured prior to distribution and engineering procedure 50009.C.
"AS-Built Notices," ';tep 4.6.3, requires ABNs to be legibl? and reproducible. This constitutes a violation of doministrative procedure 00101-C and engineering procedure 50009-C.
This violation is one example of violation 50 824/89ii4 01 ano 50-425/89-15-01, " Failure To Imp! ament Procedures 00101-C cno 50009-C Resulting In TS 6.7.1.a Violation." (2) Piant Housekeeping Conditions - Storage of material and components and cleanliness conditions of various areas throughout the facility were observed to deterfnine whether safety and/or fire hazards existed. (3) Fire Protection - Fire protection activities, stRffing; and ecuipment were observed to verify that fire brigede staffing was appropriate and that fire alarms , f xtinguishing ecuipment, actuating controls, fire fighting equipment, emergency equipment, and fire barriers were orerable. (4) Radiatica Protection - Radiation protection activities, staffing, and equipment were observed to verify proper program implementa tion. The inspection included review of the plant program effectiveness. Radiation work pennits 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 observed to verify that security barries were intact, guard forces were on duty, and access to the Protected Area was controlled in accordance with the facility security plan. Personnel were observed to verify proper display of badges and that personnel requiring escort were properly escorted. Persenel within Vital Areas were observed to ensure proper authorization for the area. Ecuipment operability or proper compensatory activities were verified on a periodic basis. (6) Surveillance (61726)(61700) - Surveillance tests were observed to verify that approved procedures were being used, qualified personnel were conducting the tests, tests were adequate to verify equipment operability, calibrated equipment was utilized, and TS requirements were followed. The inspectors observed portions of the following surveillances and reviewed completed data against acceptance criteria:
--. - . - . - .- - -- ~- . - ---
a 5 _r
-Surve,illance No. Tltle ,-
14000-1 Rev.-17 Operations Shift And Daily Surveillance Logs
,14000-2 Rev. 2- Operations Shift.And Daily Surveillance Logs-14220-1-Rev. 3 Main Turbine Valves Weekly Stroke Test 4
-14228-2 Rev. 1 Operations Monthly Surveillance Logs 14230-1 Rev.-4 Weekly Train- A & 8 Verification Offsite To Onsite Class 1E A.C. Distribution System Circuit Breaker Alignments While i In Modes 1-4 14235-2 Rev. 1 Onsite Power Distribution Operability Verification 14450-2 Rev. 1 RCS Pressure Isolation Valve Leakage
- Test
;14495 1 Rev. 3 TDAFW System Flow Path Verification 14551-2 Rev. 1 CCW Flow Path Verification 14808-2 Rev. 2 CCP And Check Valve Inservice Test 14825-2 Rev. 1 RCS Quarterly. Inservice Valve Test' 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 l independent verification. was r.ot documented for PORY block valves 2-HV-8000A ' and 8. The inspector promptly brought-this to the attention of the Operations Superintendent, 0505. and unit 55. - The: SS took the nece _ sary: corrective action to complets these steps - of the procedure on - the following shift.- It is apparent _ that an inadequate operator and supervisory review was conducted on the previous - shi f t'.
-(7) Maintenance - Activities -(62703) - The : inspector observed maintenance ractivities- tol verify - that correct equipment-clearances were in effect;Jwork requests an( fire .- prevention
, : work permits, ts: required. were issued and being follored; quality control personnel . were _ available for- inspection - activities - as required;: retesting and return of systems to
; service was promptrand-correct; Land TS requirements were being 1 followed. _ Maintenance Work -Order backlog was reviewed.
4 Maintenance was observed and work packages were reviewed for the. following maintenance activities: MWO No. Work Description 18901524 Replace NSCW Torque Switch Limiter Plate Oue To Valve 1HV-1668A Not Stroking Properly
-28902508 Stroke Steam Dump Valves L 28902598 Mair Feed Isolation Valve Repair
6 28902715 Investigate / Rework / Replace Cards As Required To Restore MFP Slave Relay K-620 To Proper Operation 28903135 Reset Power Range Detector Current Per Start Up Test Procedure 2-6SE-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. One example of one violation was identified (paragraph 2.b(1)).
- 3. Startup Test Program Implementation / Verification -
Unit 2 (72302)(724008)(71715) The inspector reviewed the present implementation of the Startup Test Program. Inspected Test Program attributes including review of administrative requirements, document control, documentation of major test events and deviations to procedures, operating practices, instrumentation 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 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 sigt,-offs listed in procedure were maintained current) or by direc+. 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 inspections conducted are listed below: 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: (a) Step 6.2, Initial Criticality per Procedure 2-600-02 (b) Step 6.3, Determination of Low Power Physics Testing Power Range (c) Step 6.4. Boron Endpoint, Isothertnal Temperature Coefficient Measurement (d) Step 6.4.11, Flux Map 2-6SE-02 (e) Step 6.11, Control Bank A Worth l l
1 7 l Power Ascension Test Sequence (72509)(72582)(72583)
- The power : ascension test sequence directing the test activities as contained lin procedure J 2-600-13 was reviewed - during testing. The following-specifi_c tests were paitially wi_tnessed.
,.~
(a)--Step 6.1.1, Adjustment of Nuclear Instruments to 50t Trio Level (b) Step 6.1.7 . Main Feedpump Operation per 12004-C 1
=
(c);" Step 6.1.8, Perform-12004-C , (d) ' Step:6.1.10,.2-6AB-01, Dynt.mic Auto Steam Dump Control ; (e)- Step 6.1.11. 2-6AE-01, Autcmatic Steam Generator Level Control ! Position Indication Test (f) . Step 6.1.20, 2-600-08, Remote Shutdown Test _ '( g ) Step 6.1.21. 2-600-09.- Loss of Offsite Power Test
-(h) Step 6.4.5. 2-6SE-02, Flux Map At 30% Power
-(1)- Step 6.4.7, 2-6SE-03. Operational Alignment Of The Nuclear Instruments ,
L(j)-Step 6.5.3.1. 2-65C-02 Load Swing Test ; ik) Step 6.10.2, 2-6AE-01,. Autcmatic 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 observed theLunit perform the transfer frc:n auxiliary feedwater to main feedwater for- the #3 Steam Generator..- Procedure 12004-C Step 4.1.4, 1 specifies that the transfer is to-be completed as-follows: 4.1.4 TRANSFER. Auxiliary- Feedwater to Main Feedwater one Steam Generator at a- time by-perfonning the following: a.- STA81LI7F ths SG NR level betweenJ45% and 55%,
- b. Slowly CLOSE the Auxiliary Feedwater Supply' Valve and -
OPEN .the BFRV while' maintaining SG level in. progra:n band. . r = c. _ .When the Auxiliary Feedwater Supply - Valve is fully closed Stabilize SG level and then-PLACE the BFRV in
-automatic, :
d.- Repeat valve transfer for remaining Steam Generators,
~
Priori to the .. start uof the transfer, the inspector noted that the Balance-of-Plant ; Operator -discussed -the - transfer 1with -the operator L. controlling Steam : Generator level. The operators decided that the-best f way: to make the _ transfer 'was - for the- BOP operator- to close the Auxiliary L Feedwater Supply. Valve and the other operator would'" punch" .the BFRV into o automatic. The: operators then conenenced' the transfer without discussion [ with the Shift Supervisor. The-BOP operator did however involve the shift supervisor l in. the - transfer by- directing him to display narrow range 'and wide range computer ' trends of 83 ' Steam Generator on the' ERF computer. Upon closing the Auxiliary Feedwater Supply Valve, the SG Water level initially _ lowered. The second operator placed the BFRV into Automatic as previously planned. The BFR'l au:enatic control began to slowly open in L
. . y - . - e- - -.~w , , . . .. , e y +-4. ,
8 order to restore steam generator levels.
-SG level to approximately 64*. _the controller and valvei wer monitoring the inventory of waterThe ERF computer displays were valuable in transient. in_ the steam generator during the level.
The 81 SG had been transferred to its BFRV ca The BOP miniflow valveoperator open. directed a plant equipment operator to fail the feed why the procedure had notThe inspector auestioned the Operations Manager on miniflow valve had to be failed open.been followed for the transfer and why the prior Step 4.1.3g had b The inspector also noted that the and 83 BFIVs were open. een signed off complete when in fact, only the al Procedure 1200a-C, Step 4.1.3.g. states: 4.1.3 9 OPEN the Bypass Feed Isolation Valve and VERIFY the Feedwater Isolation Valve is closed for each SG. The Operation Mana centrol too soon. ger counseled the operators on not going in automatic The failing of the miniflow valve was explained as a necessary evolution in that the flow froa one feedpump feeding two steam generators is at the point when the miniflow valve closes (500 gpm) which affects the generators. output pressure of the feedpump and hence flow to the steam smoother manner. By failing the miniflow valve open the feedpump performs in a Later, the inspector learned that had all four BFIVs 500 gpm and the miniflow valve would have close swapover on the first steam generator. The fact that procedure 12004-C was not followed in Steps 4.1.3.g an 4.1.4 of violationconstitutes a violation of TS 6.1.7 requirements and is one e examp 50-424/89-14-01 and 50-425/89-15-01, " Failure to implement Auxiliary Feedwater To Main Feedwater." Procedure 12004-C -S which proceeded in an orderly fashion except for th computer. the *1 SG trend instead of the 84 SG.When the Shift Supervisor called and was essentially complete by the time the proper display was The following in a smooth of procedure 12004-C, Step 4.1.4, by the operators resulte transfer. Dump Control." the plant experienced a SG level signal specified by procedure was incorrect. Step 6.3.3, directed that a test Procedure 2-6AB-01, signal generated at a T-ref of signal be inserted equivalent to the 0.5 called 553'F - by using Attachment 10.5. (2.3 volt signal)-(pins 26- and 27+).for connection of a Ronan calibrator Mode placed in the T-avg control mode oerAt Procedure the time of S the transient, six of the twelve dumps were isolated. in SG levels resulted in a feedwater isolation. Further The resultant swell details of tne i
9 event is contained in LER 50-425/89-15. This same error occurred on . Unit 1 during the startup program; however, an LER did not result. Unit 2 procedure development did not incorporate the Unit 1 procedure change. Failure to establish an appropriate procedure is an example of a violation of 10 CFR Part 50, Appendix B, Criterion V, and of TS 6.7.1.a. 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 to the discussion on 1.ER 50-425/89-14 in paragraph 4.b(3)(r) for additional information.) The inspector questioned why the identical error on Unit 1 did not result in a more severe transient. While no specific answers are known, speculation was made regarding tha number of steam dumps that 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, B, and C). If Unit 1 had only three unisolated dumps, then the transient would not have resulted in as severe 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 i reYealed that one steam dump was not inservice. The above events regarding establishment and adherence to procedures was discussed with the General Manager on April 6,1989. The inspector addressed observations regarding:
- failures to follow procedure 12004-C, l
failure of the Shift Supervisor to closely control the operator actions.
- failure to have appropriate proced.res in place for control of steam dumps and feedwater pump miniflow valves, excessive eating of food in the control room, and
- telephone distractions to the operators.
In response to the above, the General Manager took action to address these concerns by having by operations manager review and discuss these events with operators and sepervisors. l On April 7, 1989, a feedwater isolation occurred which illustrated another L failure of the operators to implement procodure 12004-C. On April 6, with the unit in Mode 3 on long-:ycle cleanup, the shift supervisor directed that in order to support anothar surveillance that long-cycle cleanup be secured from the control room. Following the surveillance, the cleanup 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 l however no longer represented the plant configuration. Since the action 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 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 sNan generators were cross connected. On April 7, with reactor power at
l 10 ) approximateif 7%, operators noticed that the 81 SG BFRV was at 60% demand, _ v2 and #3 SGs were at % demand, and e4 SG was at 0% demand. Even thougn ' two steam generators gave the indication that only one BFRV was maintaining level, the operators notified !&C to investigate the indication problem. Since SGs 1 and 4 are on the same side of containment, the physical piping layout results in these two SGs being related. While resolving the problem, the operators decided to stroke the v2 MFly as part of a maintenance functional test. As soon as the MFIV was 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 cause is related to the first shif t supervisor f ailing to implement procedure 12004-C, Step 4.1.3, in securing from long-cycle recirculation. This item is an additional example of violation 50-424/89-14-01 and 50-425/89-15-01, " Failure To Imolement Procedure 12004-C To Secure From Long-Cycle % circulation." (Refer to the discussion of LER 50-425/89-15 in paragraph 4.b(3)(s) for additional information.) The proper control of the steam dumps was addressed by the inspector as a concern in that the basis for the P-9 reactor protection interlock assumes tnat all dumps are available with normal pressurizer pressure control. TS 2.2.1, Table 2.2-1, item 18.d. specifies a trip setpoint of ~ 50% where the reactor trip on turbine trip can be blocked. The inspector asked for a review by the licensee to determine if the actual setpoint should be adjusted downward when dumps were not available. Followup of this item will be tracked as IFI 50-424/89-14 02 and 50-425/89-15-02, " Review Licensee Evaluation Regarding Adjustment Of The P-9 Setpoint When Steam j Dumps Are Removed From Service." l The above sections represent a weakness in the area of operations to implement and adhere tc the basic " Power Operation" procedure 12004-C. It becomes apparent when combined with other operations procedure /imple-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 (see paragraph 4) that additional management attention and oversight are needed. Response by licensee management has been noted; however, effectiveness of this effort will require more time to evaluate. l l The startup test program has been relatively successful with only one l noted failure discussed above regarding the steam dump testing. More l 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 l appropriate personnel the ability to be well rested and prepared for the l testing. Three examples of one violation and one inspection followup item were l identified.
1 11 4 Review of Licensee Reports (90712)(90713)(92700)
- 4. in-Office Review of Periodic and Special Reports ,
This inspection consisted of reviewing the below listed reports to i determine whether the information reprted by the licensee was technically adequate and consistent with the inspector knowledge of the material contained within the report. Selected material within the report- was questioned randomly to verify accuracy and to provide a reasonable assurance that other NRC personnel have an appropriate document for their activities. Monthly Operating Report - The inspector reviewed the Unit 1 and 2 monthly operating reports dated March 15, 1989. This review included the data revision for an earlier Unit 1 report. The inspector had no coments . No violations or deviations were identified.
- b. Licensee Event Reports and Deficiency Cards Licensee Event Reports and Deficiency Cards were reviewed for potential. generic impact, to detect trends, and to detemine whether corrective actions appeared appropriate. Events which were reported pursuant to 10 CFR 50.72, were reviewed as they occurred to determine if the technical - s'pecifications and other regulatory requirements were satisfied. In-office review of LERs may result in further followup to verify that the stated corrective actions have been completed or to identify violations in addition to those described in
~
the-LER. Each LER is reviewed for enforcement action in accordance with 10 CFR Part 2, Appendix C, and if the violation is not being cited, the criteria specified in Section V.G of the Enforcement Policy was satisfied. Review. cf DCs was performed to maintain .a realtime status of deficiencies, determine regulatory -compliance, follow the licenne corrective actions, and assist as a basis for closure of the LER shen reviewed. Due to the numerous.DCs processed only those DCs, wNch result in enforcement action 'or further inspector followup with the licensee at the end of the inspection are listed below. The LERs and DCs aenoted with an asterisk indicates that reactive inspection occurred at the time of the event prior to receipt of the written report. (1) Deficiency Card Review-(a) DC'l-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 l of gas contained in the tank. This deficiency will be i followed up on wnen submitted as an LER.
12 1 (b) *0C- 2-89-985, " Unit 2 Turbine Trip Following Standby Stator ' Cooling Pump Trip." On April 22, 1989, a turbine trip occurred as a result of a loss of stator cooling during a routine swapping of stator i cooling pumps. When the standby pump was started both : pumps tripped, causing the turbine to trip. While attempting to stabilize tho plant, a feedwater isolation - occurred due to Hi-Hi SG level on SG #3, leading to an AFW actuation when the running MFP tr_ipped. The reactor was stabilized at 2% with the SG being fed from AFW, This deficiency will be followed up when submitted as an LER. (c) DC 2-89-1027 " Reactor Trip From 60%. Power On A Turbine Trip." On May 2,1989, the u'11t received a re ctor trip from 60% power on a: turbirie trip. AFW actuated on lo lo SG level 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.- . (a) 50-424/09-06,- Rev. 'O. "!nadequate Functional- Test Leads To Improper Termination Of Limiting Condition For Operation." On: January 30,-1989, the Gaseous-Waste Processing System's-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 replaced and tested on February 7.1989. On February 23, 1989.. a review of - the- work order discovered that the 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 2 procedure'was revised. The appropriate personnel _have been counseled. Proper checks now-exist to ensure all required testing is performed pricr to- exiting a LCO. This item represents a violation of NRC requirements which meets the
. , - - , .--r, ..-s. - - - -
13 criteria-for non-citation. In order to track this item, the following licensee-identified item 15 established. NCV 50-424/89-14-03, " Failure To Perform Recuired Testing Per Surveillance Requirements Results In TS 4.3.3.10 Violations - LER 50-424/89 06." (b) 50-424/89-07,_Rev. 0, " Failure To Take Required Temperatures Results In inadequately Performed Surveillance." 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 Building Room B008 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 B008 (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 failed to note the missing temperatures when the data sheets wer3 reviewed. Corrective actions included counseling of the operators and shift supervisors on the importance of ensuring that= all required technical 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.
NCY 50-424/89-14-04, " Failure To Take Required Temperatures Results'In Inadequately Performed Surveillance Resulting in A TS Violation - LER 50-424/89 07." (c) 50-47.4/89-08, Rev. O, " inadequate Review Of Drawing Change Results In Use Of Improper Breakers." On February 23, 1989.- it was discovered that 125V DC breakers for motor-operatea valves in the Turbine Drive *i Auxiliary Feedwater pump system were not the proper size. The breakers, as installed and as shown -on design drawings 'were 15 amp thennal magnetic but should have been 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. L
14 LCO 1-89-121 was entered. The breakers were replaced. - successfully tested, and the LCO was exited. The cause of this event was due to inadequate review by the responsible engineer when a drawing change notice corrected the MOV 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 incider.t to be an isolated case. This item represents a violation of NRC requirements which meets the criteria for non-citation. 1.n order to track this item, the following licenser-identified item is established. NCV 50-424/89-14-05, " Failure To Conduct An Adequate Engineering Review Of The AFW Electrical System Which Led To AFW Inoperability Resulting in a TS 3.7.1.2 Violation - LER 50 424/89-08." (rl) 50-424/89-10, Rev. O " Valved Out Radiation Monitor Leads To Unmonitored Liquid Waste Release." On March 14, 1989, a plant operator was preparing to perform a liquid waste release per procedure 13216-1,
" Liquid Waste Release." The operator verified that radiation monitor 1-RE-0018 was registering normal 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 1-RE-0018 and found it was not registering above background levels. A brief starth found that the. inlet valve to 1-RE-0018 was closed. This valve, 1-1901-X4-144, was opened; 1-RE-0018 registered the proper activity level; and
.the liquid waste release continued. - The release was completed and the closure of the inlet valve resulted in liquid weste being released unmonitored which is a condition prohibited by Technical Specification 3.3.3.9.
. The operator omitted the performance of a pre-release line 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.
Thi* item represents a violation af NRC requirements which meets the criteria for non-citation. In order to track this item, . the following licensee-identified item is established. NCY 50-424/89-14-06, " Failure To Follow Procedures While Conducting A Liquid Waste Release Resulting in A TS 3.3.3.9 Violation - LER 50-424/89-10."
15 (e) 50-425/89-05 Rev. O, " Inadequate Review Of A Modification Results In A Technical Specification Violation." . On March 17, 1989 Automatic Surveillance Technicalwhile investigating a problem with th system, field voltage measurements were taken that revealed an electrical short on valve 2HV-19051, tha Reactor Coolant Pump *1 thermal barrier isolation vahe. -The valve was required to he operable upon entry into Mode 4, which had occurred on March 4 A Surveillance had been performed on February a, 1989, to prove operability of 2HV-19051; however, a change to the ASTEC systet wiring on February 10 resulted in valve 2HV-19051 being inoperable. The cause of this event was the issuance of an incorrect As-Built Notice. Corrective actions included counseling the appropriate engineering personnel involved, training for all engineering personnel recently transferred from the Unit 2 test organization on use of the ABN, and issuing a second ABN to restore the system to its original configuration. 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 establisheo. 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 Be Operable Prior To Entering Mode 4 - 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 warming main steam lines as part of procedure Temperature And Pressure,"12002-2 " Unit Heatup To Normal O Features actuation. A step automatic Engineered Safety of the procedure called for handswitches HS 40047/48 to be operated to resat the mein steam isolation signal. However, handswitches HS 40068/69 were operated. - These switches reset the -low steamline pressure safety injection and steamline isolation logic, removing the biceking , signal. Since the main stram line pressure was below the safety injection setpoint pressure, 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 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 51 handswitches, adding cautions to the handswitches, and incorporating details of f
16 c this event into training. This item was formally discussed 1989. following the Enforcement Conference on March 22, . This item reoresents 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 a25/89-15-05, " Failure To Follow Resulting In inadvertent $1 Actuation - LER Procedures 50-425/89-06." (g) Device Results in Containment Ventilation isola On March 19, 1989, while restoring the Plant Effluent Radiation Monitoring System to service the plant experienced an automatic Engineered Safety Features actuation Isolation. which resulted in a Containment Ventilation isolate containment ventilation. Appropriate valves and damp Control room cerators verified using that no abnormal radiological conditiW. existed 2RE-0002/0003. 2RE-2565, was placed in bypass.The monitor that actuated the equipmert The CVI was reset and position. that actuated was. returned to normal operating Due to an earlier SI, power was lost to most of the PERMS system. On restoration of power, the computer parameter files are initialized with a -9.99E-20 value. The from computer each monitorreplaces this value with oarameters received multiplexer, comu. Due to a.comunication failure of a no value was recewed for 2RE-2565.nication When the mutiplexer with 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, causing the CVI actuation. Corrective action is a procedure revision to require 2RE-2565 to be -placed in bypass- when parameters, the computer is initialized to receive (h) 50-425/89-09, Rev. O,
" procedure Misinterpretation. Leads To 1. ate Surveillance Testing."
On March 20, 1989, a diesel fuel oil shipment arrived onsite tanks. for offloading into the Diesel Fuel Oil Storage A technician obtained and analyzed a sample. technician and his foreman interpreted a note in theThe analyses scheduling procedure to mean that the neutralization number and mercaptan were not required to be performed. analysis andIn fact, only the mercaptan was exempt from the performed. neutralization number was required to be After the analysis found the other fuel properties to be satisfactory, the shipment-was unloaded
17 into the OF05 tanks. Meanwnile, a second diesel fuel oil I shipment arrived onsite, a sample was obtained and analyzed - as before and unloading into the OF05 tanks began. A laboratory supervisor reviewed the data sheets and question the omission of the neutralization number from the data sheets. After the requirement was clarified. the technician obtained the original samples from each shipment and determined that the neutralization number of each was 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 represents a violation of NRC requirements which meets the criteria for non-citation, in order to track this item, i the following licensee-identified item is established. i NCV 50-425/89-15-06, " Failure To Establish An Adequate Sampling Procedure For Diesel fuel Oil Per TS 6.7.1.a - t.ER 50-425/89-09." , (i) 50-425/89-10, Rev. O
" Radioactive Discharge Without Peruit t.eads To Technical Specification Violation."
Technical Specification 3/4.11.1 requires that releases of radioactive materials to unrestricted areas be sampled and analyzed for appropriate alpha, beta, and gama emitters. 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 permit was required. On 4 March 9, a plant operator released the tank contents to the Unit 2 Waste Water Retention Basin without a permit. On March 14 during a review of releases, it was found that no permit had been issued for. the March 9, release. The permit ensures that required samples have been taken, analyzed and are within allowable limits for releases. Procedure- 13211-2, " Turbine Building Orain System," required that sample analysis . be used to -detemine how drain tank contents are to be processed but did not specify
' that a release permit-may be required. The cause of this event was that tne operator did not obtain a radioactive release permit prior to releasing, Procedure 13211-2 has been revised to provide specific instructions that a radioactive release permit may- be required for releasing the contents of a turbine building drain tank. Also, at l
shift briefings, operators were reminded that waste permits i are required prior to release of radioactively contaminated l. tank contents. This item represents a violation of NRC l- requirements which meets the criteria for non-citation, in order to track this item, the following licensee-identified item is established. NCV 50-425/29-15-C', " Failure To Obtain A Radioactive Release Pemit Prior To Releasing Radioactive Materials Tc l 1 n
, ~ . _ - . -- -- -~- -. . . - . .- .. - . - ---
e 18 > 1 t Unrestricted Areas _ Resulting in A TS 3/a.11.1 Violation -
~
-LER-50 425/89-10." ,
(j) 50-425/89-12, Rev. 0 " Operating Incorrect Switch Results In;lnoperable Monitor Requiring Entry Into TS 3.0.3." t On March 30, 1989, while performing 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 Le6kage Detection System and ,
-2RE-2562C being inoperable. With 2RE-2562C inoperable the LCO for Tech *ical Specification 3.4.6.1 could not be_ met. ,
- -r 2RE-2562C was restored to service and-TS 3.0.3 exited. The cause of this event was _ personnel error. The~!&C technician 1 failed -to pay-attention to - detail ' when
- activating plant equipment. The purge switch was activated i instead ~of the paper drive. . Corrective actions included counseling- the. individual and issuing a memo to-.all I&C l personne; concerning attention to detail when performing maintenance / trouble shooting on. plant equipment. This i_ tem '
represents a violation of NRC~ requirements which meets the i criteria for non-citation. .in order to track this item, the following licensee-identified . item is established.
'NCV 50-425/89-15-08, " Failure 'To - Follow Procedures While Perfnruing Maintenance On 2RE-2562A Resulting In The-Plant Operating In A Condition Prohibited By TS Thus Requiring Entry Into-TS 3.0.3 - LER 50-425/89-12."
.(k) 50-425/89-13, 'Rev. _0, " Flood Barrier Removal Leads To Auxiliary Feedwater Inoperability."
Technical < Specification -3.7.1.2 requires that three- , independent' steam generator: AFW pumps- and associated' flow
- paths:be operable in_ Modes 1, 2, and-3.- On March 30, 1989, .
Plant personnel were' conducting a routine walkdown. They ! found - a flood = protection barrier removed from the wall' between the AFW discharge piping room (room 105) and the Turbine Driven AFW pump room (room 106). The barrier was replaced and-the.T5 action statement was exited. The 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
19 implementing 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 whicn meets the criteria for non-citation. In order to track this item, the following licensee-identified item 15 established. NCV 50-425/89-15-09, " Failure To Maintain The Auxi'iary Feedwater System Operable Resulting In A D nditj % Prohibited By TS 3.7.1.2. - t.ER 50-425/89-12." (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 (tuto 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 wah 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 immediately 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," will be revised to caution operators of a possible actuation of transfer of control to the control room. (3) The following LERs 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 Refueling 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
20 available for plant shutdown. 1 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 actually between the "91ves and the RWST. Thus, if a seismic event causes line failure to occur, the broken line could have potentially drained the RWST to a level below minimum requirements for plant shutdown. The cause of this condition was determined to be the failure of A/Dy to advise Bechtel of a change in valve weights from those originally shoan on the valve drawings and an error by a Bechtel Power employee in the initial review of this condition. Corrective actions included adding an additional pipe support and reviewing other safety related valves for weight discrepancies. The inspector has no further questions. (b) *50-424/88-16 Rev. O, " Water Leakage Into Control Room / Potential Exists For A Safety System Failure." On June 3, 1988, smoke from an electric duct heater actuated smoke detection alarms, Although sprinkler heads did not actuate, water from the preaction 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 the Reactor Coolant System which were promptly addressea ' and corrected by control room personnel. On June 5, 1988, it was concluded that a condition existed which alone could have prevented the. fulfillment of- the safety function of a system needed to mitigate the consequences of an accident. The cause of this event is an inadequate design of the control room ceiling penetrations which are supposed to be watertight. Corrective actions - were verified complete. l This item resulted in a NRC violation 50-424/88-24-01. l (c) 50-424/88-19, Rev. O, " Inadequate Installation Leads To Containmant Ventilation isolations." I On June 10 1988, a CVI occurred due to an apparent power i supply f a, lure in radiation monitor 1RE-2565C. The apprcpriate dampers and valves actuated as designed. Control room personnel verified that no abnormal condition existed. 1RE-2565C was bypassed and the CVI signal was reset. Later, the same day, another CVI occurred, when pla t personnel removed 1RE-2565C from bypass in order to reeater monitor setpoints.- Again the proper dampers and valves actuated and control room personnel verified that no abnormal radiation condition existed. 1RE-2565C was again placed in bypass and the CVI signal was reset. An investigation deronstrated that the cause of the CVI was an l
i
~
21 inadequate installation which left a flow transmitter shield wire exposed that electrically grounded, simulating a loss of power. Corrective action included insulating the shield wire and new default values were installed; , (d) 50-404/88-20 Rev. 1, " Inadequate Breaker Leads To Condition Prohibited By Technical Specification." On June 29, 1988, it was determined that ten containment penetrations ;ay not have adequate redundant overload protection, as required by Regulatory Guidi 1.63. The redundant protection was not provided because in each of the ten penetration circuits one of the two breakers- used was-magnetic-only, which di6 not provide adequate overload protection for the penetration. The other breaker provided was a thermal-magnetic and provided adequate overload protection for the penetration. Since the magnetic-only breakers did not provide the redundant overload protection, the. requirements of Technical Specif t::ation 3.8.4.1 for operability was not satisfied. When it was detemined that redundant overload protection may not have been adequate over the entire range, the identified containment penetrations were declared inoperable and the requirements of Tec5nical Specification 3.8.4.1 were satisfied while the breakers were- being replaced. Prior to the operation of Vogtle Unit 1, a construction test was performed for etch breaker to verify its tripping function. All tests were performed _ satisfactorily and the breakers declared operable. The - inspector has reviewed documentation whicn
- u1dicated that the corrective action was complete. The magnetic-only ' breakers were replaced with themal-magnetic breakers.
(e) *50-424/88-22. Rev.1, " Failed Potential Transformer Leads To Turbine / Reactor Trip." 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 isolated and the Auxiliary Feedwater system actuated, Control- room - operators responded properly to assist in plant stabilization. An investigation revstaled that tne failure of a potential transfomer caused the primary fuse to blow. The resultant trartlant 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 includec replacing all primary pT fuses, PT 2A, and the malfunctioning circuit boards in the GENERREX systen. The GENERREX system's operational history has been evaluated and additional adjustments are not (- L . _ _. .. _ _ _ __ _ _ . _ _ _ __ ,
. 22 considered necessary at this time. Engineering review of 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. However, a more appropriate test method has not been identified. This LER was closed in report 50-424/88-37 (f) 50-424/88-23, Rev. O, " Inadequate Design Leads To Condition Prohibited By Technical Specification." On July 29, 1988 LER 50-424/88-20 was issued, identifying that several electrical penetrations may not have been provided with adeavate redundant overload protection. As a result of the interpretation for reportability of that event, two previously identified deficiencies have been re-eval ua ted for reportability. As a result of the re-evaluation, an event that was discovered on August 14, 1987, was determined to be reportable on July 28, 1988. 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 protection may not have been adequate for the entire range of protection as required by Regulatory Guide 1.63. Technical Specification 3.8.4.1 required that electrical penetration overload protection may not have been pr"vided for several penetrations, Unit 1 may have been opera'ing in a condition prohibited by TS until the event was discovered. For each event the limiting condition for operation action statement for TS 3.8.4.1 was implemented on tne event discovery dates of July 7, 1987, and 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, !4, 34, 41, 60, and 61, concerning t.0 size conductors. The inadequate overload protection was discovered during a broadness review for Unit 2 by the designer, Bechtel Power Corporation. The inspector verified the work complete by reviewing the closed MW0s.
(g) 50-424/88e26, Rev. O, "Use Of Improper Tools !.eads To Containment Ventilation Isolation." On September 7, 1988, an electrician was in the process of installing shor ".ing bars into fuse holders following the completion of an electrical switch replacement. T? e 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
23 dampers a'?uated. Control roem personnel verif' d that no abnormal iddiation Londition existed by observ ug recuecent monitors. The control room personnel and the electrician imed : ltely confirmed that tM electrical short had initiated the CVI. The cause of t!ds event was the use of p~ an improper tool oy the electrician. Fv3e pullers provided to the electrician would not fit between the inserted shorting bars, so he used needle-nose pliers to perform the insertioi s. These pliers made the electrical short by simultaneously contacting two shotving bars following one shorting bar's insertion. Appropriate personnel were advised to avoid the use of needle nose pliers or makeshift tools for installation of fuses or shorting bars. The proper size fuse-pullers were madt available. (h) 50-424/88 30 Rev. O, " Surveillance Missed Due to Inoperabl* 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 Systerm had not been implemented within tha plant computer software as inteeded. The absence of this feature means the Rod Position Deviation Monitor is operable for this functio and that surveillance 4.1.3.2 has not been met. when required, since 'ssuance of the Unit 1 license. The surveillance required operability determination of the digital rod position indicators. For this detemination, the DPIS must be verified to be with + or - 12 steps of the DRPIS every 12 hours, except when the RPDM is inoperable, then the requirefnent is at least once per i nours. As the plant staff were unaware of the software om';sion, they did not take the required action to manually make the comparisons every 4 hours as required. The cause of this event was the om'ission of appropriate rcd supervision programs in the original vendor supplied computer software specifications. Corrective actions include increased frequency cf the surveillance and an evaluation to deterinine if either changes to the computer sof tware are feasible or changes to licensing documents are requi ed. The inspector reviewed documentation which indicated that the corrective action was complete. This item represents a violation of NRC requirements which meets tha criteria for non-citation. In order to track this item, the following licensee-identified ttem is established. 1 NCV 50-424/89-14-07, " Failure To Conduct Surveillance Resulting in A Violation Of TS 4.1.3.2 - t.ER 50-424/88-30."
24 (i) *50 424/88 41 Rev. O and 1 " Containment Purge Supply Isolation Valve Inoperable Due To Failure To Fully Close." On December 13. 1988, while performing a revised Type C Local Leak Rate Test for surveillance of the containment 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 conditico 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-Hi 2626A f ailing the lest 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 issuteg LCO 1-88-922, imediate manual seating of the valve and successfully repeating the LLRT, and establishing conservative administrative controls to ensure that each 24-inen purge isolation valve. if cycled, will be either ' manually seated or have an LLRT performed, as appropriate. Procedures 1%25-1, 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." On February 10. 1989 Control Room operators received Main Feedwater Pump Turbine "A" high vibration alarms. A check of the vibration monite'* system showed a vibration of only 1.2 mils. (The vibration system alarms at 3 mils and trips at 5 mils). Shortly thereaf ter. MFP "A" tripped. Steam /feedwater flow mismatch alarms were received on al? four steam generators. Turbine load was manually reduced 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 '4 reached 40% level and the Shif t Supervisor directed the reactor to be manully tripped. Feedwater isolation and l start of Auxiliary Feedwater pumps occurred as expected, i However, the Turbine Driven AFW pump tripped on overspeed ! after starting. The cause of the MFP high vibration trip was not positively identified. The cause of the TOAFW pump overspeed trip, although not positively identified, may l have been caused by particulate contamination of the lube l oil, which serves es the control system hydraulic fluid. Corrective actions included temporarily installing vibration instrumentation to collect MFP vibration data. Additional surveillances were also performed on the T0AFW pump to ensure operability.
25 i I (k) 50 424/89-09 Rev. O. " False Radiation Monitor Signal Caused Containment Ventilation isolation And T5 3.0.3 Entry." On March 13, 1980, radiation monitor IRC-0003 spiked high causing a Containment Ventilation isolation. Appropriate valves and dampers actuated from t.he CVI signal to isolate containment ventilation. LCO 1-89-155 was entered for 1RE 0003. Radiation monitor 1RE 0002 was out of service for a surveillance ud 1RE-2565 was not operable because of reliability concerns. Technical Specification 3.3.2 Table 3.3 2, requirds a minimum of two of the three channel be operable, but there is a provision for operation with .' only one channel in operation. An ontry was made into T5 3.0.3 since all three channels were inoperable. Control room operators verified that no abnormal radiological conditions exi:ted using 1RE-0002, which was functional but 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 CV! Signal was reset. The cause of :his event was the failure of the detc; tor tube. The tube was replaced; however, the replacement tube did not function properly and required replacement due to degradation of the voltage plateau. The replacement tube was monitored and the monitor was declared operable. (1) 50 425/89-01, Rev. O, " Spurious Signal Resulting From Circuit Board Causes Control Room Isolation." On February 14, 1989, a Control Room Iso'.ation occut.ed due to a spurious signal from radiation monitor channel 2RE-12116. Prior to this-actuation, the Safety Parameters Display Console had received intemittent trouble light indications from the channel. Control room operators verified no high radiation condition existed. The monitor's output was blocked, a LCO was entered, the CRI signal was reset, and nonnal ventilation was established. Radiation monitor channel 2RE 12116 was returned to service 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 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 f.;;r proper operation and return of the monitor to service.
)
l i 26 (m) *50-425/89-02, Rev.0 " Opening Discharge valves Causes Plant Operation Outside Of Technical Specifications." Technical Specification Section 3.4.1.a.2 states "
... Reactor Makeup Water Storage Tank discharge valves
( 1208-04 175, 1208-U4 176, 1208-U4-17 7, and 1208-U4 183) shall be closed and secured in position (in) Mode 5 with 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 ci ange, new shif t personnel realized that the reactor coolant system loops were not filled and that the two open 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 RCS above the loops to the reactor vessel flange level constituted a " loops filled" condition, after which opening the discharge valves would have been pemissible. With the discharge valves open, an inadvertent dilution event of the RCS could have been initiated. A TS interpretation of what constitutes " loop: filled" has been added to the Operations Required Reading Book. The personnel involved were counseled regarding the importance of complying with TS. lo pector followup determined that prior to the Mode 5 en.ry, the 55 had been asked to open these same valves to allow chemistry to add primary chemicals. At that time, the SS was aware that TS 3.9.1 required the valvet to be maintained shut in Mode 6 and thought that the change to
- Mode 5 would allow .he evolution. TS 3.4.1.4.2 however,
- also controls these valves when the RCS loops are not 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 removal of the RMWST valves to the CVCS was a discussion item at the shift turnover, however, neither SS recognized the consequences. Later in the shift, the deficiency was identified and corrected. This item was fomally discussed following the enforcement conference on March 22, 1989.
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. NCY 50-425/8915-10. " Failure To Maintain 1MWST, Discharge Valves Shut Closed And Secured in Position While in Mode 5 Resulting in TS 3.4.1.4.2 Violation - 1.ER 50-425/89 02." (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 for the initial heatup, preparations were being made *.o
i 27 perfonn the Pressure Isolation Valve i.eakage Test. In order to ensure proper pressure across the valves to be tested, the Shif t Supervisor decided. without an approved ! procedure, to depressurite the Residual Heat Removal system, using the RHR test return valves. The $$ directed a momentary opening of these valves. This resulted in the return line valves being lef t open for approximately 14 i hours, reducing the flow capacity of both RHR trains. and l leading to operation under Technical Specification 3.0.3 i provisions. This event was caused by (1) operations , oersonnel attempting an evolution without approved l procedural guidance (2) lack of closed loop consnunication, , and (3) inadequate system status sensitivity by the operations shif t team. Corrective actions include (1) couns& ling the Shift Supervisor and briefing of each operating crew by th Plant General manager on the importance of conducting plant evolutions with approved procedures, (2) changing the appropriate procedure, (3) stressing precise control room communications, (4) l Stressing sensitivity to system status in shif t briefings and requalification training, and (5) improving the locked 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. . (o)'50425/89-04, key. O, " Reactor Coolant System Leakage During Check Valve Testing " On March 9, 1989, with Unit 2 in Mode 3, plant operations personnel performed a pressure isolation valve leakage test. The Primary Coolant Loop e3 Cold Leg Check Valve (2-1204-U6-085) exhibited excessive leakage. A Notification of unusual Event w:s declared, because the i 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 tertninated. The event was caused by excessive wear on internal check valve components. Wear wAs found 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 into the lock block. The disc anns are notched out for ' alignment with the pivot pin. Wear was found on both 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. i
28 (p) "50 425/89-08, Rev. O " improper Control Of Steam Generator Water Level Leads To Feedwater llolation." , On March 19, 1989, onit 2 hestup was in progress. The unit Balance of-plant operator was manually controlling the steam generators water levels when a technician requested - his assistance in performing a surveillance test. The 80P operator lef t the front panel to go to a back panel area. , When he returned several minutes later, he found that an automatic feedwater isolation had occurred because SG e4 had exceeded the 787. (narrow range) high-high water level setpoint. The operator stopped the feed to SG '4, returned the flow to nortcal, and long cycle recirculation was re established. 'he 80P operator interded to leave the . front panel '9r vty a few moments and did not request relief. This is " d'r et cause of this event. s Contributing i.e &it r"..t was the Shif t Supervisor's omission in av Iq1tm . dedicated Steam Generator Water Level Controller b.t.a is the plant policy v'ien manual SG feeding is in progr'ess. The 80P operator was counseled regarding the 1mptance of maintaining a continuous watch ' on operations in progress or else requesting relief if 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 forinally discussed following the enforcement conference on March 22, 1989. This item represents a violation of NRC requirements which meets the criteria for non citation. In order to track this i tem, the following licensee-identified item is established. NCY 50-425/8915-11. " Failure To Exercise The Duties And Responsibilities Of The R0 And SS As Delineated in Operations Procedure 10000-C - LER 50 425/89-08." (q) *50-425/89-11, Rev. O. " Valve Closure leads To Non-Compliance With Technical Specifications." Technical Specification 3/4.5.2 requires that the Safety 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 Coolant System cold t.egs (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 $1 pumps from being capable of providing automatic injection to the RCS cold legs upon receipt of a $1 actuation signal. On March 26, while considering LER 2-89-003 (both trains of Residual Heat Removal rendered inoperable due to common valve , manipulations) and similar situations for other f-
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29 safety related systems, a shif t supervisor realized that the system operating procedure for filling 51 accumulators .- at low RCS pressure reautres closure of 2HV 8835 while in Mode 3. Upon discovering th'* a review of the Unit I and Unit 2 accumulator fills was nitiated. Nine separate instances were identified for Unit 1 when 1.HV.8835 was closed while in Mode 3 in addition to the single occurrence on Unit 2 $pecified previously. The cause of these events is inadequate procedures whicn did not prevent closure 2HV-8835 during Mode 3 or recuire accumulator fill prior to Mode 3 entry. The procedures are being changed to correct these inadecuacies. Future followup on this t,ER corrective actions will be in closecut of the violation. 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 St Operable While Filling . Accumulators. (r) '50-425/89-14 Rev. O. "Feedwater Isolation Results From ' Error In Startup Test Procedure." 1 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 opening 10% to 15t as expected. This led to a steam < generator water level swell and a feedwater isolation due to SG #4 reaching the high-high level.- Main feedwater isolation occurred as designed, and the safety grade 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 test procedure, which called for an incorrect test signal, was corrected and the remaining startup tests are being 1 reviewed to ensure that proper connections are specified, Sliding links associated with MFP "A" circuits were found open and are believed to be an oversight from the Unit 2 > construction phase. Similar sliding links were inspected to ensure closure. 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 ' Actuations." t On April 5,1989, a spurious trip of Hain Feedwater Pump "A" generated a Feedwater Isolation signal and automatic actuation of the Auxiliary Feedwater System. On April 7, a
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. 30 FWI and AFW actuation occurred when a steam generator reached its high-high level setpoint during a test of a Main feedwater Isolation Valve. On April 9, a second spurious trip of hfP "A" generated a FWI and subsequent AFW actuation. The cause of the April 5 and April 9 events was logic circuits.boards faulty circuit in the Solid State Protection System The April ? event, although not directly caused by a faulty circuit card, was a conseauence of the valve lineup used to functionally test repairs made following the April 5 event. The lineup of long cyr.le recirculation was not ,nroperly restored prior to resumption ,
of startup testing. Corrective actions include replacing the fou1ty circuit boards and counseling plant operators regadini 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 Jaragraph 3. One example of a cited violation and thirteen non cited violations were identified.
- 5. Action; on Previous inspection findings - (92701)(92702)
- a. (Closed) Violation 50-424/87-30 03, Valve." " Failure To Properly Close The inspector reviewed the licensee response dated July 13, 87 Valve No. 1-1208 U4-348 has had the lock removed to preclude 'sture errors in positioning from the remote operator,
- b. (Closed) Violation 50-424/88-05-02, " Lack Of Material Control."
The inspector reviewed the licensee response dated March 10, 1988. 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 Perfonn An Analysis Which Evaluates Their Failure."
The inspector reviewed the licensee response dated September 15, 198L and reviewed completed MW0s 18900130 and 18900180. During this 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.
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31
- d. (Closed) IFI $0 424/88-43 01 " Verify Resolution Of Restoring The -
55MP To A Condition To Correc,tly Indicate The Operability Status." ' t' The licensee corrected the condition by implementing a design change which removed the Boric Acid Pump Motor handswitches as an input to the $5MP. The inspector verified the change was implemented on Unit 1. Following the verification, the inspector noted that Unit 2 l had not implemented a similar change. The inspector was informed that design change MOD 89 V2M039 was being developed for Unit 2. The inspector considered the late implerentation of a Unit 2 change to be : a weakness in the area of- engineering support in maintaining the designs both units identical as possible. This change involves the ! lifting of two leads in each train panel. To track the accomplishment ' of Unit 2 change, the following inspector followup item is identified. IFl 50-425/89-15-03, " Verify Resolution Of Restoring The 55MP To A Condition To Correctly Indicate The Operability Status."
- e. (Closed) Violation 50-424/88 56-01, " Failure To 1mplement 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 responsibilities. 43006 C was revised to include controls for health physics :
- f. (Closed) Unresolved item 50-424/88-56 02, i
" Review l.icensee Evaluation Of Compliance To 10 CFR 50.62."
This item concerned the sensitivity of unit personnel to the proper operation and maintenance of AMSAC . equipment. The Itcensee 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 operational. . Failure to comply with 10 CFR 50.62 was the result of a failure to establish adequate procedures. Failure to comply with 10 CFR procedures.
-50.62 was the result of a failure to establish adequate This itum is considered to be one of the examples of violation 50-424/89-14-01 and 425/89-15-01, " Failure to establish adequate '
procedures-to ensure AMSAC was available,
- g. (Closed) Violation 50-424/88-61-01, " Failure To implement Operations Procedure- 10001-C, Required By TS 6.7.la, To Annotate And Vertfy i Proper Operations Of Control Room Chart Recorders."
In the licensee response dated Mare,h 7,1989 to the Notice dated i January 20, 1989, the licensee comitted - to full compliance on January 31, 1989, upon issuance of standing order C-89-01. This-
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l e ! i e standing order was reviewed by the resident inspector on March 24, ! 1989, and was found to be satisfactory. : One example of a cited violation and one inspector followup item were identified. !
- 6. Exit Interviews - (30703) !
b The inspection scope and findings were sumartred on May 5,1989, with those persons indicated in paragraph 1 above. The inspector describeo the areas inspected and discussed in detail the inspection results. No dissenting coments were received from the licensee. The licensee did not ! identify as proprietary any of the materials provided to or reviewed by ( the inspector during this inspection.. Region based NRC exit interviews ' 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: , e
" Failure To Implement Procedures 00101-C and 50009-C Resulting in TS 6.1.1.4 Violation" partgraph 2.b(1) l
" Failure to Implement Procedure 12004-C Step 4.1.3g and 4.1.4 for Perfonning 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)
" Failure To implement Procedure 12004-C To Secure From Long Cycle l Recirculation" - paragraphs 3 and 4.b(1)(s)
" Failure To Establish An Appropriate Procedure To Maintain 51 Operable While Filling Accumulators" - paragraph 4.b(3)(q)
" Failure to establish adequate procedures to ensure AMSAC was available" - paragraph ! '
i IFt 50-424/89-14-02 and 50 425/8915-02, " Review Licensee Evaluation Regarding Adjustment Of The P 9 Setpoint When Steam Dumps Are Removed From Service" - paragraph 5' 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 50-42_4/89-14-03, " Failure to perform Required Testing Per : Surveillance Requirements Results In 15 4.3.3.10 Violations - LER 50-424/89-06" - paragraph 4.b(2)(a) ,. . - ..-. - - , .. - . - - - - ., - ._ _ ._a
l 33 NCY 50 424/69 14-04, " Failure To Take keoutred Temperatures Results in Inadequatel i Performed Surveillance Resulting in A TS Violation - LER 50 424/89 0 " - paragraph 4.b(2)(b) { NCY 50 424/8914 05, " Failure To Conduct An Adequate Engineering Review ; Of The AFW TS 3.7.1.2 Electrical Violation - LER 50-424/89 System 08" -which Led paragraph 4.b(2) To AFW Inoperabilityi Re l NCV $0 424/89-14 06, " Failure To Follow Procedures While Conducting A ! Liquid 50 Waste 424/89 Release 4.b(2) 10" - paragraph Resulting(d)in A TS 3.3.3.9 Violation - LER NCV 50 424/8914 07, " Failure To Conduct Surveillance Resultin violation Of TS 4.1.3.2 - LER 50 424/88 30" - paragraph 4.b(3)(h)g in A NCY 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 Be Operable Prior To Entering Mode 4 - LER 50 425/89-05" - paragraph 4.b(2)(e) NCV 50-425/89 15-05, " Failure To Follow Procedures Resulting in inadvertent 51 Actuation - LER 50-425/89 06" - paragraph 4.b(2)(f) NCY 50-425/89-15-06, " 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 Prior To Releasing Radioactive Materials To Unrestricted Areas Resulting i in A TS 3/4.11.1 Violation LER 50-425/89 1b" paragraph 4.b(2)(1)
NCV 50-425/89-15 08, " Failure To Follow Procedures While Perfoming 1 Maintenance On 2RE-2562A Resulting In The Plant Operating in A Condition Prohibited 8y TS Thus Requiring Entry Into TS 3.0.3 - LER 50 425/8912" - paragraph 4.b(2)(j) 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. - LER 50-425/89-13" - paragraph 4.b(2)(k) , 1 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 - 1.ER 50-425/89-02" - paragraph 4.b(3)(m) NCY 50-425/89-15 11 " Failure To Exercise-The Duties And Responsibilities
- 1 Of The R0 And SS As Delineated in Operations Procedure 10000-C - LER 50 425/89 08" - paragraph 4.b(3)(p) l The stren testing (gths in the areas ofthe maintenance [
paragraph 3) and weakness (paragraph in the area 2.b(7)) o.' operations and startup (paragraphs 3, 4.b(2), and 4.b(3:' were also discussed. l-
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34
- 7. Acronyms And Initialism '
ABN As Built Notice A/DV Anchor Darling Valve AFW Auxiliary Feedwater System AMSAC ATWAS Mitigating System Actuating Circuitry ASTEC Automatic Surveillance Technical System BFlY Bypass feed Isolation Valve BFRV Bypass Feed Regulation Valve BOP Balance of-Plant CCP Centrifugal Charging Pump CCW Component Cooling Water System CFR Code of Federal-Regulations CRI Control Room Isolation CVCS Chemical & Volume Control System CVI Containment Ventilation Isolation DC De ficiency- Cards DF05 Diesel fuel Oil Storage DPIS Digital Position Indication System , DRPIS Digital Rod Position Indication System ECCS Energency Core Cooling System ERF Emergency Response Facility ESF Engineered Safety feature FI Flow Indicator FWI Feedwater Isolation GE General Electric GPM Gallons Per Minute HS Hand Switch , HV High Voltage
!&C Instrument and Control IFI Inspector Followup Item ISEG Independent Safety Engineering Group LCO Limiting Condition for Operation LER Licensee Event kepolts LLRT Local Leak Rata Test LOSP Loss of Offsite Power MOAFW Motor Driver. Auxiliary feedwater System Pump MDD Minor Departure from Design MFly Main Feedwater-! solation Valve MFP Main Feed Pump MFW Main Feedwater MOV Motor Operator Valve MWO Maintenance Work Order NCY Non-cited Violation NPF- Nuclear Power Facility NR Narrow Range-NRC Nuclear Regulatory Commission NSCW Nuclear Service Cooling Water NUE Notice of unusual Event 0505 On-Shift Operation Supervisor
e 35 PERMS Plant Effluent Radiation Monitoring System PORY Power Operated Relief Valve PT Pressure Transmitter PV Pressure Valve RCOT Reactor Coolant Drain Tank RCS Reactor Coolant System RHR Residual Heat Removal System 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 SGWLC Steam Generator Water Level Centrol SI Safety. Injection System SS. Shift Supervisor
- SSMP Safety System Monitor Panel TDAFW Turbine Driven Auxiliary Feedwater Pump TS -Technical Specification TSC Technical Support Center 7
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er.c.ove. No. Q Vogtle Doctric Generating Mont A 00304-C 4kr NUCHN4 OPERATIONS g,,,,n ya, "M " [ g Unit Georgia Power ep,w; , VOlu EQUIPHENT CLEARANCE AND TAGGING 1.0 PURPGsE
'Ahis procedure provides instructions for requesting, issuing, and releasing CLEARANCES on plant equipment or systems to ensura safety of during maintenance, testing, personnel or inspection. and equipment Instructions are included in the following:
4.0 Instructions 4.1 Clearance Philosophy 4.2 Requesting A Clearance 4.3 Preparing The C'.earance Sheet 4.4 Clearing And Tagging 4.5 Issuing Subclearances 4.6 Adding Clearance Points 4.7 Performing Functional Tests 4.8 Performing Partial Releases 4.9 Releasing Clearances 4.10 Caution Tage 4.11 Performing Quarterly Checks 2.0 DEFINITIONS 2.1 CLEARANCE Authorization to work on plant equipment that has been rafely isolated by the use of HOLD TAGS l m.o.s m
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PMoCLDUME No. EgyssioN PAgg No. VEGP 00304-C 14 2 of 43 2.2 CLEARANCE NUMBEP. The control number assigned to a unique CLEARANCE SHEET and associated red HOLD TAG (S). The CLEARANCE NUMBER will be a 3-part number designating unit number, year issued, and the consecutive number. Example: 1-87-14 would be the fourteenth CLEARANCE SHEET issued in 1987 for unit one or common equipment. NOTE Unit Numbers are as follows: 1 = Unit u. snd Common 2 - Unit Two 2.3 CLEARANCE POINT All those valves, breakers, switches, etc. that must be positioned to positively clear all sources of electrical power, liquids or gasses from the work area. 2.4 CLEARANCE REQUEST FORM A form used by PLANT / CONSTRUCTION personnel to request CLEARANCE on a plant component or subsystem. (See Figure 2.) 2.5 CLEARANCE SHEET The )rimary means of CLEARANCE documentation. The CLEA.tANCE SHEET shall consist of a minimum of one sheet, front and back (Figures 3a & 3b). Any Subclearance Continuation Sheets (Figure 3c) also become part of the CLEARANCE SHEET as they are required. l 2.6 EXTENDED ACTIVE CLEARANCE A CLEARANCE which remains in effect for more than 3 months, l 2.7 FUNCTiDNAL TEST l A test of a component or subsystem to verify satisfactory operation of the com)onent or subsystem, after the component or subsystem has been placed in a configuration that assures plant equipment and personnel safety. 90M4%
PROCEDURE No. mgyst,16I[' - PAGENO, VEGP 00304-C 14 3 of 43 l l 2.8 HOLD TAG A HOLD tag (Figure 1) which, when attached to a piece of equipment, prohibits the operation of that equipment in all circumstances. NOTE White DANGER tags, previously used by this procedure, that are still in the plant will be replaced with red HOLD tags checks. This during quarterTy~be replacement may conducted sooner at Operators dia.cretion. Danger tags currently in use carry the same authority as the new HOLD TAG. 2.9 HOLD TAG NUMBER The nur.ber placed on each HOLD TAG derived by using the CLEARANCE NUMBER and the sequential tag number from the CLEARANCE SHEET. Examples 1-87-14-1 would be the first HOLD TAG placed on CLEARANCE 1-87-14 1-87-14-2 would be the second HOLD TAG placed on the same CLEARANCE. 2.10 INDEPENDENT VERIFICATION The establishment implemented of completed by procedure activity accuracy,ified and documented by a qual individuni acting independently from the individual responsible for activity performance. 2.11 RELEASE Subclearance holder authorization that clearance I l points are no longer necessary to provide plant i equipment or personnel protection. 2.12 PARTIAL RELEASE The act of releasing one or more CLEARANCE POI':7S without releasing the entire CLEARANCE. (See N gure 6) i F0 Het
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PMOctDURE Peo. MgyssioN PAug NO, l
. VEGP 00304-C a4 4 of 43 l 2.13 QUARTERLY CHECK A check of EXTENDED ACTIVE CLEARANCES which is merformed at three month intervals, based on the CLEARANCE installation date, to verify the following
- a. The equipment is still aositioned and tagged as indicated on the Cl,EARAiCE SHEET.
- b. The CLEARANCE is still valid and required by plant conditions.
2.14 SUBCLEARANCE The method by which plant personnel may sign on to a CLEARANCE and perform work under the protection of th-CLEARANCE. 2.15 SUBCLEARANCE HOLDER An individual listed on the Qualified Subclearance Holder List (Figure 7), normally a Plant Sumervisor or Foreman (PS/F), who has been issued a SUBCLEARANCE. 2.16 TAGGING DESK
- A location in or near the Control Room, under the direction of the Shift Supervisor, where active CLEARANCE books, UNIT CLEARANCE LOGS, and other related forms are kept.
2.17 TAGGING DESK OPERATOR A qualified Operations Department employee who coordinates activities as described in this procedure. 2.18 UNIT CLEARANCE LOG An index of CLEARANCES (Fiaure 4) which contains the following information: CLEARANCE NUMBER, Equipment Description, MWO No. Installed and Released Dates, and l any QUARTERLY CHECKS. 2.19 CAUTION TAG A yellow tag attached to a piece of equipment that provide cautions related to its use or operation. This tag is not to be used to provide personnel protection, mm
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emoctount No. mmvow ' PAOL No.
'VEGP 00304-C 14 5 of 43
.c _ 3.0 RESPONSIBILITIES 3.1 RESPONSIBLE POSITIONS FOR RELEASE OF CLEARANCES 3.1.1 General Manager, Plant Manager, and the Plant Support Manager. The General Hansger, Plant Manager, or the Plant Support Manager, is responsible for releasing SUBCLEARANCES if the SUBCLEARANCE HOLDERS cannot be contacted and providing notification to that individuni when he/she returns to work. 3.1.2 Unit 11 Field Construction Manager / Project Construction Hanager During the Initial Test Program the Unit 11 Field Construction Manager or the Project Construction Manager is responsible for releasing subclearances of construction personnel, if the SUBCLEARANCE HOLDER can not be contacted and providing notification to that individual when he/she returns to work. 3.1.3 The On-Shift Operations Supervisor (OSOS) or the Dweartment Supervisor may release a SUBCLEKRANCE if the SUBCLEARANCE HOLDER is off-site, and gives permission by phone. 3.1
- The OSOS and Department Supervisor may relemae a SUBCLEARANCE if the SUBCLEARANCE HOLDER is off-site, and cannot be contacted. They are also resmonsible for providing notification to that individual w'1en he/she returns to work.
3.2 DEPARTMENT MANAGERS / SUPERINTENDENTS The department heads are responsible fori 3.2.1 Assigning their personnel to attend CLEARANCE training provided by the Training Department. 3.2.2 Notifying the Manager Operations in writing, of their Plant Supervisors / Foremen (PS/F) who have successfully completed CLEARANCE trainin; and have been qualified to be SUBCLEARANCE HOLDERS. Tais is done by completing Figura 7.
- P4
Mp" 00304.C 14 6 of 43 3.3 MANAGER OPERATIONS The Hanager Operations is responsible for 3.3.1 Implementation of this procedure. 3.3.2 Ensuring QUARTERLY CHECKS are completed. 3.3.3 Ensuring that the personnel who implement this procndure are qualified by demonstrated ability and pror.edurcl knowledge. 3.4 TRAINING DEPARTHENT The Training Departmest is responsible fort 3.4.1 Providing CLEARANCE training when required by department superintendents. 3.4.2 Providing department superintendents with a list of their personnel who successfully complete CLEARANCE training. 3.5 SHIFT SUPERVISOR The Shift Supervisor is tesponsible for 3.5.1 Obtaining permission from the System operator before issuing any CLEARANCE which might affect the load carrying capability of the unit. NOTE If continued operation of equipment important to the load carrying capsbility of the unit may endanger personnel, that equipment may be removed from service without the permission of the Syste's Operator. The System Operator will be notified as soon as possible. 3.5.2 Signing for the Systen Oprirator to initiate or release a subcle.srence whan so requested by the System l Operator. 3.5.3 Maintaining a current list of those employees qualified to implement this procedure and a list of those qualified to be SUBCLEARANCE HOLDERS. on
PROCEDURE NO. REYl&loN PAGE NO.
. VEGP 00304-C 14 7 of 4.'
3.5.4 Issuing and releasing CLEARANCES. 3.5.5 Ensuring the UNIT CLEARANCE LOG and the UNIT CAUTION LOG for each unit are maintained. 3.5.6 Preparing and/or authorizing the CLEARANCE SHEET after reviewing the impact of the CLEARANCE on plant operations. 3.5.7 Preparing and/or authorizing FUNCTIONAL TESTS and PARTIAL RELEASES. 3.5.8 Verifying that all applicable Technical Specifications action statements are followed when issuing a CLEARANCE. 3.5.9 Calling the Fire Protection Engineer when issuing or releasing a CLEARANCE on any Fire Protection equipment. 3.6 OPERATIONS DEPARTHENT TRPLOYEES Operations Department employees are responsible for 3.6.1 Reviewing and approving CLEtJANCV REQUEST FORMS. 3.6.2 Reviewing / preparing CLEA7.ANCF. S!IEETS, HOLD TAGS, FUNCTIONAL TEST and PARTIAL RELEASE forms. 3,6.3 Maintaining the UNIT CLEARANCE LOG and the UNIT CAUTION LOG 3.6.4 Performing equipment alignment and hanging and removing HOLD TAGS as necessary to implement this procedure. 3.6.5 Performing INDEPENDENT VERIFICATION as required. 3.6.6 Performing QUARTERLY CHECKS of EXTENDED ACTIVE CLEARANCES. _ w .
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Paocsouns wo. navision PAos n VEcr 00304-C 14 8 of 43 3.7 PLANT SUPERVISOR OR FOREMAN i NOTE During the Initial Test. Program the term PS/F may i ibslude construction area r.rordinators and engineers / s'est Oors who have we m stully completed i
//11#M MCE training and are i nri 44) authorization list. j A PS/F !,s dattimsf.ble fors 3.7.1 Obtaini~nn n !!!!hCIZARANCE, when required, before allowing the performance of work which the PS/F is responsdb)<a fm.' completing.
3.7.2 Verifying thm the CLEARANCE is adequate for the work ~ to be-ptir:formtid before work begins. 3.7.3 Informing reach crew member of the limits of that CLEARANCE when-directing a crew to perform work under that CLEARANCE. 3.7.4 Releasing'the SUBCLEARANCE when the PS/F's crew has completed their portion of the work requiring the SUBCLEADANCE. 3.7.5 . Releasing the SUBCLEARANCE if the PS/F is to be away for an extended period of time. These SUBCLEARANCES ' shall be reinautd to the PS/F's qualified replacement if the work in incomplete. 3.8 PLANT PT,RSONNEL It is the responsibility of all plant personnel to adhere to the requirements of this procedure. 3.9 INDEPENDENT VERIFIER , 'l, The Operations Department Individual who is responsible for verifying the position of a safety-related - component as described on the CLEARANCE SHEET in accordance with the provisions of Procedure 00308-C,
" Independent Verification Policy".
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PMOCLDUME No. Egyt$ son PAotNo. VEGP 09304-C 14 9 of 43 l 4.0 INSTRUCTIONS i 4.1 CLEARANCE PHILOSOPHY 4.1.1 When clearing power supplies to solenoids remove fuses, where practical, instead of links. Fuses shall be bagged and HOLD tagged as part of the CLEARANCE. No more than two fuses per bag. 4.1.2 The scope of each CLEARANCE should be just enough to adequately clear the equioment. This is to reduce interference with other CLEARANCES, and use of PARTIAL RELEASES. 4.1.3 When HOLD tagging a Hotor Operated Valve (HOV) as a fluid boundary, the handswitch shall be HOLD tagged in the position in which the valve handwheel will be HOLD tagged. The breaker shall be opened or off, as applicable, and the handwheel shall be HOLD tagged. 4.1.4 When using Air Operated Valves (A0V) as boundary valves perform the following: 4.1.4.1 For a FAIL CLOSE A0V
- a. HOLD tag the handswitch in the closed position
- b. HOLD tag the air supply valve closed and check that the air line to clui valve is depressurized. ..
- c. If the valve has a handwheel, HOLD tag it in the closed position.
4.1.4.2 For a FAIL OPEN A0V with handwheel
- a. HOLD tag the handswitch in the closed position
- b. HOLD tag the handwheel in the closed position
" ' 'l( i u.1.4.3 For a FAIL OPEN A0V without handwheel
- a. HOLD tag the handswitch in the closed position
- b. Hechanically or hydraulically (as approariate) gag the valve in the closed position and HOLD tag the gagging device.
4.1.5 When restoring Air Operated Valves used as boundary l valves perform .he following l l
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PMoCEDOM No. MsV*oN PAot No. ^ . VEGP 00304-C 14 10 of 43 4.1.5.1 For a FAIL CLOSE A0V
- a. If the valve has a handwheel, remove the handwheel HOLD tag and restore to the operate or open i
position. i
- b. Remove the HOLD tag from and open air supply l valve
- c. Remove HOLD tag from handswitch and oper :a as required.
4.1.5.2 For a FAIL OPEN ADV with handwheel 4
- a. Remove HOLD tag from handwheel and place handwheel in the open position.
- b. Remove HOLD tag from handswitch and operate as required.
4.1.5.3 For a FAIL OPEN A0V without handwheel
- a. Remove HOLD tag from gagging device and remove gag.
- b. Remove HOLD tag from the handswitch and operate as required.
4.1.6 The handswitch position on HOLD TAGS shall be in the same position as the controlled comp nent, e.g. A handswitch tagged closed means the valve is closed. If a difference exista due to unforeseen circumstances an information tag sha!.1 be attached to the handswitch and the CLEARANCE stating canditions. An example may bei The motor of a HOV is burned out and manual operation is necessary. 4.1.7 HOLD TAGS should be placed in a manner that i. hey will be easily visible to anyone preparing to operat's the equipment.
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Ectouns wo. nevuuon PAot wo. 1.4 11 Of 43 < . VEGP 00304-C 4.1.8 A FUNCTIONAL TEST is intended to allow testiag of equipment after it has been repaired. The TUNCTIONAL TEST should not extend for more than 4 days. If the test will last partially ormore fully than released. 4 da ys the CLEARANCE shall be 4.1.9 When HOLD tagging valves with remote operators (reach
] rods) place the valve in the position required on the clearance sheet and only HOLD tag the external handwheel or operator. Verify the clutch is engahed when operating the valve, if applicable.
4.1.10 When isolating a fluid filled system, or mortion of a system, that will be opened to the atmosphere for maintenance, the clearance should include a vant and a drain that will drain that portion of the system to be worked. 4.1.11 If a clearance has core than one subclearance holder
- the CLEARANCE shall not be modified for one subclearance holder without the concurrence of all subclearance holders. Example: HCC breaker tagged off and Locked (door closed), you may not remove the lock, open the door and RELOCK the breaker (door open)
I 4 .1.12 without the approval of all subclearance holders Should a clearance be voided after it has been easigned a number the word " VOID" shall be written on each page and the individual voiding the clearance shall initial and date each page. It should than be canceled from I ~ the log, sent to the Shift Clerk and handled the same as a released clearance. WARNING NO HOLD TAG SHALL BE ATTACHED OR REMOVED WITHOUT AUTHORIZATION FROM THE SHIFT SUPERVISOR. 4.2 REQUESTING A CLEARANCE NOTE The TAGGING DESK will be manned by the TAGGING DESK OPERATOR during periods of increased work activity to assist the Shift Supervisor in implementing this procedure. 4 701486 4 _ _ - _ _ . __-_-_-
N N .4LE NJ. NE No. MtVl&loN 14 12 cf 43 VEGP 00304-C 4.2.1 A CLEARANCE is requested by completing a CLEARANCE REQUEST FORM (Refer to Figura 2) and submitting it to the TAGGING DESK OPERATOR, Shift Supervisor, or Operations Work Planner preferably at least 24 hours prior to the time needed. 4.2.2 The requesting individual shall provide the following informations
- a. A Description of Equipment / System to be Cleared.
(Example: Motor-Driven Fire Pump)
- b. The tag number for that equipment, (Example:
C-2301-P4-002)
- c. The Reason for the CLEARANCE,
- d. The Estimated Outage Time
- e. All Associated Work Order Humbers,
- f. Requested and Needed Dates and Times, i
- g. Name of Requesting PS/F and Extension,
- h. Recomended CLEARANCE POINTS and their positions,
- i. Reference Drawings 4.3 PREPARING THE CLEARANCE SHEE' NOTE Computer generated alearance i.heets may be used.
I 4.3.1 The Shift Supervisor, Operations Work Planner, or TAGGING DESK OPERATOR will review the CLEARANCE REQUEST FORM and the plant status to determine whether the CLEARANCE can be issued. If he determines that the CLEARANCE can be issued, he will ensure that the CLEARANCE POINTS are adequate for personnel and/or I ogmentprotectionbeforep S (Refer to Figures 3a & The Shift Supervisor, Operations Work Planner, or paring the CLEARANCE
.)
4.3.2 TAGGING DESK OPERATOR will prophre the CLEARANCE SHEET:
- a. lete the following spaces on the UNIT CE LOG (Typical of Figure 4): CLEARANCE NUMBER, Description of Cleared Equipment, and HWO Number (if applicabic),
- b. Complete the information above the double-line on the front of the CLEARANCE SHEET. (Figure 3a)
[ -_ _
.' . # ""' 13 of 63 EnYlh 00304-C 14 WARNING RELAYS, CHECK VALVES, SOLENOID VALVES AND AIR OPERATED VALVES ENERGIZED IN THE DESIRED POSITION SHALL NOT BE USED AS CLEARANCE POINTS. EXCEPT AS NOTED IN THE FOLLOWING. A HOLD TAG SHALL NOT BE PLACED 04 ANY COMPONENT WHICH IS ENERGIZED WITHOUT THE COMPONENT BEING MECHANICALLY BLOCKED IN THE DESIRED POSITION.
- c. Complete the information on the back of the CLEARANCE SHEET (Figure 3b). This should include Equi CLEARANCENUMBER,HOLDTAGNUMBER[
Name and Number, and Required Pos tion,pment
- d. Complete the " Prepared by" and " Locked Valves" "s paces on the front of the CLEARANCE SHEET. The Locked Valves" space should be checked "yes" if the CLEARANCE requires the manipulation of locked valves.
- e. Submit the CLEARANCE SHEET to the Shift Supervisor for review and authorization.
4.3.3 If the Shift Supervisor agrees that the CLEARANCE can be issued, he will do the followings
- a. Perform or assign an individual to review the CLEARANCE for adequate protection of personnel and/or equipment. Reviewer shall sign the reviewed by blank on the CLEARANCE SHEET.
- b. Review CLEARANCE for safety-related items, ensure that all Technical Specification action statements can be met, and check the appropriate " Involves Tech. Spec. Safety-Related Item ' space on the front of the CLEARANCE SHEET.
NOTE Step 4.3.3c is required only after receipt of the Unit Operating License.
- c. Provida explicit notification to the Reactor Operator that a safety-related system is being ,
removed from service. Such notification shall be ; recorded in the Unit Control Log. m.w
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msvisioN 1g MGE NO, 14 og 43
- d. When CLEARANCE operations result in a related component or system being safety inopera ble, the Shift Supervisor shall ensure that all required surveillances on the redundant train are performed as required.
- e. If a Clearance involves Fire Protection Equipmenti (1) Notify the Fire Protection Engineer (FPE), or designee, during normal work hours.
(2) If the FPE, or designes, cannot be reached during non-normal work hours (weekends, holidays or nights), contact the Duty Engineer. h0TE The FPE, designee, or Duty Engineer, as appropriate shall notify the Corporate Insurance Representative if the impairment will last inore that .ight hours or includes a shift change.
- f. Review the request to see if the load carrying capability of the plant. may be affected.
- g. Record the date and time and sign the " Authorized by" space on the front of the CLEARANCE SHEET.
NOTE CLEARANCES may aleo originate in the form of written switching orders issued by the System 0)erator or Division Operator. Taese switching orders will constitute the plant's permanent record of these CLEARANCES. These will be executed in accordance with the latest edition of the " Electric System Operation" procedure, published by the Georgia Power Comgany ( The Operating) Red Book Department.
.' PROCEDUML No, j PAQtNo.
VEGP 00304-0
.4 N 14 15 of 43 4,4 CLEARING AND TA*2GING 4.4.1 A qualified operator when clearing and tagging, will do the following
- a. Write the following on the HOLD TAG (S): (Figure 1)
(1) HOLD TAG NUMBER (Example: 1-87-14-1) (2) Specified Position. (3) Equipment Identification Number (Examples: HS-7907B, 1AA02-10. C2301-U4-660) l I NOTE Computer generated labels with the same information may also
- be used.
- b. Have the authorized CLEARANCE SHEET in his possession when performing clearing and taggit; operations.
- c. The Shift Supervisor should be notified immediately of multiple HOLD TAGS and abould make the decision as to the position that affe-de the highest degree of personnel protection,
- d. Operate equipment and attach HOLD TAGS as described below in sequence, from the top of the i page to the bottom of t..a page, and initialing the appropriate space as each step is completed.
(1) For switchgear breakers, HOLD TAGS shall be placed on the cubicle door. (The HOLD TAG does not prevent removal of the breaker for i maintenance purposes.) (2) 480VAC HCC breakers shall be operated as follows: (a) Operations personnel shall operace the i breaker per 13435-C, " Circuit Breaker Racking Procedure" and place a HOLD TAG on the breaker switch icek ring. If the CLEARANCE is for physical wor):. on that breaker, then the HOLD TAG shall be 11 aced on the cubicle door and the lock placed on the lock ring after the door is opened. tuseg
[ \N$' 00304-C 14 16 of 43 NOTE Construction craftmen will work under the Operations lock installed in stap (a), if applicable, The following steps (b). (c), (d), , (e) and (f) apply to Georgia Power Company, IBEW personnel only. (b) Any Georgia Power Company, IBEW Electrician performing maintenance on equipment supplied by the breaker will obtain the padlock key along uith a numbered lock and key from the Control Room, remove the H0 2 TAG, unlock the breaker, and verify de-energization of the load side using a suitable = multimeter without operating the i breaker. J (c) Following verification of load side de-energization, the Electrician shall close the cubicle door and relock the breaker switch with the numbered lock, and rehang the HOLD TAG. l (d) The operations padlock and key will be returned immediately to the control room. The numbered key will be held by the Electrician's Foreman until work is complete at which time it shall be returned to the control room.
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(e) Any Cecrgia Power Company, IBEW Mechanic performing maintenance on equipment supplied by the breaker will request that an Electrician verify de-energitation of the load side. In this event, steps (b) and (c) above shall be followed. (f) The operations padlock and key will be returned immediately to the control room. The numbered key will be held by the Mechanic's Foreman until work is complete at which time it shall be returned to the Control Room. The Operations Department will remove the HOLD tag and numbered lock and re-energize the breaker only after all SUBCLEARANCES have been released, ropes
PMoCEoVM NJ. MYt31oM PAGE No. VEGP 0024-C ll: , 17 of 43 (3) For 480V At power panels AC and DC distribution pane 10 the HOLD TAG shall be placed conspieuausly adjacent to the breaker. NOTE Independent Verificat%n is required only after receipt of che Unit Operating License. 4.4.2 The operator shall initial each CLEARANCE POINT as indicated and sign and date the space provided on the CLEARANCE SHEET. The Shift Superviso: shall ensure INDEPENDENT VERIFICATION is performed when required. 4.4.3 Upon completion of the clearing and tagging, the Shift Supervisor or TAGGING DESK OPERATOR shall review the CLEARANCE SHEET for completaness, place it in the activo CLEARANCE books and initial and date the UNIT l CLEARANCE LOG in the spacc provided. 4.4.4 The Shift Supervisor or TAGGING DESK OPERATOR should then notify the applicable PS/F that the CLEARANCE is ready for SUBCLEARANCE issue. 4.5 ISSUING SUBCLEARANCES 4.5.1 The responsible PS/F shall verify that the CLEARANCE is adequate for the work his crew will perform. 4.5.2 If the CLEARANCE is inadequate, additional CLEARANCE POINTS may be added by request of the PS/F. The additional CLEARANCE POINTS shall receive the same review as the original CLEARANCE. 4.5.3. The Shift Supervisor or tagging desk o,erator may issue a SUBCLEARANCE to a qualified PS/F by saving the PS/F record the MWO, CAT Ntunber or other work document, the date, time, and sign the " Issued To" Section on the front of the CLEARANCE SHEET. NOTES
- a. If the SUBCLEARANCE does not have a work document, the purpose for a SUBCLEARANCE shall be written in this space.
- b. Subclearances may be requested by the System Operator (S0) by telephone. The Shift Supervisor will sign for the SO (" Shift Supervisor for System Operator")
on the clearance sheet,
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PMoCEDURE NJ. WEY6s6oN PCE NG VEGP 00304-C 14 ; 18 of 43 4.5.4 If there are more SUBCLEARANCE HOLDERS than spaces provided, the Shift Supervisor or TAGGING DESK OPERATOR will attach a SUBCLEARANCE Continuation Sheet (Figure < 3c) issnediately behind the CLEARANCE SHEET, and check the "/es" box on the CLEARANCE SEY.ET. 4.5.5 If maintenance is to be performed (i.e., the CLEARANCE is for personnel protection), the PS/F shall, for 480V AC power panels, lift leads from the breaker in accordance with Procedure 00306-C, " Temporary Jumm r And Lif ted Wire (Sntrol" or Procedure 20429-C "S 2 ort Term Documentat.a cr. Of Temporary Jumpers And Lif ted Wires" depending upon the length of time that the maintenance will take. 4.5.6 If no maintenance is to be performed (i.e., the CLEARANCE is for equipment protection), the PS/F may , lift the leads for 480 VAC power panels as described in Step 4.5.3 if desired. 4.5.7 The PS/F will inform each member of his crew of the limits of the CLEARANCE before work begins. When a PS/F wishes to release his SUBCLEARANCE, he will 4.5.8 verify that all arounding devices which he or his crew may have instal. led . ire removed. He will then report to the Shift Supervisor or TAGGING DESK OPERATOR, sign and record date and time in the appropriate space-en the CLEARANCE SHEET. The sign-off by the System Operator will be-done by the Shift Supervisor, when requested by telephone. 4.6 ADDING CLEARANCE POINTS TO AN EKISTING CLEARANCE 4.6.1 To add points to an existing clearance complete the top part of Figure 12 " Additional Clearance Point Form" and submit to the SS or Tagging Desk Operator. 4.6.2 The SS or Tagging Desk Operator will review the request to detarmine if the additional points can be added to the clearance. After ensuring the clearance points are ade by"quate space.the Shift Supervisor will sign the " Approved 4.6.3 A1! eubclearsacs holders on the existing clearance must be notified of the additional points and approve of the addition. The subclearance holders will complete the spaces 1.s the subclearance block on the Figure 12 to show tFair approval. Approval may be obtain by telephone if so noted. mm
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MtootDURE No, REvetoN
. VEGP 00304-C 14 PAOF'.U. ~ ~192 43
'l 4.6.4: The'a'dditional , N rance points will be added to the= ;
existing clearance to:= AFTER the SS and subclearance' '~~ . holders have approved the adsition. ) 4.6.5 After approval the additional clearance points may'be installed, documented on the clearance sheet, and signed for on Figure 12. 4.7 PERFORMING FUNCTIONAL TESTS WARNING SUBCLEARANCE RE12ASE FOR TEST BY ALL SUBCLEARANCE , HOLDERS NUST-BE OBTAINED ,
. BEFORE ANY FUNCTIONAL
- TESTS CAN BE AUTHORIZED.
NOTE If-there are no SUBCLEARANCE HOLDERS The CLEARANCE should be released per lSection 4.8. This Section is inappropriate for use. 4 . 7 .1 -.- The Shift Supervisor or TAGGING DESK OPERATCR will nomally complete a FUNCTIONAL TEST fom -(Figure 5) upon request from a PS/F. 4.7.2 he individual (PS/F or-the SS) re uesting a release-will have the-responsibility.for obtaininfrom all of the theSUBCLEARANCE test,- HOLDE Each:SUBCLEARANCE HOLDER will he responsible for-notifying his._ crew of the_ test.- 4.7.3 After all SURCLEARANCE HOLDERS-have released-their-SUBCLEARANCE for FUNCTIONAL TEST, the. Shift Supervisor.- Lor TAGGING DESK OPERATOR will attach the FUNCTIONAL TEST form to the CLEARANCE SHEET and submit to the Shift Supervisor. , 4.7.4 The1 Shift Supervisor shall ensure that all-SUBCLEARANCE HOLDERS have. released their SURCLEARANCE-before
.authoriGng the FUNCTIONAL TEST.
- 4.7. 5 : After: approval the Shift Supervisor will provide a qualified operator to perform the test and operate the equipment as requested by the requesting PS/F.. .
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Mr. No.
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' ntvisioH PAQs NO.
VEGP 00304-C 14 20 of 4:- NOTE Prior to fuel load, the Shift Supervisor may cuthorize a maintenance department 1erson (i.e., electrician, mec anic, or IEC technician) to remove / install tags during the l functional test. If this occurs, the maintenance department person shall assume all cpplicable operator responsibilities described in Section 4.7. 4.7.6 The operator performing the FUNCTIONAL TEST shall
- a. Have the CLEARANCE SHEET with the t. sched authorized FUNCTIONAL TEST form in M a possession before removing any HOLD TAGS.
b'. Remove HOLD TAGS, position the equi nnent, and initial each step as indicated on taa FUNCTIO'iAL TEST form in the proper sequence (the top line is the first step and the botten line is the last).
- c. Sign and record date and time on the FUNCTIONAL TEST form when all CLEARANCE POINTS are released.
- d. Attach Functional Test Tag (Figure 3) to any handswitch from which a hold tag was removed, or which is associated with equipment under functional test even if not previously tagged.
- a. i i Operatetheehpmentonlyasdirectedbythe requesting-PS
- f. Return the CLEARANCE SHEET with the attached FUNCTIONAL TEST form and HOLD TAGS to the Control Room if the test will require more than 2 hours to complete. The Shift Supervisor or TAGGING DESK OPERATOR will then place these in the FUNCTIONAL TEST log book.
4.7.7 After the FUNCTIONAL TEST has been completed, the CLEARANCE points will be restored to t;ae original status as indicated on the CLEARANCE SHEET. The restoration sequence should be as directed by the requesting PS/F unless the CLEARANCE is to be released. 4.7.8 The operator will gosition the equipment as indicated, reattach the HOLD .AGS, remove any FUNCTIONAL TEST TAGS, and initial each restoration step, m$- K-____________--__--__---_-__________--____-____--__-______-_--_-_==-
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PRoCEDUCE HC REYlSloN PAGENO. VEGP 00304-C 14 21 of 43 4.7.9 When the CLEARANCE is restored, the operator will sign and record date and time in the space provided on the FUNCTIONAL TEST form. The Shift Supervisor shall ensure INDEPENDENT VERIFICATION is performed when required. 4.7.10 The operator will then return the CLEARANCE SHEET with the attached FUNCTIONAL TEST form to the Shift Supervisor or TAGGING DESK GPERATOR. 4.7.11 The CLEARANCE SHEET with the attached FUNCTIONAL TEST form shall then be returned to the active CLEARANCE l _ books. 4.7.12 If the CLEARANCE is to be ecleased after the FUNCTIONAL TEST is complete the operator shall return the FUNCTIONAL TEST TAGS, CLEARANCE SHEET with the attached l FUNCTIONAL TEST form and HOLD TAGS to the Shift Su ervisor for release of the CLEARANCE (See Subsection E 4. ). 4.8 PERFORHING PARTIAL RELEASES 4.8.1 The Shift Supervisor or TAGGING DESK OPERATOR will
.ormally complete a PARTIAL RELEASE form (Figure 6) upon request from a PS/F.
4.8.2 The requesting PS/F (or SS if applicable) will have the responsibility of obtaining releases from all SUBCLEARANCE HOLDERS before a PARTIAL RELEASE can be authorized. NOTE Two or more separate CLEARANCE points may be released on a single PARTIAL RELEASE form. 4.8.3 After all SUBCLEARANCE HOLDERS have released the CLEARAliCE POINTS for PARTIAL RELEASE, the Shift Sumervisor or TAGGING DESK OPERATOR will attach the PARTIAL RELEASE form to the CLEARANCE SHEET and indicate on the back of the CLEARANCE SHEET the removal sequence and position of the equipment to be released. 4.8.4 The Shift Supervisor will then evaluate the PARTIAL RELEASE to determine if it connromises personnel or equipment safety. If so, the 7ARTIAL R3 LEASE shall not be authorized. 4.8.5 The Shift Supervisor shall ensure that all SUBCLEAPJWCE HOLDERS have released the CLEARANCE POINTS for PARTIAL RELEASE before authorizing the PARTIAL RELEASE. ; reun
PRoCEDU E N3. ?'EV1514N PAJE No. VEGP 00304-C 14 22 of 43 4.8.6 The Shift Supervisor will sign and record date and time on the PARTIAL RELEASE form and return the CLEARANCE SHEET with the attached PARTIAL RELEASE form to the TAGGING DESK OPERATOR. 4.8.7 The Shift Supervisor will then provide a qualified operator to perform the PARTIAL RELEASE. 4.8.8 The operator perfoming the PARTIAL RELEASE shall
- a. Have the CLEARANCE SHEET with the a* ched authorized PARTIAL RELEASE form in ... possession before removing any HOLD TAGS.
- b. Remove HOLD TAGS, position the equi) ment, and initial each step as indicated on t1e CLEARANCE SHEET in the proper sequence (Perform the step labeled "1" first),
- c. Sign and record date and time on the PARTIAL RELEASE fom,
- d. Return the CLEARANCE SHEET with the attached PARTIAL RELEASE form and HOLD TAC (S) to the Shift Supervisor or TAGGING DESK OPERATOR. If the HOLD TAGS are contaminated with radioactive material, they shall be disposed of as radioactive trash and the Shift Sumervisor or TAGGING DESK OPERATOR informed of taeir disposal.
4.8.9 The Shift Supervisor shall ensure INDEPENDENT VERIFICATION is performed as required. Upon com?letion, the operator shall initial each step on the back of the CLEARANCE SHEET and sign and record date and time in the space provided on the PARTIAL RELEASE form. 4.8.10 The Shift Supervisor or TAGGING DEEK OPERATOR will ensure that the PARTIAL RELEASE is complete, destroy the returned HOLD TAGS, and place the CLEARANCE SHEET with the attached PARTIAL RELEASE form in the active CLEARANCE books. 4.9 RELEASING CLEAPANCES WARNING ALL SUBCLEARANCES MUST BE RELEASED BEFORE A CLEARANCE CAN BE RELEASED. mus - - - . . - . - - - - .....,.,,.Q _
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navision paoa No. pmoesount No. - 00304.it 14- 23 of 43 _aVEGP 4.9;1 Upon:a request from a PS/F, the Shift Supervisor or l TAGGING DECK OPERATOR should: ;
-a._ Ensure-that-all SUBCLEARANCES are released. l
- b. Evaluate plant status to determine if the CLEARANCE can be released. ,
If the clearance includes Fire Protection c.- !
-Equipment, NOTIFY the Fire Protection Engineer, or designee, and request concurrence with the ,
release. If the FPE,'or designee, is not ' available contact the Duty Engineer.
- d. -Specify the removal _ sequence and-. desired position l
-of-each CLEARANCE point on the back of the CLEARANCE SHEET. The SS or Tagging Desk Operator will utilize-the normal system alignment,-in ~ -accordance with the normal system line-up procedure (11XXX-X), as modified-by existing CAUTION TAGS, Infornation. Tags. etc. 'Jhon s pecifying removal position and sequence. If the remov.21 procese does not result ia restorction to normal system alignment-the SS wi'11 ensure the off-normal condition is. properly documented via Caution tags, Information-tags,--etc. (The removal .
sequence.shall be spectfind by ',p"lacing a "1" adjacent to the first step, a 2 adjacent to the . -s econd step, etc.) .
- e. Submit the-CLEARANCE SHEET to the-Shift Super'risor.
4'.9.2 The Shift Supervisor shall ensure that all o SUBCLEARANCES haveibeen-released and that the CLEARANCE can be:releasea before-signing the.-authorization-to release. 4.9.2.1 If the Nuclear Operation or: Construction SURCLEARANCE l
- HOLDER (SCH):is not onsite, but~can be contacted by
. phone:and gives:his permission. The 0805 or the
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Kresponsible department supervisor may rele~nse the SUBrrwAniuCE.- The sign-off on the'SUBCLEARANCE should be, " 'for permisaton by-phone", If the Nuclear Operation:SUBCLEARANCE HOLDER is not-on 'f 4.t.2.2. site and cannot be-contacted the OSOS and responsible. ,- ' department' supervisor shall complete ani~both sign L Figure'9 and-release the SUBCLEARANCE if stated conditions are met. The sign off on the~SUBCLEARANCE should be " for by Figure 9". u
E bdOURE No, PAGE No, 00304-C-MiO/I5 ion 14 24 of 43 VEGP 4.9.2.3 If Figure 9 conditions are not met the General Manager, Plant Manager or Plant Support Manager shall be contacted for permission and Figure 9 so noted. The sign off on the SUBCLEARANCE" " should be by permission of , if permission is granted by phone. If the Manager signs the release in person his name is sufficient. 4.9.2.4 If the Construction SUBCLEARANCE HOLDER cannot be contacted, the Construction Duty Officer shall be contacted. He should call the respective discipline manager and together complete Figure 9. If all question are answered yes both should sign approval to release the CLEARANCE. This approval may be by telecon provided adequate answers can be obtained by phone and the duty officer and discipline manager sign figure 9 the next working day. 4.9.2.5 If Figure 9 for construction cannot be completed in the affirmation, the Unit II Field Construction Hanager or the Project Construction Manager shall be contacted for germission. The by permission of sign off on the SUBCLEARANCE chould be
" if granted by phone. If the Manager signs the release in person his name is sufficient.
4.9.2.6 If the SUBCLEARANCE HOLDER cannot by contacted, the person, requesting the CLEARANCE be teleased, will verify that all grounding devices, which the SUBCLEARANCE HOLLER or work crew may have installed, are removed. . 4.9.3 The Shift Supervisor will provide a qualified operator to perform the CLEARANCE release. 4.9.4 The SS will determine mechanical and electrical equipment alignment requirements for that equipment contained within a clearance boundary. At the discretion of the Shift Supervisor, performt.nce of a system line-up procedure for the affected portions of the system prior to returning the system to service, may be required. I I am
ibnoctouni; VEn otVtEloN 00304-C 14 PAGE No. 33 of 43 4.9.5 The operator performing the CLEARANCE release shall I a. Have the authorized CLEARANCE SHEET in his possession before removing any HOLD TAGS. b. Remove appropriate, theposition HOLD TAG or FUNCTIONAL TEST TAG as the equipment each step in the speci.fied sequence., (perform and initialthe step labelled "1" first) c. Sign and record date and time on the CLEARANCE SHEET when the release has been completed, d. Return the CLEARANCE SHEET, HOLD TAGS and FUNCTIONAL TEST TAGS to the Shift Supervisor or TAGGING DESK OPERATOR. If the HOLD TAGS are be disposed of as radioactive trash and the Shiftco Supervisor or TAGGING DESK OPERATOR informed of their disposal. 4.9.6 The Shift Supervisor shall ensure INDEPENDENT VERIFICATION is performed when required. completion the operator shal'. initial eachUpon CLEARANCE POINT as indicated and sign and date the space provided on the CLEARANCE SHEET. 4.9.7 The Shift Supervisor or TAGGING DESK OPERATOR will ensure that the released CLEARANCE is complete, destroy the HOLD and FUNCTIONAL TEST TAGS, and initial and date the UNIT CLEARANCE LOG in the space provided. NOTE Steps 4.9.8 and 4.9.9 are required only after receipt of the Unit Operating License. 4.9.8 Shift Supervisor shall ensure a verification ofIf the s operability is accomplished when the system is being returned to service following maintenance or testing. The Shift Verification Supervisor'sofLog. Operability shall be entered in the 4.9.9 If the system is Technical Specifications-related , the Shift Supervisor shall provide explicit notification to the Reactor Operator that the system is in service Log. Such notification shall be recorded in the Unit Cont o1 . rou
PMoCEDURE b I ~ PAGE No. L.EVl&loN VEGP 0. >4-C 14 26 of 43 4.9.10 The Shift Supervisor or TAGGING DESK OPERATOR will then submit the released CLEARANCE SHEET with any s attachments to the Shift Clerk for routing to Document Control. 4.10 CAUTION TAGS 4.10.1 The Yellow Caution tags (Figure 11) may be attached to a switch, component, or piece of equipment to provide cautions related to operating the switch, conponent or equipment, i.e.e seal veter is isolated because of excessive leakF.O. op6M it prior to starting pump. 4.10.2 Caution tagr , "
" -he purpose of protecting the process and v, - + nly. "antion tags are not used for the proi n erstnnel.
4.10.3 The content of as w a;< should be presented in clear and cone: 2 ; larp easy to read print. 4.10.4 Each Caution tag in .. signed - number consisting of Unit Number, Year, and the nwxt sequential number from the Caution Tag Log (Figure 10). The equipment number and/or panel number will be placed on the Caution Tag and the Log. 4.10.5 The special instructions from the caution Tag should be recorded in the remarks section of the caution Log. 4.10.6 The SS is responsible for ensuring the Caution Tag is accurate and does not adversely impact the operation of other systems, components, or equipment. 4.10.7 Caution Tags are valid only when signed by a SS or higher Operations management. The SS approval will be obtained before removal of a caution Tag. 4.10.8 Operations personnel removing the Caution tag will return the tag to the SS or Tagging Desk Operator. If the Caution tag is contaminated with radieretive material it will be disposed of as radioactive trcsh. The SS or Tagging Desk Operator will be informe,d of its disposal. 4.10.9 The SS or Tagging Desk Operator will ensure that removed Caution Tags are destroyed. l Imm __-____?_N_-_____- _ - -_J L.
~~ ' ~ ~ ~
PRoCLDUAE No. V AGE No. i .' ygop oo:<a.c
. ..ON 14 27 of 43 d
j 4.11 PERFORHING QUARTERLY CHECKS 4.11.1 h e Shift Supervisor should ensure that the QUARTERLY CHECKS are performed on EXTENDED ACTIVE CLEARANCES by the quarterly anniversary of the CLEARANCE installation date. NOTE QUARTERLY CHECKS in high radiation areas need not be conducted unless the Shift Supervisor rieems the check necessary. 4.11.2 The Shift Supervisor or TAGGING DESK OPERATOR should ensure that all EXTENDED ACTIVE CLEARANCES are still required by plant conditions. 4.11.3 The operator performing the QUARTERLY CHECK shalli
- a. Review thw Clearance Index versus the Active clearance Sheets to ensure that they agree,
- b. Have the CLEARANCE SHEET in his possession.
- c. Check that the equipment is still properly HOLD tagged, the HOLD TAG is legible, and the equipment is in the specified position.
- d. Replacc. all missing or damaged HOLD TAGS.
- e. Report abnormalities to the TAGGING DESK OPERATOR and the Shife Supervisor.
- f. Return the CLEARANCE SHEET to the Shift Supervisor or TAGGING DESK OPERATOR.
- g. Review the Caution Tag Lo3 and perform a Quarterly Check of Caution Tags. Tae requirements of 4.11.3 c, d, and e above apply.
4.11.4 Upon completion of a QUARTERLY CHECK, the Shift Supervisor or TAGGING DESK OPERATOR should initial and date the space arovided on the UNIT CLEARANCE LOG and return the CLEAMNCE SHEET to the active CLEARANCE books.
enoctount No. Pact No. VEGP 00304-C { cew;iot-; 14 28 of 43
5.0 REFERENCES
5.1 ANS-3.2/ ANSI N18.7-1976, " Administrative controls and Quality Assurance for the Operational Phase of Nucicar Power Plants" (Subsection 5.2.6, Equipment control). E 5.2 GPC, Power Generation Department Procedure - GEN-2075.000 " Power Generation clearance Procedure" 5.3 GPC, Operations Department. " Electric System Operation Procedure" ("The Red Book") 5.4 IE Bulletin 79-06A " Review of Operational Errors and System Misalignments Identified During the Three Mile Island Incident", Action 10, 5.5 0737, " Clarification ot THI Action Plan Requirements" i 5.6 OP-203, Jan/1982 "INPO Good Practice Procedures For The Protection Of Employees Working On Electrical And Mechanical Components." 5.7 PROCEDURES 5.7.1 00306-C. " Temporary Jumper And Lifted Wire Control" 5.7.2 00308-C, " Independent Verification Policy" 5.7.3 13435-C, " Circuit Breaker Racking Procedure" 5.7.4 20429-C, "Short Term Documentation of Temporary Jumper And Lifted Wire Control" END-0F PROCEDURE TEXT
m;.souAt No. stymon PA.E NO. VEGP 00304-C 14 99 0f 43 we_ e G ( START u E tattAR1 cttAnnet
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enoc wo. navision ,Aoa No. MMO EXAMPLES OF TYPICAL HOLD TAGS GEORGIA POW [ t COMPANY NUCLEAR OPERATLONS HOLD TAG 00 NOT OPERATE THIS EQUIPMENT
/ HOLD TAG OPERATING THs PIECE OF EQUIPMENT 5 PR0Hento As LonG As Tsis TAG is ATTAmED UNDER CLEARANCE NO.
P0sm0N TAG NO. EQUIPMENT NO._ GEORGIA POWERCh4PANY HOLD TAG , O DO BOT OPERATE THS EQUIPhENT Figure 1 ftDMS _______ _ :_ - = - - - . . , _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
] RROcLDURE NO- QEVISION DAEL'NT
. VEGP 00304-C 14 of 43 CLEARANCE REQUEST FORM Description of Equipment / System: Number _
Reason For Clearance: Estimated Outage Time: Work Order la l, Requested Date/ Time / Needed Date/ Time: / Requested by: Extension: Recommended Clearance Points Equipment Po,,sition o Equipment Position
- 1. 11.
- 2. 12.
i
- 3. 13.
- 4. 14.
- 5. 15.
~
- 6. 16.
- 7. 17.
- 8. 18.
- 9. 19.
- 10. __
20. 1 j Reference Drawings P&ID: One-Line: Other: 1 2 i Figure 2
i <_ _ v t r ~ __ r ~__ _ =_= = ' - - '-
,PRocEDUREMo Revision POGE NO 14 3 2 ' ,'
.) VEGP 00304-C CLEARANCE SHEET CLEARANCE i Equipment / System / Number: Reason For Clearance: l Estimated Outage Time: Work Order f: Requested Date/ Time / Needed Date/ Time / Requested by: , Extension: Involves Tech, Spec, or Safety-Related Item: No Yes
-) Locked Valves: No Yes Prepared By Fire Protection Impaired No _ Yes _ Reviewed By ,
Authorized by: Date: Time Installed by: Date: Times 3 Verified by: Date: Time: SUBCLEARANCES GROUNDING DEVICES NAME VERIFIED REMOVED Printed in first space AND SUBCLEARANCE
^
Signature in second space RELEASED BY: PRIETED AND SIGNATURE WORK DOC EXT DATE TIME SIGNATURE 'DATE TIME 1. 2. 3. 4. 5. Subclearance Continuation Sheet Attached? Yes NO CLEARANCE REMOVAL: Authorized by: Date , Time Removed by: Date: Time Verified by: , Date Time: FRONT Figure 3a (TYPICAL)
.4
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l PMOCEDURE NO- CEVl&lON PAGENO. VEGP 00304-C 14 34 of 43 SUBCLEARANCES - CONTINUATION SHEET CLEARA' ICE i j GROUNDING DEVICES NAME VERIFIED REMOVED Printed in First Space AND SURCLEARANCE Signature in Second Space RELEASED BY: PRINTED AND SIGNATURE WORK DOC EXT DATE TIME SIGNATURE DATE TIME 1 i i Figure 3c mm
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P G G N R E A E _ R B mV AM E U L N C m l1llI li
Revision PAOL NO,
' l account 80 14 36 of 43 3 -
VEGP 00304-C FUNCTIONAL TEST FORM CLEARANCE i EQUIPMENT TO BE TESTED kEQUESTED BY REASON FOR TEST TEST DOCUMENT NO. CLEARANCE POINTS TO BE RELEASED CLEARANCE RESTORATION Req'd. Tag No. Equipment No. Pos. Init. Sequence Pos. Init. Init. - SUBCLEARANCE RELEASE CLEARANCE ALIGNMENT FOR TEST TIME DATE RESTORED TIME DATE VERIFIED BY TIME DATE TEST ALIGNMENT PERFORMED BY TIME DATE SHIFT SUPERVISOR PERMISSION TO PERFORM TEST TIME DATE _ Figure 5 m.*s
. PRO *4041. . REVISION I PAGE NO.
, y; :.
00304-C 14 37 Of '3 PARTIAL RELEASE FORM CLEARANCE in BOLD TAG i TO BE RELEASED HOLD TAG f TO BE RELEASED SUBCLEARANCE HOLDER SUBCLEARANCE HOLDER APPROVAL APPROVAL SIGNATURE DATE/ TIME SICNATURE DATE/ TIME SS APPROVAL: DATE/ TIME SS APPROVAL: DATE/ TIME PERFORMED BY: DATE/T!ME PERFORMED BY: DATE/ TIME VERIFIED BY: DATE/ TIME VERIFIED BY: DATE/ TIME Figure 6
Roct ung,v nomsion nog no. _ 38 of 43 I< QUALIFIED SUBCLEARANCE HOLDER LIST DATE DEPARTMENT The following personnel are qualified by demonstrated ability and procedural knowledge to hold a subclearance per Procedure 00.O4-C. i NAME (PRINT) SIGNATURE PLT EXT /HOME PHONE f/ BEEPER f DEPARTMENT HEAD APPROVED BY: MANAGER, OPERATIONS FIGURE 7 i
"'E$p" ' 0o3o4_i.
14 39 of 63 FUNCTIONAL TEST TAG l l , FOR ( INDIVIDU AL) . .. - CLE AR ANCE NO. TYPICAL FIGURE 8 } U _-_-____:-_ _ - _ _ - _ _ _ - _ - _ - _ _ _ _ _ _ _ _ - _ - _ - - _ _ - - - -
- PftOCEDURE No. FA,Ydd}; ' PAGE NO.
VEGP 00304-C 14 40 of 43 SUBCLEARANCE (SC) RELEASE FORM Clearance Number containing Subclearance to be released SUBCLEARANCE HOLDER (SCH) Being Released SUBCLEARANCE HOLDER (SCH) Work Phone No. SUBCLEARANCE HOLDER (SCH) Home Phone No. CIRCLE
- 1. Was attempt made to c.ontact M st home? YES NO
- 2. Vere applicable work orders and work YES NO document REVIEWED for completeness of work?
- 3. Was equipment field verified safe to YES NO operate i.e , no equip.nent or personnel safety concernet
- 4. Has SCH's supervision been notified? YES NO
- 5. Is it mandatory to release this CLEARANCE YES No now? If yes, state why:
]
- 6. Will action be taken to notify the SCH YES NO and CREW upon return to work that this SC has been releasedt f all Six Questions are answered "YES", sign below and on the
, .LEARANCE to release the SUBCLEARANCE HOLDER.
1'
#0505 DAtDM iDEFARTlH.NI SUPV. DATE/ TIME l DISTRIBUTION: 1) Ona copy attached to clearance
- 2) Original to Plant Managar
- Construction Duty Officer for construction subclearance holder.
A Discipline manager for construction subclearance holder. TYPICAL FIGURE 9 man _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ ________.____..______.___.___________.._..________._______.____._.______._________._______-___.__m__ _ _ - . _ - _ _ . - - _ _ -.m
I! L . DA EV VO OR MP 3 EP 4 RA f E . O T T S. I A 1 N DS 4 U 6 K R a A M n, E R e N O I T U A C G 0 O 1 L D EL E 4 N TA R 1 O AV U I IO T TR G U IP I A NP F C IA E . T A S. DS m k s R E w B M U N L C E
- N 4 A 0 P 3 /
0 T 0 N E M P I U Q E G _ A P T G R E NE aV a OB IM e.
- TU UN
- a. A e C n _
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*$P yt ' 00304-C l '. 42 ef 43
; t CAUTION CAUTION 00 NOT OPERATE THIS /
DO NOT OPERATE THIS EQUIPMENT UNTIL SPECIAL EQUIPMENT UNTIL SPECIAL INSTRUCTIONS BELOW ARE INSTRUCTIONS ON REVERSE THOROUGHLY UNDERSTOOD. SIDE ARE THOROUGHLY UNO2RST00D. CLEARANCE No. WPL NO. TAG NO. _ !] CEDRGIA POWER COMPANY NUCLEAR OPERATIONS CAT" TION CAI" TION
=m .mm nor-m. m.
&=ilE" uilL.E"
- 3. m = .e-== e= ==.
TYPICAL FIGURE 11 mm L.. _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ - - - - - - _ - _ _ _ _ _ - - - _ - - _ - - _ - - - _
. toun ngymon pEgii ADDITIONAL CLEARANCE POINT FORM Clearance Number Reason for addition E
Clearance Points Requested Equipment Nunber/Name Position Equipment Number /Neme Position
~ a SUBCLEARANCE H017;ER APPROVAL DATE TIME J
SHIFT SUPERVISOR APPROVAL ,Date Time PERFORMED BY DATE TIME VERIFIED BY , DATE TIME FIGURE 12 L - - - _ _ - - _ . - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ - . _ _ _ _ . _ - - - . _ _ _ _ _ . _ . _ . _ _ . _ _ _ . _ - _ _ . _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - . - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ - _ - - - . _s
wiovar no. naymow cAot e.o. VECF lbuc0-C 11 26 of 26
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AJl/,Y y QUESTION OR AREA NEEDING CLARIFICATION: k NAY 'DOFA /1)/ R 2 2A 8 7I0/8 (?0 0 A 0 $' ,, A //ect ' m c w ? INTERPRETATION: lL M st)l d6A)SA'D[A> LCOM $ F 4)/75 0
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Date xc: Manag M T/si$i$El Nuclear Safety E. Compliance Manager Engineering S pport Manager Plant Trainin E Baergency Prepardness Manager Required Read ng Book FIGURE 2
l , u I
' ON-tA-88-71 l l
FR$5/CWis.460 e ,- RT50 rh'id, Radiation 4 Support Systems l em 744 4317 Pa(ertare 2. I >= February 16, 1987 l**:' poron Dilution Event Analysis . RC5 Active Volumes 7,fjj,j;, 3g,ff, Yr/;y 1: J. C. Rock WECE 4-09 TransientInalysis WEC1 4 09 cct R. R. ftlins P.A.Leftusl R. K. 5tirre l E. C. Arnold K. P. 51sby R. A. toose P. A. Serilla ' File: M 791/2 8. C. Seguin MAN 781/2 Referencest 1 'etter FR55/CWBS 455, I 9 87. 2-Calculatten FR$5/CW55-C-091A, ' Addendum A to FR$$/CWp5 C 093 3 (M. calculatten RAM)",J.t.Fix FR$$/CW35 b f !!-87.U3, 'Seren Dilution Accident - RC Active Volumes", J. E. Fix, 2-t-87. In Reference 1 Fluids, Radiation,&SupportSystems(FRS$)hadtrans- < mitted the active mixing volume for use in the F54R Seren Dilution twent enelysis for several plants. This letter is a follow up letter as FR55 hos calev1sted and documented,)in Reference 2. the estive mi for leaver volumes include Valler he Unit volume #2of(tuti one and Seabreek full Asecter Unit Coolant #1 (RAN). Systes loop (notThe estiv ir.cluding tL. upper head neien of the reetter vessel) and one. Residual Neat Remeval train. h total active volumes for these plants e m as follows: teef . Seever Valley Unit ft 5013.7 us.ft. A4M - Seabrook Unit #1 5233.1 es.ft. Per peer vegvest the volmes c'/ those segments dish temposed the total active miains veImmes fte thee plants transmitted in Reference 1 en If there em ary geestions, please feel tabulated in the Attachner.t.
?=se to contact the.ondrestined. :
A"*[N
. E. ta, [ neer ical Wes e, & 90p Systems ,
8'*8888 /p1w Attachment
' CN-%88-71 ,.,e 1 er 1
/
Reforme. 2. / Attacheent to 255/cwas-460 p Seren Dilution Event Analysis d(dy/ Res Active volumes 3
*Ma&si The volumetrie unite are subic feet (ft ).
Rah / ens asm/RTR CAE CSE SAP (1) CDE SCP 78X TCX segeant 00E tant TWF/TEP Cc3 .... ...... 4 4 4 4 4 A 3 3 3 4 5 3733.7 3733.7 3643.5 4678.0 4678.0 4603.5 4646.1 4675.0 4731.3 h47.0 547.0 894.0 831 9 831.9 1919.9 019.9 831.9 831.9 (3)C 91.1 771 3 71.3 79.5 79.5 D 79.5 106.5 83.3 91.1 I 935.0 1000.3 973.6 1036.0 936.0 rD73.6 573.6 1936.0 936.0 138.9 135.5 137.7 137.7 <130.5 130.5 139.3 139.3 F 133.s 18 6 8 78.6 78.6 86.0 78.6, 78 6 v 86 0 ** 86.0 78.6 119.7 89.9 98.6 98.6 /80.8e 80.5 83.8 83.8 M 89.3 313.3 313 3 x 313.3 313.3 313 3 313.3 313.3 313.3 313.3 Total 4816.3 5013.9 4631.1 5611 4 5511.4 (339.1 5381.7 5555.5 5538.5 (1) Segment key !. A - e Ecs 1 epe 3 - Roseter Veseal volume g347 7 c = upper head end guide tube volumes D = Mat Zmg IF== 8/S (Pr ping volume - side volume ]wgjg yM Croceever Leg pi e - Reester Coolant volume volume
$ .g pDp g 8
)d{,
E = cold Img pining volume J h A.% / z - one num trala volume er -- (3)' h e total volume is the sum of asynente 3 and D through 2. The volume of segment C is enktreated. 4 4 9 _ W __:_ _____ _ ____
e s o f pa eseyo,
!'s ,.. )p ' , UNITED STATES 2 1 NUCl. EAR REGULATORY COMMISSION
'e / wasumotoN. o C. Mh66
\ * *s**'. -. ' f MAY l 6 IM?
HEHORANDUM FOR: Those on attached list FRON: Gary Holahan, Deputy Director Division of Systems Technology Office of Nuclear Reactor Regulation
$UBJECT: HEETin HINUTES FOR SHUTDOWd AND LOW POWER ISSUES CONFERENCE HELD ON APRIL 30 - MAY 2, 1991 During the period April 30, 1991 to May 2, 1991, a conference on shutdown and low power issues was held la Rockville, Maryland. The purpose of the conference was to provide a forum for cognizant NRC personnel and personnel from associated national laboratories to discuss shutdown / low power issues and draw preliminary insights on the risks associated with these issuet,. The discussions were based on on-going evaluations and experience in the areas of shutdown and low power risks such as AE00 operating experience reviews, NRR,'
site visits, Regional experience from inspections and operator licensing, and RES probabilistic risk assessme.its. The insights from the conference will be used to focus future program activities on the most safety significant issues, s. The final agenda covered a broad range of topics and is provided as Enclosure 1. A composite list of participants over the three-day conference is providgd in Enclosure 2. As a result of the discussions, preliminary insights were developed and are provided in Enclosure 3. The insights from the conference have been broadly categorized and are provided to you for review ano comment. Your review should include any coments on the completeness of the list from conference discussions as well as any additional insights which you think are warranted as a result of reflecting on the subject of shutdown and low power issues. All coments should be provided to Mark Caruso at (301) a?2-3235 by May 24, 1991 in order to expeditiously proceed with near term program activities. m (s L Gary> y#, Deputy Director Holaha Division of Systems Technology Office of Nuclear Reactor Regulation
Enclosures:
As stated cc: See next page
-~%91052 POP 69 910516 ' " = p PDR ORG NRT<D PUR .
l' l
%0ollt ,
. I l
t MAY f 41991 cc: Memorandum for those on atta.:hed list Ralph Architzel (801) William Arcicert (INEL) (NL 007) Jesse Arildsen (100 24) Jay Ball (9A-1) PhilBrochman(Rill) Allen Camp (Sandia) Mark Caruso (8E-23) NileshChokshi(NLS217) Donald copinger (ORNL) Mike Cullingford (12G-18) Mark Cunningham (NLS-372) Kulin Oesai Paul Doyle 100-22) ((8E-23) Bob Fitzpatrick (BNL) Daniel Gallagher (SAIC) Nanette Gilles (11E-22) Anthony Gody, Jr. (13E-21) Pete Habighorst (RI) Gary Holahan (8E 2) Kahtan Jabbour (9H-3) RonaldoJenkins(7E-4) JimKnight'(7E-4)(13E-16) LawrenceKokajko Jack Kudrick (801) George Lanik (AE00) Bill Lazarus (RI) l Melvyn Leach (Rill) Jim Lazevnick (7E-4)
- WarrenLyon(8E-23)
Fred Manning (AE00) George Minarick (SAIC) Robert Perch (8H-3) Marie Pohida (10E-4) William Raymond (RI) Mark Reinhart (11E-24) Howard Richings (8E-23) Richard Robinson (NLS-372) Faust Rosa (7E-4) Bob Samworth (13E-21) Susan Shanksan (100-24) Warren Swenson (13E-4) l Norman Wagner (80-1) . Len Ward (INEL) (NL-007) Hillard Wohl (11F-23) Ashok Thidant (BE-2) Willin Russell (12G-18) Thomas Novak, AEOD (MNBB-3701) Jack Samuel Rosenthal,(AE00 (MNBB-9715) Collins Region IV) l Brian Sheron, RES (NLS 007) NRR Division Directors Central Flies (P1-37) SRXB R/F , ! PDR: ,
~
. . . _ _ . _ - _ _ _ _ _ _ _ - . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ ~ _ _ _ _ __ __
i ! l , ENCLOSURE 1 1 FINAL AGENDA CONFERENCE ON SHUTDOWN AND LOW POWER ISSUES PROPOSED Dl5CUS$10N DATE SESSION SUBJECT LEADER 4/30 8:15 AM Opening Remarks Gary Holahan, NRR 8:30 AM Presentation on RES RES, BNL, SNL PRA Studies 9:00 AM Presentation on AEOD AE00 1 Review of Operating Experience 9:30 AM PWR Loss of Decay Heat Warren Lyon, NRR Removal and LOCA 4/30 Afternoon 15LOCA Sam Diab, NAR BWR Loss of Decay Heat Tim Collins, NRR Removal and LOCA 5/1 Horning Safety Assessment in Warren Lyon, NRR Outage Planning and Hanagement ,,
~ '
5/1 Afternoon Boron Dilution Howard Richings, NRR BW3 Fuel Hisload Howard Richings, NRR Heavy Loads / its1ph Archittel, NRR Tuel Handling , 5/2 Horning Availability of Jim Knight, NRR Electric Power , Containment Design Jack Kudrick, NRR and Closure Procedures 5/2 Afternoon Discussion of Overall Gary Holahan insights and Program Ofrection i s
. , , i 1
ENCLOSURE 2 CONFERENCE ATTENDECS SHUTDOWN AND LOW POWER ISSUES APRIL 30 - RAY 2, 1991 i NAME ORGANIZATION Ralph Archittel NRR William Arciceri INEL Jesse Arildsen HRR Jay Ball NRR Phil Brochman Region 111 Allen Camp Sandia Mark Caruso NRR Nilesh Chokshi RES Donald copinger ORNL Hike Cullingford NRR Mark Cunningham RES Kulin Desai NRR Paul Doyle NRR Bob fitzpatrick BNL Daniel Gallagher SAIC Nanette Gilles HRR Anthony Gody, Jr. NRR Pete Habighorst Region ! Gary Holahan NRR Kahtan Jabbour NRR Ronaldo Jenkins NRR Jim Knight NRR Lawrence Kokajko NRR Jack Kudrick NRR George Lanik AEOD Bill Lazarus Region i Melvyn Leach Region !!! Jim Lazevnick NRR Warren Lyon NRR Fred Manning AEOD George Minarist SAIC ' Robert Perch HRR Marie Pohida NRR William Raymond Region I Hark Reinhart NRR Howard Richings NRR Richard Robinson RES Faust Rosa NRR Dob Samworth NRR ', Susan Shankman NRR Warren $wenson NRR Horman Wagner NRR Len Ward INEL Hillard Wohl NRR s
___m..... l- - t n ENCLOSURE 3
'H51GHT5 FROM CONFERENCE ON SFUTDOWN AND LOW POWER 1550E5
- 1. DUTAGE PLANNING AND CONTROL A. GENERAL -
Cutage plenping and control may be the most significant elements of shutdown 1d low power risk. All utility personnel and programs are stressed during shutdown operations:
- Operations '
Engineering Maintenance Er.ergency Planning
- Security RAD Protection Industrial Safety Contractor controls and trainin during chutdown is inconsistent (particularly for new individua s). e In general, the emergency planning programs have not considered the special circunstances and problems enccuntered during shutoown (e 3.,
evacuttion of workers, ability of TSC and others to deal with complex configurations). , The effect of outage activities on operating units on the s ee site (e.g.,sharedsystens,wrongunit). Forced outages get less planning but involve fewer and less complex l activities. Rate of loss of 4/c power to safety busses has been much greater during shutdown than during power operations. l
- Fuel' hand 11tig and heavy loads do not appear to be significant shutdown risk issues.
l 8 CPERATIONS Operators have less centrol of activities and plant condittons during shutdown than during power operations. Entering and maintaining PWR mid loop operation is a significant vulnerability. Operator actions are generally more necessary for events that occur (furing shutdodo operation than for events initiating during power operation. l k
l'. , 2
- Response procedures are weak.
- Not specifically developed for shutdown operation %. ,,,
- Incomplete /not symptom oriented. , , ,
- Tor additional study - effects on plant staff of
- Overtire during outages
- Changing shift rotations
- Rapidly changing plant configuration '
- Accommodating to shutdown activities
' Operator Training . .
- NRC operator exams generally do not cover shutdown conditions.
- Simulators generally don't cover shutdown conditions.
- Technical Specifications
- Plant modes in Tech Specs don't correspond to risk significant operating condition (e.g., PWR mid-loop, def9eled).
- Shutdown mode T/5s can be confusing and don't consistently ,
establish minimum requirements.
- Sort plant-specific T5s have no requireme'nts on electrical power systems during shutdown. ,
- STS typically only require one division of electrical power sources (1 EDG, 1 offsite, 1 battery, 1 ac distribution system, 1 DC bus, 2 vital ac buses from inverters) reg'ardless of load requiretrents (Modes 4 and 5 for BWRs, Modes 5'and 6 for PWRs).
!]. HARDWARE / DESIGN
- Shutdown instrumentation is not designed for shutdown conditions
- Operators have reduced confidence in instrutnents
- Availability problems
- Inappropriate ranges
- Instruments not well understocd
- Core terrperature of ten not monitored
- Demands on equipment during various rtedes/ configurations not always consistent with the design of the equipment (e.g., LPCl/RHR).
- BWRs generally have more water available during shutdown.
- Injection sources
- Higher level in vessel
* ; I l
l BWR (i.e., only Harklimited I ar.d !!s have no ' containment'
' confinement" capability capability)during exists refueling
- PWRandBWRMark111containmentsmaybecapableofconta'idingshut-down accidents if appropriate plans and procedures are available.
- PWR containment integrity may be important during mid loop operation.
- ECCS recirculetion capability may be reduced or lost by intentional sump isolation (i.e., coverage to prevent debris entry) or by foreign material in containe.ent during shutdown.
- PWR upper internals may inhibit water from entering the core from the refueling cavity.
- BWR loss of DHR is less significant th6n PWR loss of DHR.
- For additional study - Containment perforrance during accidents initiated from shutdown.
' F9r additional study - Role of secondary containment in shutdown accidenu.
J
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i . UNITED STATES OF AMERICA , NUCLEAR REGULATORY COMMIS SION 4
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r i litl6l BRIEFING ON SiiUTDOWN RISK STA'tUS LOCatiOIll RocxvzLLE, MARYLAND Dat6 JUNE 19, 1991 Pa965 71 PAGES .
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NEAL R. GROSS AllD C0., Ilic. COVRT 8tP081E85 AND TRAhSCt!Btts 1323 Rhode Island Avenue, Northwest - Washington, D.C. 20005 (202) 234-4433 W
1 improvcm:nto in training and prcuduroc. Thoro is o 2 general observation that both training and procedures 3 have really historically been developed to deal with 4 power operation, and this really runs the gamut from 5 emergency procedures, use of simulators. Even NRC 6 operator licensing program has really been focused on 7 power operation and shutdown activities have not been B really focused on and it's lef t those areas with less 9 well-defined, less robust programs, and it's something 10 that we think is important enough to look at. 11 The fourth item deals with technical 12 specifications. One of them I think Bill mentioned 13 earlier has to do with mode definitions. It became 14 clear when both national laboratories began to put 15 together their PRAs that the current mode definitions 16 in technical specifications are really not detailed 17 enough to identify the safety-significant conditions 18 that the plant is in, the most obvious one being mid-19 loop operation for PWRs. That's no'. identified as a 20 specific mode, doesn't have specific applicable 21 limiting conditions for operation. It's really 22 treated as either part of mode 5, cold shutdown, or 23 mode 6, refueling, depending upon whether the head is 24 i tensioned or not. 25 But when the tech spec requirements were NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAHO AVENUE, N W WASHINGTON D C. 2000$ (2021 232 4600 (202) 234 6433
1 g:nzrotzd for moda 5 cnd 6 th;y rool) dl ' .' t cnvicion 2 the plant being in mid-loop operation. When the plant 3 is in mode 6, refueling, we normally think of the 4 refueling canal full of water, 23 feet of water and 5 300,000 or 400,000 gallons of water above the core, 6 but in doing the PRAs it becomes clear that that 7 typical condition is not really what always exists. 8 When you're legally in mode 6, there's really a 9 variety of conditions that the plant could be in. 10 In some of our discussions with utilities, 11 it's become clear that when they plan an outage -- I 12 remember one utility took mode 5 and divided it into 13 i SA, 58, SC, because mode 5 didn't really estsblish 14 unique conditions that set the real safety 15 requirements for equipment and for activities. So, 16 that's something that we think is important to look 17 ij' into. 0 18 i The other part of the toch spec issue that N 19 turned up as important is the variability in what 20 really As required in shutdown. What we find is, 21 particularly in the older plants with custom tech 22 specs, there are really minimal requirements on system 23 availability during s..utdown and refueling modes. 24 , There are a number of plants, for example, which have 25 no requirements for AC power availability when the 1
- l. NEAL R. GROSG d CX)UR7 REPORTER $ AND TRANSCR@CR$
1373 RH00E ISLAND AVENUE, N W. um,,-n mN,~m0N. o c. m. g ,,, ,u ox
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101 M ARitTT A $f RttT, N W. ATL ANT A. CEOm01 A 30323 g- 1 DEC 17 Wdi Docket No. 50-424 'I ;S-License No. NPF-68 , M t Georgia Power Company I ATTN: Mr. James P. O'Aeilly l Senior Vice President-Nuclear ;
- Operations 1
P. O. Box 4545 Atlanta, GA 30302 Gentlemen:
SUBJECT:
INSPECTION RCPORT NO. 50-424/87-60 i This refers to the Nuclear Regulatory Commission (NRC) inspection conducted by Messrs. - J. F. Rogge, C. W. Burger, and R. J. Schepens en October 8. - November 20, 1987.- The inspection included a review of activities authorized for your Vogtle facility. At the conclusion of the inspection, the findings T
- were discussed with those members of your staff identif'ed in the enclosed inspection report.
Areas examined during the inspection are identified in the report. Within i these areas, the inspection consisted of selective examinations of procedures and representative records, ' interviews with personnel, and observation of activities.in progress. Within the scope of the inspection, no violations or deviations were identified. In accordance with Section 2.790 of. the NRC's " Rules of Pr.ctice " Part 2 Title 10, Code of Federal Regelations, a copy of this letter and the enclosure
~
will be placed in the NRC Public Document Room. ' Should you have any questions concerning this letter, please contact us. Sincerely, c / /
.]/s'nft)k:M' Virgil"L..Brownlee, Chief N.
Reactor Projects Branch 3 Division of Reactor Projects
Enclosure:
NRC Inspection Report. cc w/ enc 1: (See page 2) N-g y y ,. ,.9.M-++y- e
V Georgia Power Company 2 DEC 171987 cc w/ enc 1: P. D. Rice, Vice President, Project Director C. W. Hayes, Vogtle Quality Assurance Manager G. Bockhold, Jr., General Manager, Nuclear Operations L. Gucwa, Manager, Nuclear Safety and Licensing J. A. Bailey, Project Licensing Manager B. W. Churchill, Esq., Shaw, Pittman, Potts and Trowbridge D. Kirkland..!!!, Counsel, Office of the Consumer's Utility Council D. Feig, Georgians Against Nuclear Energy
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- NUCLEAQ AEGULATORY COMMIS$10N j.I,1,'
j miciok al tot MAmitTTA stattT.N w. j ATL ANT A, ClomGIA 30M3 ) s, .....j Report No.- 50-424/87-60 Licensee: Georgia Power Company P. O. Box 4545 Atlanta, GA 30302 Docket No.: 50-424 License No. NPF-6B Facility Name: Vogtle 1 Inspection Conducted: October 8 - November 20, 1987 n CA /~/ dc:t (t. ned I Inspectors;i[J.Rogge,SeniorhesicentInspector / 2-[/O[f 7
.n Date Signec f.G.,/ /YnA-oYo~ c
! ? / /G lf 7 g6 R. J. Schepens, Resloent inspector Date Signed f E ') b nb;oae p ** L{. W. Burger, Resitaent Insractor i 2//G fl*?
~0 ate 51gneo Approved by:
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- i. I V R D T sintule, section cnief Division of Reactor Projects oate s39 nee
SUMMARY
Scope: This routine, unannounced inspection entailed resident inspection in surveillance, areas: the following fire plant operations, raGlological controls, maintenance, protection, security, and Quality programs and acministrative controls affecting Quality. Results: No violations or deviations were identified. ,{ {?Q(U bk - a w
I REPORT DETAILS I
- 1. Persons Contacted
- Licensee Employees 4
G. Bockhold, Jr., General Manager Nuclear. Operations :
*T. V. Greene, Plant Support Manager
-i
*R. M.-Bellamy, Plant Manager i
*E, M. Dannemiller, Technical Assistant to General Manager t C. C.-Echert -Technical Assistant to Plant Manager "J. E.- Swartzwelder, Nuclear Safety & Compliance Manager .
*W.,F. Kitchens, Manager Operations R. E. Lide, Engineering Support Supervisor
*H.-Varnadoe, Plant Engineering Supervisor
*R. E.-Spinnatu, ISEG Supervisor C. W. Hayes, Vogtle Quality Assurance Manager :
-"G. R.--Frederick, Quality-Assurance Site Manager - Operations !
W. E. Mundy, Quality Assurance-Audit Supervisor , M. A. Griffis, Maintenance Superintendent !
*R. M. Odom, Plant Engineering Supervisor +
*C, L. Cross, Senior Regulatory Specialist-
- 5. F. Gof f, Regulatory Specialist
*A. L. Mosbaugh,- Assistant Plant Support Manager H. M. Handfinger, Assistant Plant Support Manager i F. R. Timmons, Nuclear Security Manager Other licensee employees contacted included craftsmen, technicians, supervision, engineers, . operations, maintenance,- chemistry, inspectors,- l and office personnel, i
- Attended Exit'!nterview '
P
- 2. Exit Interviews-(30703)
The inspection scope and findings were summarized on November 20, 1987, . with - those persons indicated in paragraph 1 above. -The inspector j described the -areas inspected and discussed .in detail the inspection i results.: No dissenting' comments were received from the licensee. The; , licensee did not identify as proprietary any of the materials provided- to 1
-or; reviewed by the inspector during this inspection, . Region based .NRC l 1 exit interviews were attended during1the inspection period by a- resident !
inspector,
2
- 3. Operational Safety Verification (71707)(93702)
The plant began this inspection period in Power Ope ation (Mode 1) at 100', power until October 9 when the unit was tripped to complete a portion of the startup testing program and commence a short outage. The outage Droceeded without difficulty until the number 1 reactor Coolant pump motor failed. As a result of the failed motor, Unit I restart was delayed approximately seven days. The unit entered Hot Standby (Mode 3) on October 27. . Shortly after achieving Mode 3 the residual heat removal cretstie valve motor operator failed and the engineering wallcowns identified that the reactor vessel level instrument impingement plates were not installed. These two problems resulted in further startup delays. On October 31 the unit entered startup (Mode 2) and acnieved Mode 1 on November 1, The unit achieved 100", power on November 4 On November 5 the unit tripped on a turbine trip when a vibration sensor was bumped. The unit returned to Mode 1 on November 6 and achieved 100% on November 7. On November 9 the unit performed the 10*, load swing startup test. On November 11 the unit tripped from 100% reactor power when the wrong test panel was U$66 during the performance of a reactor trip breaker test. On November 12 the unit returned to Mode 1 and achieved 90% power. From November 12 through 17 the unit experienced secondary water chemistry problems which limited power and required the plugging of condenser tubes. On November 18 the unit was held at 98% power while engineering concerns in regard to exceeding the 3411 MWT limit were resolved. On November 19 the unit achieved 100*, power. The plant experienced three ESF actuations; the Control Room Emergency Ventilation System on October 26 when a technician improperly reset the radiation monitors and on November 17 when RE-12116 spiked high, an auxiliary feedwater actuation on November 5 when an operator shut the discharge valve of the running Condensate pump due to improper labeling, and a Containment Ventilation Isolation from RE-2565 on November 9 when the check source did not fully retract. A Notice of Unusual Event was reported on November 17 when power was lost to meteorological instruments.
- a. Control Room Activities Control Room tours and observations were performed to verify that facility operations were being safely conducted within regulatory requirements. These inspections consisted of one or more of tne following attributes as appropriate at the time of the inspection.
Proper Control Room staffing Control Room access and operator behavior l Adherence to approved procedures for activities in progress I {
3 Adherence to Technical $pecification (TS) Limiting Conditions for Operations (LCO) Observance of instruments and recoroer traces of safety related and imoortant to safety systems for abnormalities Review of annunciators alarmed and action in progress to correct Control Board walkcowns Safety parameter display and the plant safety monitoring system operability status Discussions and interviews with the On-Shift Operations Supervisor, $hif t Supervisor, Reactor Operators, and the Shif t Technical Advisor to determine the plant status, plans and assess operator knowledge Review of the operator logs Unit log and shift turnover sneets No violations or deviations were identified.
- b. Facility Activities Facility tours and observations were performed to assess the ef fectiveness vf the administrative controls established by direct observation of plant activities, interviews and discussions with licensee personnel, independent verification of safety systems status and LCO's, licensee meetings and f acility records. During these inspections the following objectives were achievec (1) Safety System Status (71710) -
Confirmation of system operability was obtained by verification that flowpath valve alignment, control and power supply alignments, component conditions, and support systems for the accessible portions of the ESF trains were proper. The inaccessible portions are confirmed as availability permits. Additional in-depth inspection of the Auxiliary Feedwater System was performed to review the system lineup procedure with the plant drawings and as-built configurations, compare valve remote and local indications, and walkdown of hangers, supports, snubbers and electrical equipment interiors. The inspector verified that the lineup was in accordance with license requirements for system operability. (2) Plant Housekeeping Conditions - Storage of material and components and cleanliness conditions of various areas throughout the facility were observed to determine whether safety and/or fire hazards existed. t (3) Fire Protection - Fire protection activities, staffing and (. equipment were observed to verify that fire brigade staffing was i appropriate and that fire alarms, extinguishing equipment, actuating controls, I fire fighting equipment, emergency equipment, and fire barriers were operable.
4 (4) Radiation Protection (71709) - Radiation protection activities, staf fing and equipment were observed to verify proper program implementation. The inspection included revier of the plant program ef fectiveness. Radiation work permits and personnel compliance were reviewed during the daily plant tours. Radiation Control Areas (RCAs) were observed to verify oroper identification and implementation. (5) Security (71881) - Security controls were observed to verify that security barriers were intact, guard forces were on duty, and access to the Protected Area (PA) was controlled in accordance with the facility security plan. Personnel within i the PA were observed to verify proper display of badges and that personnel requiring escort were properly escorted. Personnel within vital artas were observed to ensure proper authorization for the area. Equipment operability and proper compensatory actisities were verified on a periodic basis. - (6) Surveillance (61726)(61700) - Surveillance tests were observed to verify that approved procedures were being used; qualified personnel were conducting the tests; tests were adequate to verify equipment operability; calibrated equipment was utili:ed; and TS recuirements were followed. The inspectors observed portions of the following surveillances and reviewed completed data against acceptance criteria: Date Surv. No. Dept. Title 11/3/87 14915-1 Ops OPTR Special Condition Surveillance Log 11/4/87 14915-1 Ops Control Rod Insertion Limits Special Condition Sury. Log 11/4/87 14205-1 Ops Plant Emergency signal weekly Operability Test 11/4/87 14805-101 Ops Quarterly. Train B RHR Pump & Check Valve Inservice Test 11/6/87 14808-102 Ops Quarterly, Train 8 CCP & Check Valve Inservice Test 11/19/87 14030-1 Ops Power Range Calorimetric Channel Calibration 11/20/87 14825-108 Ops Quarterly, Train A AFW Valve Inservice Test (7) Maintenance Activities (62703) - The inspector observed maintenance activities to verify that correct equipment clearances were in effect; work requests and fire prevention ' work permits, as reauired, were issued and being followed; quality control personnel were available for inspection activities as required; retesting and return of systems to
5 service was prompt and correct; TS requirements were ceing followed. The maintenance backlog was reviewed and noted as consisting of approximately 2,100 MdO's (i .e. , both correettve and preventive) pri;r to tne outage. Maintenance had scneduled 249 maintenance work orders to be worked during the outage. During the cutage the inspectc* observed that maintenance nac actually performed an additional 151 MWO's due to discovery items and 109 Mw0's due to the forced outage on tne reacter coolant pump motor in addition to the 249 MWO's planned for a total of 509 MWO's. At the completion of the outage the outage backlog had been reduced from 506 to 300 MWO's, however the total MWO backlog had increased slightly from 2,100 to 2.175 MWO's. The inspector either observed maintenance activities or reviewed completed maintenance work packages for the following maintenance activities: MWO No. Dept. Work Description 1-87-02793 Elect. Maint. Perform MOVATS Procedure and DCP VIE 007 1-87-05326 Elect. Maint. Investigste Problem Witn Open Indication Light Not Working 1-87-08736 Mech. Maint. Implement Design Change Package To Pressurizer Level Transmitter LT-461 1-87-11815 Maint./ Chem. Condenser Waterbox B West Tube Leak Check & Plugging (8) Outage Activities (71711) - The inspector observed portions of the outage activities to determine management effectiveness in conducting outages. While this was not a refueling outage it did demonstrate the liceasee's ability to schedule, prepare, and execute the plan. As noted above, at the completion of the outage the outage backlog had been reduced from 506 to 300 MWO's. During the course of the outage teamwork was evident in surfacing new problems and achieving resolution to prevent a new critical path f rom developing. The planned critical path work involving the removal of the temporary steam strainers was achieved ahead of schedule. Tne outage work inside containment was performed with few difficulties. Two major items did occur which had severe schedule impact and resulted in a seven day restart delay. These items were the motor replacement on the number one reactor c C lant oump and the failed motor on tne RHR cros3 tie valve HV-87'68. Teamwork in resolving both problems . resulted in a very ::ercinated repair effort. Unit recovery was delayed upon discover f inat tne impingement plates for RVO S were not installec cor 'ccatacle, which required new oieces 10 . be fabricated.
6 No violations or deviations were identified 4 Review of Licensee Reports (90712)(90713)(92700)
- a. In-Office Review of Periodic and Special Reports This inspection consists of reviewing the below Iisted reports to determine whether the information reported by the licensee is technically adeQutte and consistent with the inspector Knowleoge of the material contained within the report. Selected material within the report is questioned randomly to serify accuracy to provioe a reasonable assurance trat other NRC personnel have an appropriate document for their activities.
Monthly Operating Reports - The report dated October 8,1987 was re vi eweri. The inspector had no significant comments regarding these reports.
- b. Licensee Event Reports (LER's) and Deficiency Cards (DC's)
Licensee Event Reports - (LER's) and Deficiency Cards (DC's) were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate. Events which were reported pursuant to 10 CFR 50.72, were reviewed as they occurred to determine if the technical specifications and other regulatory reqairements were satisfied. In-of fice review of LER's may result in further _ followup to verify that the stated corrective actions have been completed, or to identify violations in addition to those descrdbed in the LER. Each LER is reviewed for enforcement action in accordance with 10 CFR Part 2, Appendix C. Review of DC's was performed to' maintain a realtime natus of deficiencies, determine regulatory compliance, follow the licensee corrective actions, and assist as a basis for closure of the LER when reviewed. Due to the numerous DC's processed only those OC's which result in enforcement action or further inspector followup with the licensee at the end of the inspection are discussed as listed below. The LER's denoted with an asterisk indicates that reactive inspection occurred at the time of the event prior to receipt of the written report. (1) Deficiency Card reviews: OC 1-87-2616 "05-416 Reactor Trip Bre8ar Inspections" This deficiency documents the results of the weld inspections. During the inspections the NRC resident and vendor brancn inspectors were present. The resul;s of the inspection were acceptable however the NRC recommended that the shafts De replaced in the long term. These inspections were performec to address the concerns as addressed in Information Notice No. 87-35.
7 OC 1-87-2708 "RVLIS Impingement Covers" On 10/23/87 the impingement cover plates for RVLIS tubing for 1-LX-1310 and 1-LX-1320 were not installed. In order to correct inis croblem new plates were f'abricated and installed. This resulted in a delay in return to power. l' DC 1-87-2733 " Control Room Isolation While Resetting Radiation Monitors" This DC describes an unplanned actuation on 10/26/87 when tne radiation parameter resetting procedure did not call. for blocking of the output. In addition poor communication ~ between operators and the chemistry department was exhibited in that the status of the Control Room Ventilation being reset-was not fully understood nor was the nature of work to be performed. ; DC 1-87-2753.1-87-2766,1-87-2846 " Mode 3 Entry Performed without' all requirements met" These deficiency cards documented three instances that the licensee identified af ter the unit entered Mode 3 -The three cases were failure to perform IST testing on ' the A train AFW discharge check valve- following maintenance,- ' failure to have the Steam Driven AFW pump steam admission valves-open, and failure to perform a functional test of the A train safety injection pump following changeout of the lubricant. Each instances had minimal impact as follows: the check valve e tested satisfactorily, full secondary steam pressure had not ; been obtained to support the surveillance testing, and the safety-injection pump was tested satisfactorily. DC 1-87-2915 " Reactor Trip While Performing OSP 14701-1" This Reactor Trip resulted when the 3 train auto shunt trip test- - panel was used during the testing of_the A train breaker. While ' the procedure directed the operator to the correct test. panel no' ' labeling was in place at the test panel to indicate that the ' wrong train was being utilized. During the performance of- the undervoltage coil trip test no additional indication ' existed to indicate that the shunt coil had not been blocked. When the ' shunt coil trip test was executed the B train shunt coil i energized and the B train reactor trip breaker opened. Since the A train $$PS was in test-to support A train reactor trip breaker testing- the control room operator had to insert a manual-trip to open the A- train reactor trip breaker and perform a manual start of the A train Auxiliary Feedwater Pump. DC 1-57-2974 " Missed Surveillance" -This deficiency occurred on November 16- when a- room temperature- 'veillance was not performed due to the floor being painted. The operator NA'd the step which was later identified during a supervisor review and > at that time it-was noticed that the TS had been missed.- (2) The following LER's were reviewed and are ready for closure pending verification that the licensee' stated corrective actions have been completed.
B (a) 50-424/87-05, Rev 0-4 "120V AC Voltage Transient Causes ESF Actuations" These LERS describe a plant concision where a voltage transient causes ESF actuations uoen energization of the Safety System Secuencer Panel. The inspector noted to the licensee that the final supplemental LER was due on July 30, 1987. The licensee informed the inspector that the LER will be closed on January 1988 once the information is received from Westinghouse. (b) 50-424/87-20, Rev 0 "ESF Actuation Caused by Excessive Leakage Through a Main Feedwater Regulating Valve" Tne inspector noted to the licensee that the final supplemental LER was due on July 10, 1987. The 'icensee informed the inspector that the LER will be closed once the final corrective action is performed. The LER states that further testing of valve IHV-5139 will be performed when the unit is in Mode 3. The Licensee failed to accomplish-this test during the outage but will do the test at the next forced outage or refu0 ling. The final LER will be issued following the test. (c) 50-424/87-56, Rev 0 " Technical Specification Not Met Due To incomplete Vendor Sof tware For Oose Calculations" This LER describes an event which occurred on September 16, 1987 when it was identified that the cumulative dose calculation program fcr gaseous releases to the atmosphere for
' radiciodines did not include isotope 1-133 in the sof tware package. The licensee identified this during a data review !
while preparing the semi-annual radioactive effluent ' release report. Corrective action includes revising the sof tware and the performance of a functional testing, The inspector has no further questions regarding this report. The following is identified: 50-424/L!v87-60-01 " Failure To implement an Appropriate Surveillance to determine cumulative dose contributions in accordance with the 00CM per TS 4.11.2.3 - LER 87-56" (d) 50-424/87-58, Rev 0 " False Signal From Rad Monitor Leads To Control Room Isolation" This LER describes an event which occurred on September 21, 1987 when the control room isolation occurred due to a f alse high radiation signal from 1-RE-12116.
- While no- violations resulted from this event the licensee has yet to specify the root cause of the l
l failure in a supplemental report due December 15, 1987. (3) The following LER's nere reviewed and are considered closec. (a) 50-424/87-01, Rev 0 " Incorrect Transmitter Circuit 8:ard Leads to Missing a Required Flow Rate Estimation" This .ER was reviewed in NRC Rpt 50-424/87-44 and recuirec L -
__ _ . --__.. _._ _ _ _ _ _ . _ . _ _ . _ _ _ _.m___ _ _ . _ . _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ i i 9 1 verification of the corrective actions. The inspector reviewed procedure 34226-C and tne training attendance : sheets. The following item is identified: ' 50-424/ LIV 87-60-02 " Failure to Perform reovired T5 I Surveillance to Verify compliance with TS 3.3.3.10 - LER87-01" (b) *S0-424/87-02, Rev 0 " Potential Failure of MSIV's to Close ' Following Small Steam Line Break" This L.ER was reviewec in NRC Rpt 50-424/87-44 and required verification of sne corrective actions. The inspection revitwed the vencor qualification report dated 3-20-87. This report documents that the main steam isolation valves which were supplied can remain in the open position for approximately I hour ! while exposed to a 320 degree F environment and retain the capability of closing and stopping steam flow in the : system. The inspector noted that the test configuration included the relief valve (4100 psi) and that the hydraulic pressure reached only 3950 psi during the test. OCR 87 V!E 0030 was also reviewed, No further corrective actions are required as a result of the test report. (c) *S0-424/87-03, Rev 0 " Restriction of Pipe Movement with Incorrect Penetration Sealant Material" This LER was reviewed in NRC-Rpt 50-424/87-44 and corrective action was verified during the course of the event. The inspector nas , no further questions. (d) '50-424/87-04, Rev 0 "Contai, snt Isolation Actuations i Caused by Faulty Circuit Board" This LER was reviewed in NRC Rpt 50-424/87-44. Corrective action = was verified regarding the repair of the f aulty circuit during the course of the event. The inspector verified that a new annunciator has been added and 17006-1 response procecure changed. In addition the inspector noted that the radiation monitors have been removed as an input to containment isolation. (e) *50-424/87-06, Rev 0 "ESF Actuation of Auxiliary Feedwater Due to Inadvertent Trip of the Main Feedwater Pumps" This LER was reviewed in NRC Rpt 50-424/87-44 and corrective action was verified during the course of the event. The inspector notes'that a further corrective action has Deen the practice of removing the control fuses to the actuation circuit for AFW. This practice its resulted in LER 57-36 when the wrong fuses were pulled. ( f) *50-424/87-07 Rev 0 "ESF Actuation Caused by Steam Generator Water Level"; "50-424/87-09, Rev 0 "ESF Actuation Caused- by Adjustments to Steam Generator Level Control I (
- - - - - , - ,- ,,m-- _ . . --..----r_m . . , . - - - - ~ , . ,
1 t 10 Syst*ms"; '50-424/87-10. Rev 0 "RPS Actuation Caused oy ! Adjus;ments to Steam _ Generator Level control Systems"; ;
'50-424 M 12, Rev 0 " Reactor Trip Due to Feeo ater Control Problems Following Generator / Turbine Trio"; *$0-424/87-14 Rev 0 " Steam Generator High Level Results in Reactor Trip";
*50-424/87-18. Rev 0 " Reactor Trip Caused oy Faulty Bistable Circuit Board"; *$0-424/87-24 Rev 0 " Procedure ;
Inadecuacy Causes Auxiliary Feedwater Attuation"; ;
'50-424/87-25. Rev 0 " Reactor Trip Due to Startup Test Procedure inaceouacy"; *50-424/87-27. Rev 0 " Reactor Trio Caused by inadvertent Closure of M51V During Mainter.ance";
*5u424/87-30. Rev 0 " Lightning Causes Reactor Trip Due to Incorrectly Grounded Current Transformer"; '50-424/87-31, Rev 0 " Auxiliary Feeowater System Actuation During Startup Test Due to Procedure Inadequacy"; '50-424/87-34 Rev 0 "Reactur Trip Due to Failure of Main Feedwater Pump Discharge Check Valve"; '50-424/87-35, Rev 0 " Faulty Main Feedwater Pump Turbine Hydraulic Tubing Connection Leads to Reactor Trip"; *50-424/87-36, Rev 0 " Auxiliary Feedwater Actuation Circuitry Inoperable Due to Personnel Error",
*50-424/87-39, Rev 0 " Pressure Transmitter Failure Cause.
E5F Actuation on Steam Generator Hi-Hi Water Level";
'50-424/87-41. Rev 0 " Reactor Trip Due to Improperly Calibrated Field Current Transducers"; *50-424/87-50, Rev 0
" Reactor Trip Caused by Instrument Technician's Error" These LERs were reviewed in NRC Rpt 50-424/87-38 and NRC Rpt 50-424/87-44 with corrective action verified during the course of the events. Additional NRC concerns were addressed in several management meetings regarding the control of Steam Generator water level. Improved system performance resulted from increased operator experience and additional system tuning.
(g) *50-424/87-11, Rev 0 " Trip due to Lo-Lo Steam Generator Level" This LER was reviewed in NRC Rpt 50 424/87-44. The inspector noted that the corrective actions included temporary markings on the site glass and an engineering evaluation to cetermine further correction action. The inspector questioned the final status of these two actions and was informed that no further actions were rutcessary.
- (h) *50-424/87-13, Rev 0 "Feedwater System Valve Malfunctions Result in Reactor Trip" This LER was reviewed in NRC Rot 50-424/87-44 and at the time of the event. MWO 1-87-4987 was reviewed to verify proper reassembly. LER 87-34 describes a rupeat failure of the same check valve and describes furtrer corrective action.
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11 (1) *S0-424/S7-15. Rev 0 "Inaovertent $ team Dump Operation Results in ESF Actuation" This LER was reviewed in NRC Rpt 50-424/87-44 and at the time of the e ca,. Training was verified regarding the Conrection of test racks. The in50ector noted to the licensee that tr. ,ER implies that the event steam header pressure cortrol lorp wn tested after the to ensure its proper operation was oart of the corrective action, when in fact the cnly testing was as part of the power ascension test phase. The licensee nas not been responsive in revising the LER. (j) *50-424/87-19, Rev 0 ' Control Room Isolation Jue to Signal From Toxic Gas Mond tors"; "50 424/87-28, Rev 0 " Control Room Isolations Caused by Spurious $1gnals From Toxic Gas Monitor" proce6te 24537-1 and 24538-1 were reviewed to verify that monthly ca'libration checks were implemented. It was noted that the licensee is not required to have operable monitors $ nce chlorine is removed f rom the site. d The Itcensee is pursuing a TS change to raise the setpoint f rom 2 to 5 ppm to eliminate spurious actuations and then return chlorine onsite (k) 50-424/87-21, Rev 0 " Control Room Isolation Initiated by Radiation Monit - Loss of Power" The final corrective actions for this problem will be discussed along with the resolution of LER87-05. (1) *50-424/87-23 Rev 0 "RHR System Minimum Flow Requirement Potaatially Not Met Due to Partially Closed Valves" This LER was reviewed in NRC Rpt 50-424/87-31 and resulted in the identification of a Severity Level Ill Violation 50-424/87-31-02. Procedure 14460-1 was verified to have the changes and the preventive niaintenance sheets indicate the calibration frequency to be every six months. The corrective MW0s were also reviewed. (m) *50-424/87-32, Rev 0 " Operator Error Leads to a Reactor Trip on Source Range High Flux" Procedure 12003-1 was reviewed to verify the requirement for a ICRR plot and a reactor engineer. Procedure 14940-1 was reviewed for to verify incorporation of correct boron worth and that the procedure will be performers by a reactor engineer. The training plan , and simulator changes were reviewed. (n) *50-424/87-33, Rt v 0 " Reactor Trip on Steam Generator Lo-Lo Level while Trarsferring Feedwater Flow" Procedure 12004-1 was reviewed to verify that the correct power levels were indicated for t ansferring from the Bypass Feedwater l regulating valve to the Main Feedwater regulating valve.
4 12 (o) '50-424/87-37, Rev 0 " Failure to Meet Technical - Specification Action Statement Due to Procecural Inadecuacy" Procedure 00150-C was reviewed to verify the additional guidance was incorporated. The inspector interviewed the NSSS engineering supervisor to cetermine the results of the LLRT performed during the outage. ine results indicated that while degradation was noted the valve was within the acceptance criteria. The inspector determined that no actJal TS violation had occurred since the valve was inoperable due to the potential that the leakage was high. This event served in identifying a procedural system weakness. (p) '50-424/87-38. Rev 0 " Manual Reactor Trips Due To Overly Conservative Annunciator Response Procedure" Procedure 17010-1 was reviewed to verify that the response procedure has been revised to place DRPI in the Data A or Data B to regain rod position indication prior to a manual trip. (c) "50-424/87-42, Rev 0 " Boron Concentration Exceeds Tech. , Spec. Limiting Condition of Operation Time Limit" The tickler sheet was reviewed to show the correct T$ limits, The memorandum regarding surveillances was also reviewed. This item is identified as follows: 50-424/ LIV 87-60-03 " Failure to Adequately Perform reovired TS Surveillance to Verify compliance with TS 3.1.2.6.b - LER87-42" (r) *50-424/87-43, Rev 0 " Improper Performance of Containment Pressure Surveillance Due to Personnel Error" Procedure 14000-1 was reviewed to verify that the computer point was included in the procedure. This item is identified as follows: 50-424/ LIV 87-60-04 " Failure to Adecuately Perform reovired TS Surveillance to Verify compliance with TS 3.6.1.4 - > LER87-43" (s) 50-424/87-46, Rev 0 " Waste Gas Decay Tank Not Sampled Within Technical Specifications Time Limit" The memorandum regarding surveillances was reviewed. Corrective actions include the establishment of fixed time. This item was identified in NRC report 50-424/87-49 as an LIV. (t) *50-424/87-57, Rev 1 " Procedure Deficiency Results in Failure to Trip Overtemperature Delta T Reactor Trip Bistable" This LER describes an event which occurred on August 8, 1987 when the shif t f ailed to place one of four
13 I required bistables in trip. The error was identified on August 9,1987 during a control panel walkdown. T h( root cause was a procedural deficiency in specifying the correct Distables to trip. The inspector noted that tne failure mode con.isted of the p essure instrument drif ting nigh about insper? 40 psi and not a total failure high. At - the
'rs reauest engineering performed a calculation to show t:9 *tect that this pressure drift would have on the setpoint.
This calculation showed that even witn tnis error the setpoint was within the 6.6% tetal allowance. The procedure was reviewed and the corrective actions nave been completed. The inspector also noteo that the LER was submitted late due to an improper review of the deficiency card. Both items above represent violations of NRC requirements where the licensee has met the criteria for no citation, To track these items the following are identified: 50-424/ LIV 87-60-05 " Failure to Place the OTOT Trip Bistables in the Ti to Condition per TS 3.3.1 Item 7 - LER 87-57" and 50-424/ LIV 87-60-06 " Failure to Submit an LER Within 30-Oays Af ter The Discovery of the Event per 10 CFR 50.'3(a)(1) - LER 87-57" 5, Management Meetings (303026) On October 21, 1987, an enforcement conference was held to discuss the results of NRC report 50-424/87-56. On November 9, -1987, a site tour was given to the Director, Office of Nuclear Reactor Regulation (NRR), Thomas Murley and the Associate Director for Intpection & Technical Assessiant, Richard Starostecki by the resident inspectors. licensee. The Following the tour, two meetings were conducted with the first meeting was held with the Unit 1 operations personnel and the s;2and meeting was held with the Unit 2 construction personnel, On November 10, 1987, the fourth onsite meeting with the licensee was held regarding the performance of the unit.
VECP-FSAR-9 {A A local sampling point is provided for verifying the solution concentration before transferring it out of the tank. The tank is provided with an agitator to improve mixing during batching (,"l operations and a steam jacket for heating the boric acid solution. 9.3.4.1.2.5.14 Chemical Mixing Tank. The chemical mixing tank is used primarily in the preparation of caustic solutions for C. . ,* , pH control, hydrazine solution for oxygen scavenging, and chemicals for corrosion product cxidation during a refueling shutdown. 9.3.4.1.2.5.15 Chiller Surge Tank. The chiller surge tank handles the thermal expansion and contraction of the water in the chiller loop. The surge volume in the tank also acts as a thermal buffer for the chiller. In addition, this tank can provide a holdup should there be a leak in the chiller heat exchanger. The fluid level in the tank is monitored with level indication and high- and low-level alarms provided on the main control board. (m 3 9.3.4.1.2.5.16 Mixed Bed Demineralizers. Two flushable mixed bed demineralizers assist in maintaining reactor coolant purity. A lithium-form cation resin and hydroxyl-form anion resin are charged into the demineralizern. The anion resin is converted to the borate form in operation. Both types of resin remove fission and corresion products, The resin bed is designed to reduce the concentration of ionic isotopes in the purification stream, except for cesium, yttrium, and molybdenum, by a minimum factor of 10. Each demineralizer has more than sufficient capacity for one core cycle with 1 percent of the rated core thermal power being generated by defective fuel rods. One demineralizer is C normally in service with the other in standby. A temperature sensor monitors the temperature of the letdown flow downstream uf the letdown heat exchanger. If the letdown temperature exceeds the maximum allowable resin operating temperature gapproximately 140'F), a three-way valve is (* automatically actuated so that the flow bypasses the demineralizers. Tempetature indication and high alarm are provided on the main centrol board. The air-op'-ated three-way valve failure mode directs flow to the volume control tank, f ( 9.3.4-21
_ _ _ = _ - .- - .-- -. . - Nov 14 '59 13:04 G T Wi 4 P.2 GP 14649 Westinghoues . Inorgy Systems W * * ** Bactric Corporation " ' * " " NPwmfwe umem November 14, 1989
. NS 0PLS 0PL 189 553 Mr. L. K. M: Coy Vice President, Nuclear Vogtle Project Georgia Power Company P.O. Box 1295 Birmingham, Alabama 35201 i V0GTLE ELECTRIC GENERATING PLANT UNITS 1 AND 2 Raron Dilution Analvans in Madas Eb and 6 Dear Mr. McCoy Westinghouse has completed the analyses to support the addition of a non borated chemical solutiot, to the RCS during shutdown modes with the conservative assumstion that the loops are not filled. This procedura results in a dilution of tto RCS boron concentration and has been analyzed with respect to the boron dilution transient presented in FSAR 15.4.8. The attached safety evaluation (SECi. 89 943 provides the bases for the conclusion that this modification does not i volve an unreviewed safety question. Attachment A to l- the safety evaluation provides the reconsnanded FSAR changes while Attachment B provides the recommended th hnical specification changes and the accompanying significant hazards evaluation.
Reanalysis of the boron dilution event was necessary since dilution in Modes 5b (cold shutdown, loops not filled !- to precluding such an event by ve)rtand 6 (refueling)lves ing certain va to be closed.had The not bee results demonstrate that the Standa Review Plan (SRP) acceptance criteria for fifteen minutes in Mode Ib and thirty minutes in Mode 6 for operator action time between the high flux at shutdown alarm and criticality are met. In Mode Ib, assuming a nocinal dilution flow rate of 3.5 gpa results in a calculated operator action time of 100.47 minutes. The maximum acceptable ! dilution flow rate for Mode Ib is calculated to be 23.1 gps, which results in an operator action time of 15.22 minutes. For Mode 6, assuming a 3.5 gpm dilution flow rate'results in an operator action time of 377.37 minutes and a i l maximum acceptable flow rate calculated as 44.2 gpm with a resulting 30.54 minutes for operator action. l. t
.o NOV 84 '59 13:56 WEC-CAST 4 S P.3 Based upon these results; it is concluded that the chemical addition to the RCS during Modes 5b and 6 as defined above does not violate the licensing hatit acceptance criteria for a bcron dilution event.
Please take a few minutes to complete and raturn the attached quality survey form for this product. If you have any questions or comnents, please centset the undersigned. Very truly yours, WESTINGHOUSE E TRIC CORPORATION
'3 l cQ L. Tain, Mentger g[gg outhern Comptny Projects S. 01Tomaso/
Attachments cc: C. K. McCoy IL, 1A J. A. Bailey IL, IA NORMS (Vogtle Site IL, 1A G. L. Greenwood IL), 1A G. Bockhold, Jr. IL, IA P. D. Rushton IL, IA R. Odom ll, 1A (Vogtle Site) J. Aufdenkampe IL, IA (Vogtle Site) J. Stringfellow IL,1A l [ l
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, 1 : FROM8 WEST /FOCUSeSET/ WOO .T0!GA PWR CO 424354331 ' NOV 13 1989 3:33PM P . 04 - i SECL $9.g43 :
Customer Reference No(s). ELV.00e10 Vsstinghouse Reference No(s). AT-76E10 {' WESTINGHOUSE NUCLEAR SAFETY- 4 SAFETY EVALUATION CHECK LIST
!) NUCLEAR PLANT (S) : Vaatle Unita 1-and 2 ,
- 2) ' SUBJECT (TITLE): Partodic knina of CVct Valves in tenden 5 and 6 for Chemistry Control
- 3) The written safety evaluation of the revised procedure, design change or i modification required by 10CFR50.5g (b) has been prepared to the extent required and is attached. If a safety evaluation-is not required or is incomplete for_ any reason, explain on Page 2.
; Parts A and t-of this Safety Evaluation Check List arc to be completed only on the basis of the safety evaluation perfonned.
- CHECKLIST.PARTA10CFR50.59(a)(1) ;
, Yes,.)L, Nof A change-to the plant'as described in the FSARt1
. Yes.2_ No No l AAchange to procedures as described in the-FSARt
. -Yes test or experiment:not described in the FSARf
. Yes.J. No L A change to tho' plant- technical specifications?
- (See note on Page 2.):
- 4) CHECK LIST.'- Part 8 10CFR60.59(a)(1) (Justification for Part 8 answers must be included on Page 1.)
(4.1)- Yes_,_,, No L Will the probability of an accident previously
- evaluated in the FSAR be increased?
(4.2) Yes; LN o.,1,;1 Will: the consequences' of an accident previously-evaluated:in the FSAR be increasedt_ _ f(4.3)!Yes_,,_, No.l., May the= possibility of an accident which is different' . than any already evaluated in the FSAR be created? (4.4) Yes_ - No.l Will-the probability.of a malfunction of equi ment -- important to safety previously evaluated in tie FSAR be
.increasedt (4.5) Yes_ No.l_ - Will- the consequences of-a malfunction of equipment .
_ iaportant to safety previously evaluated in the FSAR'be increased?.
-(4.6);Yes_ - No.l., May the possibility of a malfunction of equipment important to safety different than any-alrosdy evaluated in the FSAR be createdt _
(4.7) Yes No L.- Will the margin of safety as defined in the bases to any technica specifications be reduced?- Page 1 l
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NOV 14 'c9 13857 ICC-CAST 405A P.4 SECL 89 943 NOTE 5:- If the answers to any of-the above under 5) AEMARKS and explain below. questions are unknown, indicate If the answers to any of the above cannot be answered in the negative,based questions on theinwritten Part Asafety 3.4 or Part I evaluation, the chante review would require an application for license ! amendinent as required by 10CFR50.59(c) and submitted to the NRC pursuant to 10CFR50.90.
- 5) REMARKS:
The follow [ng sunusarizes the justification based upon the written safety evaluation , for answers given'in Part A 3.4 and Part B of this safety evaluation check list: The proposed modification ir 21ves periodic opening of valves 176 and 177 to allow for chemical additt n for water chemistry control. The effects of this change are evaluated for boron dilution concerns. FSAR and i
~
technical specification changes to implement this change are included. I Reference to documenta containing written safety evaluation:
~
FolLFIAR UPDAIE i Section 15.4 a _ Pages:Al' Tables: 18.4.6 1 Figures: - 9.1.4 9.: l.47 Reason for/ Description of Change To accura",al" rar act the unn of valvan 176 and 177 far narindie enanine which wir m' low der chanica' addition for water chanintry contral.
- 6) SAFETY EVALUATION APPROVAL-LADDER:
6.1)Preparedby(Nuclearsafety): Nd. M Date: n/M/M
- 5. C. Difossaso '
6.2) Nuclear _SafetyGroupManager: 7- " Date # M' R. J. $terd s
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9 FROM WEST / FOCUS / SET /uGG- T0 IGA PWR CO 48455453&O NOv ' 13, 190 : 3:33PM P.06 SECT. 89 943 Vogtle Units 1 and 2 Safety Evaluation in Support of
- Periodic OpeninE of CVCS-Valves 176 and 177 for Controlled them. cal Addition in Modes Sb and 6 -3.0 RACKGR00@
and 6 It is necessary during Nodes 5b (loops not filled, cold shutdown)ish this,
-(refueling) to periodically adjust-the RCS chemistry. To accompl Georgia Power is proposing to add chemicals to the RCS via the reactor makGp water storage tank discharge path through the chemical mixing tan h -Valves 176 and 177 in the CVCS must be opened in order for this addtfienpathtobeused.;Theextentofthechemicaladditionis est4 dated to be for no longer then.30 minutes at a time for a maximum of
- 10 times throughout the Mode 5b and 6 duration. The maximum flow rate thrcugh this line under any condition with the' valves open is calculated to be less than 3.5 gpa, which is identified in FSAR 15.4.6.2.1.2 as Initiator 3 for a potential boron dilution path.
The? injection-of a non borated solution into the RCS'for chemistry control during shutdown modes results in a dilution of-the core boron concentration. The current boron dilution analysis for Vogtle-is .- presented in FSAR 15.4.6. Dilution flow paths have been identified for-Modes 3, .4, and la (loops-filledT configurations.- The analyses are iperformed:in:accordance with NURkG 0800, Standard Review Plan (SRP)between 15.4.6, to demonstrate that at -least fifteen minutes.is available,- the high flux at shutdown alarm and complete loss of shutdown margin (criticality), for operator action time to terminate the dilution flow. Therefore, boron dilution analyses have been performed which verify that the anticipated dilution flow rates will still permit adeqJate time for
. operator action in-accordance with the acceptance criteria. NRC approval of this analysis is-provided in NUREG-1137 Supplement 1. Vogtle Units.1 and 2 Safety Evaluation Report.- Section 15.4.6. However, analyses do not - -
extst for dilution flow in Modes 56 or 6. Instead, boron dilution is
' precluded by verifying that the possible dilution flow paths-are closed and secured in position in accordance with Technical Specifications L
f 3/4.4.1.4.2-and 3/4.9.1. In order to verify that chemical- addition in Modes 5biand 6 will not violate the acceptance criteria, specific: analyses were performed to demonstrate adequate operator action time is.available. l Note that-the acceptance criteria. identified in SRP 15.4.6'for Node 6 ! boron dilution is thirty minutes for operator action time. Page 3 L
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*f FROMfWEST/ FOCUS / SET /WOG To:GA PWR CO'4845545310 NOV 13 1999 3:34pp , gp SECL 89 943 2.0 LICENSING AP.PA0ACH AND SCOPE The purpose:of this safety evaluation is to su> port the FSAR changes and evaluate the: proposed change in accordance wit) the criteria specified_in 10CFR 50.59 so that.the basis for the conclusion that the chemical addition does not involve an-unreviewed safety question is identified.
The assum>tions and criteria presented above have been used as the bases upon whici- the Modes 5b and 6 boron dilution analyses were perfomed.
- Such a change in plant operating procedures will be reflected in the FSAR as well as-the: technical specifications...Therefore, Attachment A to this safety evaluation identifies the recommended FSAR changes. As it has been ',
determined that modifications to the technical: specifications.are required t to implement' this change, submittal to the NRC for review and approval is required.- Attachment B constitutes the significant hazards evaluation in accordance with 10CFR 50.92 and the associated recommended technical
-specification changes.
During Mode 6, reactivity conditions of the RCS must be maintained at the
.most restrictive of the two 2CS boron concentration above 2000 ppm or a
' K.gf of- 0.95 or less por Technical S >ecification~ 3.9.1 Technical Specification 3.1.1.2 controls varia>1e shutdown margin = in Mode 5. These .
boron requirements have not changed as a result of t to Modes 5b and 6 , boron dilution analyses. - Rather, the analyses have been performed such that:they adhere to and.are in conformance with these existing > requirements.' Also,; the Modes 5b and 6 analyses have assumed the l operability of the 51gh flux at shutdown alarm in these modes, with a flux L Lmultiplier alarm s.tpoint of 2.3. This setpoint is defined in Technical E Specification Table 4.31 Note 9.and is consistent with the Modes 3, 4 and 5a analyses. - The scope of this evaluation will address the effect' of the Modes bb and 6 i-
~ boron dilution event on each of the disci lines within Westinghouse l: cognisance.as-discussed in detail in the ellowing section. ,
3.0- EVAllJAT10MS c 3.1 - :Non LOCA Accident Analyses E .. The injection-of non borated chemical solution into:the RCS for coolant L chemistry control results in a dilution of the core boron concentration. u A prolonged and unmonitored addition of the non-borated-solution can be
- postulated to eventually-result in.the complete losk of shutdown margin .
The current boron dilution analysis- for.V tie is presented in FSAR lSection 15.4.6. Dilution flow paths'have n identified for Modes 3,s4, and Sa (loops filled) configurations.- The analyses were perfomed in accordance with:NUREG 0000, Standard Review Plan (SRP) 15.4.6, to demonstrate that at least 15 minutes is available,' between an alarm and complete. loss of: shutdown-margin, for operator action time to terminate-the dilution flow.-- Por the FSAR. boron dilution in Modes 5b and 6 is-currently administrative 1y precluded by verifying that possible dilution flow-paths are tzolated and the. appropriate valves are secured in position in accordance with. Technical Specifications 3/4.4.1.4.2 and 3/4/.9.1.- Therefore, calculation of operator action time in Modes 5b and 6 is not currently required for. the FSAR. owe a -_ __ , ,
Fro pyEST/ FOCUS / SET /WOG
~
TolGA FVQ CO 40435433M e 13, 199@ 3135PM A.28 SECL 89.g43 Analysis of the boron dilution ' event for Mode 5b and 6 with a minimum cold
-drained reactor vessel volume was performed assuming a maximum dilution flow rate of 3.5 gpa to determine the minimum operator action time. This flow rate is the maximum that can be achieved via the proposed flow path unde" any operating condition. In addition to using the minimum cold -drained reactor vessel . volume, the active RCS volume was further minimized by making the following assumptions: only one residual heat removal train-is in operation, miniflow and bypass lines are considered empty, and no reactor coolant loop volumes are assumed. Note that the analyses also assume the operability of the high flux at shutdown alarm such that the instrumentation reliably annunciates a neutron flux level which is 2.3 times greater than that occurring at the initiation of the boron dilution event.
The results of the analyses demonstrate that for a dilution flow rate of 3.5 gpm or less there is sufficient-operator action time available to terminate the flow after the high flux at shutdown alam. The SRP acceptance criteria of fifteen minutes in Mode 5b and thirty minutes in Mode 6 for minimum operator action time is met and exceeded. No other non LOCA safety analysis assumptions, methods or results are affected by the proposed procedure. 3.2 Mechanical Equipment Evaluation The addition of a non borated solution to the RCS via the chemical mixing tank will be performed in order to adjust water chemistry within the current requirements. Also, since the boron requirements will not change, the proposed change will not involve the creation of a new chemical environment to which the components will be exposed. Therefore, the performance and qualification of mechanical equipment will not be affected
- as 4
- result of this modification.
3.3 Fluid Systems Perfomance Evaluation The two plant fluid systems involved with this change are the reactor makeup water s stem ( M S, FSAR 9.2.7) and the chemical and volume control
. system (CVCS.- SAR 9.3.4)
The function of the MS to supply degassified and dominera11 red water to the RCS is not altered as a resuit-of this modification. Also, the makeup water chemistry specifications are not changed, therefore the performance requirements and capacity of the RMWS will not be challenged or exceeded. Similarly, the function of the CVCS to control RCS chemistry is not . altered. The addition of chemicals to the RCS in Modes 5b and 6 via the RMWS is in accordance with the procedure for addition of chemicals to maintain water quality-as already described in FSAR 9.3.4.1.2.2. L Therefore..no new system alignments or perfomance criteria are imposed on E l the CVCS as a result of this change.
.Page 5
FROMWEST/ FOCUS / SET /UDG TO GA PUR CO 4045543314 NOV 13 1989 3:35pm p,gg SECL 69 943 3.4 Instrumentation and Control Evaluation The Mode 5b and 6 boron dilution analyses assume the operability of the high flux at shutdown alarm in these modes, which receives input from the source range neutron flux monitors. In order to assume the high flux at shutdown alarm, which indicates to the operator that manual action to terminato dilution flow is required, this function must be operable during Modes 5b and 6. Given that the high flux at shutdown 11am function is operable, the perfomance requirements for the equipment and channels to detect and alam for an increasing flux condition are not changed for . service in these modes. Qualification of the source range detectors remains valie, .s documented in FSAR Table 3.11.N.1-1. The flux multiplier setpoint for the alarm for all modes is consistent and remains at 2.3. 3.5 LOCA and LOCA related Accident Evaluation Chemical addition for water chemistry control in Modes 5b and 6 is not modelled in the LOCA and LOCA related accidents. Sinco all applicable
-technical specifications for RCS boron concentration remain unchanged and will continue to be met by surveillance, there is no adverse effect on the following analyses and the conclusions presented in the FSAR remain bounding for small and large break LOCA, LOCA hydraulic forces, rod steam ger. orator ejection tube rupture mass andreleases, post-LOCA hot leg switchover to prevent long tem coreprec boron cooling,ipitation.
3.6 Containment Peak Pressure / Temperature Evaluation containment analyses are limiting for mass and energy releases as a result of a steam itne break or large break LOCA. Due to the fact that there is no effect on steam line breat or LOCA mass and energy releases as a result _ of this change, the conclusions and limiting cases presented in the FSAR remain bounding. 4.0 COELUSION Using the analyses and evaluations presented above, the bases u)on which specific responses to the questions presented in Section 4 of tto checklist can be addressed. The addition of a non borated solution during Modes 5b and 6 does not involve an unreviewed safety question as determined in the following discussion.
- 1. This chemical addition procedure does not increase the probability of an accident previously evaluated in the FSAR. No new perfomance requirements or alignments are being imposed on the CVCS or RMWS such that any design criteria will be exceeded. The recommended chemistry guidelines will continue to be adhered to, precluding the creation of an adverse chemical environment which may prematurely affect component performance. This dilution flow path, although administratively Page 6-
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__ _ 7
~.FROMitKST/ FOCUS / SET /WOG TO 0A PWR CO 484594 W eam yp gg I
SECL 8g 943
- precluded in Modest 5b and 6. _was previously considered for Modes 3, 4
-5 and 6 in Chapter 15 of the FSAR. The classification of the boron dilution event continues to be an ANS condition II incident, one of moderate frequency. - Other boron-dilution flow paths will continue to '
be precluded by the technical-specifications. 2.- The consequences of an accident previously evaluated in the FSAR are ; not increased due to this chemical addition procedure. - The-results ' presented in the FSAR-for the Modes 3. 4 and la dilution events remain valid. Boron djlution as a result of chemical addition in Modes 5b and.6 will not create more severe dose consequences. 3.- This chemical addition procedure does not create the possibility of an L ~ accident which is different than any already evaluated in the FSAR. H Boron dilution configurations in Modes 5b and 6 have been previously ' considered and evaluated in the FSAR. The conclusion was to keep-the flow paths isolated so that no dilution flow was possible. In order to support .the chemical addition procedure,- an alternative approach.- which utilized specific analyses that=are bounding for the injection - path configuration, was used. The results indicate that the required operator action time is available.-given the expected dilution flow rates. Therefore. -the Modes 5b and 6 boron dilution analyses meet the Plant Vogtle licensine basis acceptance criteria for this event. e Other boron dilution flow paths will continue to' be precluded by the E technical specifications. 4.- This chemical addition procedure will not increase the probability of a malf"nction of equipment important to safety. As stated previously. r
. component and system performance will not be adversely affected and no new system alignments-are-required which will challenge the-CVCS and p
RMWS design bases.
- 5. . The chemical addition procedure will not increase the consequer.cos of a malfunction of equipment-important-_to safety previously evaluated in the FSAR. - The chemical addition procedure will not degrade-any-system L
J performance such that its malfunction will adversely affect.another transient. Therefore, no more severe dose consequances will result due=to this procedure.- 4
- 6. The chemical addition procedure _will not create the possibility of:a
- ; malfunction of equipment-important to safety different than any_
already evaluated in the FSAR, All original design.and wrformance criteria continue'to be-met for.the CVCS and Rmf5 such tiat there is. no new failure mode expected as a result of this procedure. The chemical addition procedure has not introduced a new limiting single failure for these systems. L Page 7
, , _ ., , , , _. , , - _ _ , ._s 4._,
Fb. WST/ FOCUS /E/t,03 Tag M m ggg g SECL 89 943
- 7. The margin of safety in the plant licensing basis for boron dilution is defined as operator action time between-the high flux at shutdown criticality).- The high flux at alarm shutdown alarm setpoint defined in (Technical Specification Table 4.31 and loss of shutdown margin Note 9 is 2.3. For Mode 5b, the operator action acceptance criteria as defined.in SRP 15.4.6 is fifteen minutes and for Mode 6 SRP 15.4.6 defines the acceptance criteria as thirty minutes. The analysis criteria is designed to provide sufficient time for the operator to mitigate the event and prevent the complete loss of shutdown margin.
Prevention of t,he loss of shutdown margin entures that all ANS Condition ll . criteria are met. Therefore, ths margin of safety is not reduced. It can therefore be concluded that the addition of a non borated chemical mixture throtSh the flow paths provided by valves 176 and 177 in the CVCS during Modes bb and 6 does not involve an unreviewed safety question as defined in 10 CFR 50.59.
+
1 Page 8
r FROMtLESTd L..w/ SET /UDG TO8GA PWR CC 40455453ad Nov a3, 1999 3:37pn p,g3 SECT. 89 943 ATTACHNENT A
^
RECOMMENDED F$AR CHANGES
.- . . . - - - . . - . - - -- - . - - - . _ - - ~ . _ . . - . . . . . .
i Nov 14 *it 15 :.. ' .AST 405A P . 2, l .
.n TEGF-FSAR 9
]
materials and water chemistry of berated water / stainless steel /siroonium/Inconal systems. In addities, lithium-7 is produoed La the sere region due to arradiation of the dissolved beren in the seelant. I The eensentration of 11thium=7 La the RCS is maintained within the range 0.3 to 2.5 pas as lithium for pE : (See table 5.3.5-3.) If the eencontraties eentrol. eneeeds this range, as it may durias the early stages : of a sore eyele, the eVCS desimeralisers are employed to-remove essese lithium. Stase the enount of lithium ) ' to be removed is small and its buildup een be readily ealculated,_the flow through the domineraliters is not l required to be full letdown flow. If the seneentration " of Lithium-? is below the specified limits, lithium hydreside can be introduced Late the RCS via the sharging flow. The solution is ared in the i
- laboratory and poured late the sal mining tank.
Roaster' makeup water is ther used te flush the salutten
- to the sustion manifold of W sharging pumps.
- s. carven control During plant startup from the sold sendition, hydrastas to esployed to scavenge saygen. The hydrasine solution I
l- is introduced into the RCs in the amaner described I above for the pH esatrei agent. Bydrastae is met meraally esployed easept during sterM from the sold , tthh3 h During moraal plant operation, hydrogen utseelved in the remeter seelant is used to esattel and eenvenge esFgen produced by redielysis of water la the sore region. A suffittent partial pressure of hydrogen is maintained in the volume sontrol teak such that the aermal opetating range of 30-40 em (BTF) E d hg I O 8 to obtained. Apressure,esatrolvalvemainYatasI
=4mi== pressure of 18 to 20 peig ta the vapor space of the volume sentrol tank. This valve saa be adjusted to provide the eerrest equilibrium h seamentration. Eydrogen is suppl ed tea the hydrogen aantield in the aus111ary was system.
l C. Roseter.Coelaat Purification ) i Miaed bed desimeralisers are provided la the letdown line to provide cleanup of the letdown flow. The dominera11aers remove ionic serresien products and l I
. 9.3.4-7
1
~
..
- NCY l'd '49151ii !EC-CAST 42tSU.+
. 4 -
- S. J . .: '
. ..*. .. p.3 l
l VEOF-FSAR-15 ; 15.4.4 CEDt! CAL AND VOLUMI CONTROL SYSTEN MALyUNCTICH THAT RESULTS IN A DECREASE IN TME SORON CONCENTRAT10N IW i Tus RsAcroa COOLANT l (I 15.4.5.1 Man 1MiaA11an_of Causes and Aasident Amatrintien Beset.ivity saa be added to the sore by feeding primary grade water late the reaeter seelant system (RCS) via the chemical and
/h volume sentrol system (CVC5). Beren dilutica is a manual (F operatlea under strict administrative sentrols with precedures calling for a limit en the rate and duratten of dilution. A berie said blend system is provided to permit the operator to matek the borea sessentration of remeter seelant makeup water during moraal sharging to that in the Ecs. The Cves is designed to-limit the potential rate of diluties to a value which, after Ladioation through alayas and instrumentation, provides the '
operater suffistent time to sorrect the situation in a safe and orderly manner. The opening of the primary water makeup eentrol. valve provides makeup to the RCS which saa dilute the reacter seelant. l Inadvertant dilution from this source saa he readily terminated by sleeing the esatrol valve._ In order for askeup water to be ( added to the RCS at pressure, at least one sharging pump must be running in addition.to a reacter askeup water pump. Normally, only one primary grade water supply pump is operating while the other is en standby. i the berie acid from the berie acid tank is lpleaded with primary grade water at the mining tee, and the sempesitten in determined by the preset flowrates of boric acid and primary grade water en the sentrol. heard. Informaties sa the status of the remeter sosiant makeup As sentinuously available to the operator. Lights are provided on the sentrol board to indicate e.he operating eenditien of the
-{g pueps la the CTCS. Alarms are astusted to warn the operator if marie acid er desimeralleed water flowtateu deviate from preset vehee as a result of system malfunt: tiers.
This event is classified as an Aasrican Muslear Society condition !! insident (an insident of aederate frequency) as - (y defined La subeestion 15.0.1. 1 ( - l
. . . . . . - . .- .~.~ -.--_.- _ _ - .-._._._ _ - _ . -
t@/ 14 'E9 13:57 WC-EAST 405A P.5 l i
~ '
~ VECF-FSAR-15 i 15.4.4.2 Am=1vais of Effects ==d Canaamuences 0
15.4.4.2.1 Nethod of Analysis
- k To sever all phases of the plant operaties, boren dilution during refueling startup, sold shutdown, hot standby, and power operation are sea,sidered in this analysis.
44 h 4.6.2.1.1- un el . roues mer B This aos t h* l is pr y rative trols .ioelate 8 from potent seurse e rated er. alves , 174, 177 183 in CVCs will- locked o ed er i ted by r 1 of conte air er el rieal- su , refueli perations. se valve ill hise fle the whiek d allow ated make water-to ach LC5. which required d av refue will meat stor supp11 rem the re eling'wa storav *'a=6 hv >
*- ' 1 _
#-d safety ajeetten Y =-
~
15.4.6.2.1.'2 undown. Een standby, ==d g Et h.:
-ana ye s was per erses to eva.uate beren )
dLution events duriaq sold shutdown,- het shutdown, and het standby. . Failure modes and effects analysis, human errer analysle,Eand event tree analysis ware used to identify eredible beren dilution initiators and to evaluate the plant respcase. to these events. For the tattiators identified, time intoavais fres alars to less of shutdown sarvin were salaulated to ' determine the length of time available:for operator reopease. These-esiculations depended en dilution flowrates, borea sensentrations, and Roaster Coolant System volumes specifts to the event and mode of operation. The teshaique nedeled realistie. plant senditions and responses, ineluding both seshanteal isilure and human errors.- The analysis identified four events which were considered to be the most likely initiators:
- 1. Domineraliser outlet isolation valve open during resia '
- flushing.
- 2. Valve 226 open following ETRS desineraliser flushing L operation.
- 3. Fail,ure te soeure chemical eddition.
- 4. Berie acid flew control valve (IV-110A) fails closed 's y during make-up. /
15.4.6-2 , _
NOV 14 '99 13:56 EC-CAST 405A P.6 INSERT A 15.4.8.t.1.1 hii rtaa auc h esfuelina. A very small amount of unborated chemical aslut' en a alleued to enter the RC8 for water chasistry quality control. The dilutten flew path is provided by opening CYC8 valves 174 and 177. The manteus flow rate possible throush this flow path is less than 3.5 which is approximately 35 of the limiting flew rate considered in the anal is for Modes 3 4 and la. Any other chemical maksaa solution which is requ red during refue, ling will be borated water supplied free the refueling water storage tank by thi law head safety injection pumps. Valves 175 and 183 in the CVCS will be locked closed er isolated by removal of control air er electrical supely during refueling operattens. These valves will block additional flew water in excess of 3.5 spe fe reach the RCS.hs which could allaw unberated che e i e l l
- . - - . -- - , - . , _, a , _ . . - - . .
P 7' NOV 14 '89 13:59 LCC EAST'405A y.h - . h VEOP-FSAR-15 Initiati >y was found to be the most limit 1hg event for modes 3, i 4, andJr. The' parameters used in the calculation of time l available for e rator tasponse are listed in tabla 15.4.6-1. ! Conservative va ues of heren worth (pen / ppa), as a function of l (-) RCS beten eeneantration, were assumed in the analysis. Since the active volumes considered are se small in cold shutdown.with the reactor coolant loops drained, it was determined that the ease valves locked out in refueling would
-) loops are need to be desiaed looked saa. (out pace.grath if.4 b.1.
in sold shutd wn l.I). when the reactor coolant l 15.4.8.2.1.3 Dilution Durins full Power omeration. Insluatna Etartum. 15.4.4.2.1.3.1 Dilution During stantup. Conditions at startup, require the resoker to have available at least 1.30-percent ek/k abutdown as in. The maximum boren consentration required
-to meet this shu margin is senservatively estimated to be '
1704 ppa (Unit 1), and 1692 ppa (Unit 2). The following conditions are assumed for an uncontrolled heron dilution during startup A. Dilution flow is assumed to be the combined capacity of the two primary water makeup pumps (approximately 242 gal /ain).
- 3. A minimum water volume,- 9757 fts (Unit 1) and.
9972 fts -(Unit 2) La the roastor coolant system is used. This volume corresponds to the active volume of the RCs minus the pressuriser volume.
- 15.4.4.2.1.3.3 Dilution During Power Operation. During power operation, the plant may be operated two ways, under manual (b operator sentrol er under automatic Tape /M eentrol. While the L (, plant is in manum 1 sentrol, the dilutish u t is assumed to be a ,
marisus-of 242 gal /ain, which 12 the sombined capacity of the two primary water askeup pumpe. While in automatic control, the dilution. flow is limited by the maximum letdown flow (appresiaately 125 gal / lain). h -Conditions at power operation require the reactor to have available.at least 1.30-percent Ak/k shutdown margin. The maximum boren sensentration required to meet this shutdown margin is very senservatively estimated to be 1366 ppm (Unit 1) and 1704 ppa (Unit 2) . ( i _, _ . . _ . _ _ _ . _ .-n-
e tCV 14 899 13:5:- kEC-EAST 405A P,8
\
l INSERT B In Mode 5b addition of(mid smallloop operatloa), amounts InlLlatur of unwrated 3 was also chemical considered s91ution into the to RC5allow for the watar chemistry control. The maximum flow rate sossible through this flow path is approximately 3% of-that associated with tie limiting flow path for Modes 3, 4 and la.
l Nov 14 '59 14 02 WEC-EAST 405A P.9 VECP-r5AR-15 A minimum water volume of 9972.2 f t8 in the RCS is used. This volume corresponds to the active volume of the Ac5 minus the ; pressuriser' volume. 15.4.4.2.2 Results The calculated sequence of events is shown in ** hie 13.4.1=1. ,
$n64r4 U i
vaMM
- b 18.4.6.2.2.2 Dilution ">arine cold shutdown. For dilution during. cold shutdown, the Technical spectrientions provide the
,. required shutdown margin as a function of RCS baron
- soncentration. The specified shutdown. margin ensures that the rater has 15 min from the time of-the high fium at shutdown-gaaretothetotallossofshutdownmargin y l'5. 4. 4. 2. 2.'2 . Dilution Durf.nz Eat Sta ahv ad Met Shutdown. For -
dilution- during het staney anc, hot s:sutsewn, the Technical
-Specifications provide the-required shutdown margin as a function of RCS heren eensentration. The specified shutdown margin ensures that the operator has 18 min from the time eI the high flum at shutdown alars to the total less of shutdown margin.
J [ 15.4.4.2.2.4 unplanned appreseT Q & h ina Startup.
"e crithoality or dilution during power In the event of an escalation while in the startup mode, the operator is alerted to i an unplanned dilution by a reactor trip at the power-range neutron flun high, low setpoint. After remoter trip there is at least 19.0 min (Unit 1), and 17.25 min (Unit 2) for operator 3
- action prior to less of shutdown margin. I .1 i
15.4.4.2.2.5 Dilution Durins Power Cneration. During i full-power operation with the roastor in manual control, the operator is alerted te-an uncontrolled dilution by an % overtesgerature AT remoter trip. At least 16.9 min (Unit 1), I .i aos le.a, min (Unit 2) are available from the trip for operator I a tion prior to lose of shutdown margin. 1_ __ . , _ _ - . _ .- .- --
tCV 14 '99 14101 ICC-CAST 4054 P,10 INSERT C lince the maximus, flow rate associated with the available dilution flow paths in Mode 8 is very small the total time from initiation of event to the eventual complete loss o,f shutdown margin is significantly large compared to the minimum required operator action t'me. Therefore, a considerable amount of time is available for the operator to initiate and teminate procedures for RCS water chemistry adjustments before potential loss of shutdown becomes a concern. backroundAdditionally, it is shown that 'echnical the specification shutdown marginasswaint the availability of requirement for Mode 6 is sufficient to ensure that the o nrator has 30 minutes from the time of alarm to terminate the dilution befors ssutdown margin is lost.
1 Nov 14 'G914:01 EC-EAST 405A P.11-I INSERT D due to Iaitiator 4 which is the limiting case for Mode la. The same condition as specified for Mode 4 in paragraph 15.4.6.t.2.1 applies for Mode 5b due to Initiator 3. F L
a 14 .ss 14:01 d e-tAsT 'asA 4 ' P.12 - - VEOP-FRAR-15 During full-power operation with the reactor in automatic control, the insertion h operater la alerted to an uncontrolled reactivity the red insertion limit alarms. At least 36.8 n;,n (
. .)
-limit alarm until a less of shutdown margin occurs.are availab e for operat 15.4.5.3 Conclusions
<the**- results presented above show that adequate time is available O *
- flow. - Fo>llowing termination a= 2tr * * * *a ' 'at=*i -
of the dilut'ien flow, tne operator can-initiate reboration to recover the shutdown margin. s l-C . 0434Y 15.4.A-5 _ _ _ . _ __ -
NOV '14 *C9 14803 WCd-CAST 40 % - - . . . . . - . .. ' '<.* .. . P.13 . . 1
~~
. VEGF-FSAR-15 TAar2 15. 4. 4-1 PARAMETERS @
(I Dilution Flowrntes: Initiator Flowrate fval/ min) 1 63 (I 2 100 3 3.5 4 110 Volumes: Hgdg volume (ft') yolume (ea1) 3, 4 9972 74593
- ( Sa-(filled) 5239 39188 ,
Sh (drAWad 300 2I800 (,- (drentd) 3%o 2.s880 l
. t L
O '
.*. bswd r< fed ta du re ad* r ve"* / '* * /^^ /*"/ **
L &. md pie e. .f A ne ulu. LO l
- a. See appendix 153 for reload cycles.
- . .. .. .-. . . - = . . .. . .. ..
FDiD-UY - S/ SET 6 70tGA PA CO 4845545314 . c 13, 1999 3:3 p . ,, 3 SECL 89 943 S ATTACHMENT 8-SIGNIFICANT HAZARDS EVALUATION' AND - RECOMENDED TECHNICAL SPECIFICATION CHANGES
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1FROMi(ES7er%US/SEN- ,yoiM PWR CC 4049345314 NOV 13 19e9 , 3i3gpn _- p.16 SECL 89 943 , VNTLE ELECTRIC GENERATING ~ PLANT NRC DOCKETS 50 424, 50-425 0?ERATING LICENSES NPF-68, NPF 81
. REVISION TO TECHNICAL SPECIFICATIONS-MODES $8 AND 6 BORON DILUTION 10 CFR 50.92 EVALUAT10N' Pursuant to 10 CFR 50.92, each application'for amendment to an operating license must-be reviewed to1 determine if the proposed change involves a significant hazards consideration. The amendment, as defined below, describing a non-borated chemical addition activity during Modes 5b and 6, has-been reviewed and deemad not to involve significant haaards-consideratiors. The basis for this detamination follows.
Backaround L In order to-provide for~the capability to make non-borated chemical ! additions to.the RCS during Modes $b (loops not filled)- and 6-(refueling) l-' for-' proper water chemistry control, it was necessary to perform boron dilution analyses- for the specific dilution' path to be utiliaed in these modes. The injection of.non-borated water-into the RCS for chemistry control during shutdown' modes results in a dilution of the RCS boron concentration. The current boron dilution analysis for Vogtle'is
- presented in FSAR 15.4.6. Dilution flow-paths during shutdown have been identified for Modes -3, 4, and la (loops filled): configurations.. The analyses are performed in accordance-with NUREG 0400,-Standard Review Plan (SRP),=Section~15.4.6 to demonstrate that at least fifteen minutes-is available, between:the high_ flux at shutdownialarm and complete loss of shutdown margin (criticality),' for operator acd on time to terminate'the dilution flow.- Therefore,' boron dilution analyses have been performed-- .
which verify that-the anticipated' dilution flow rates will-still permit l adequate time for. operator action in-accordance with the' acceptance-criteria. However, analyses do not exist for dilution flow in= Modes 5b or
- 6.- Instead, boron dilution is precluded by verifying that'the possible
~
dilution-flow paths are closed and-secured in position in accordance with-Technical Specifications 3/4.4.1.4'.2 and 3/4.9.1. In order to verify that chemical addition in Modes 56 and'6 will not violate the . acceptance criteria, specific analyses:were performed to demonstrate adequate-operator action time is available. Note that the acceptance criterta L identified in SRP 15.4.6 for Mode 6 boron dilution is 30 minutes for ; k operator action time. 1' l l L l l L
^
l
N IEST/ FOCI 5/SEET4JOO M GA M CD e m m g4g yg 1 SECL 89 943 1Analysis i A review- of the accident analyses-in the Vogtle FSAi has determined that
'the only transient which is affected be this chemics) addition procedure.
is the boron dilution event. Since all applicable technical specifications for RCS boron concentrations will continue to be met by : surveillance and the reconnended RCS chemistry will not be changed, there is rio aciverse effect on any other accident analyses or system or component perfer;4ance.
- During Mode 6 -- reactivity conditions of the RCS must be maintained at the e most restrictive-of the two: RCS boron concentration ~above 2000 ppm or a K.f t of 0.95~ or less per Technical Sacification 3.9.1. Technical L
Specification 3.1.1.1 controls varia>1e shutdown margin in Mode 5. These > boron, requirements-nave not changed as a result of the Modes 5b and 6 boron dilution analyses. Rather, the analyses have been performed such that they adhere to and are in conformance with these existing requirements. Also, the Modes 5b and 6 analyses have assumed the - operability of the high flux at shutdown alam in these modes, with a flux-multiplier alarm setpoint of 1;3. This setpoint is defined in Technical Specification Table' 4.3-1 Nota = 9 and is consistent with the Modes 3, 4 and 5a analyses. . The injection of unborated chemical-solution into the RCS for coolant chemistry control results .in a dilution of the core boron concentration, b A prolonged and unmonitored addition of the:unborated soiution can be postulated to eventually result:in the complete loss of shutdown margin. The current: boron' dilution analysis for Vogtle:is presented in FSAR 4,- Section' 15.4.6. Dilution flow paths have been identified for Modes 3 and Sa (loops filled) configurations. -- The- analyses were performed in-accordance with NUREG 0000, Standard Review Plan (SRP)'15.4.6, to-
' demonstrate that at least fifteen minutes is available,1between an alarm and complete loss of shutdown margin, for operator action time to terminate the' dilution flow. Per the FSAR, boron dilution.in Modes 5b and 6 is currently administrative 1y precluded by verifying that possible:
Ldilution flow paths are isolated.and the appropriate valves-are secured'in position'in accordance with Technical Specifications-3/4.4.1.4.2 and-3/4/.9.1. Therefore, calculation of operator action. time in Modes 5b and 6 is mot currently required for the FSAR. Analris of the boron dilution event for Mode 5b and 6 with a minimum cold-
? drained reactor vessel. volume was performed-assuming'a maximum dilution Eflow. rate of 3.5 gpa to determine she minimum. operator action time. This flow. rate is the maximum that.can be achieved via the proposed flow path e
-under any operating condition. In addition to using the minimum cold idrained' reactor vessel volume,- the. active RCS volume was further minimized j
by making' the following assumptions::only one residual heat- removal train is in operation, miniflow and bypass' lines are considered empty, and no i ( lr ) e q
m _ _ .._____ _ _ _ _. _ _. _ _ , _ _ _ _ _ . . _ NU WESMOC1& SET / WOO 70s rA N 404554214 Nov a iges 3: agpg p.16 SECL 8g g43
- reactor cool' ant loop v61us.ei art assumed. ht; t%et the analyses also assume the. operability of the high flux at shutdown alarm such that the instrumentation retteMy annunciates a neutron flux level which is 2.3 times greater than that occcrring at the initiation of the boren dilution l event. -i The results of the analysis demonstrate that for a dilution flow rate of 3.5 ppm or less there is sufficient operator action the available to terminat the flow after the high flux at shutdown alarm. The SRP acceptance criteria of fifteen minutes in Mode 5b ared thirty minutes in '1 Mode 6 for minimum operator action time is met and exceeded. No other non40CA safety _ analysis assumptions, methods or results are affected by 9 the proposed procedure.
l 1Results: Based on the information presanted above, the following conclusions can be reached with respect to.10 CFR 50.92.
- 1. This chemical addition procedure does not increase the probability of an: accident previously evaluated in the FSAR. No new p rformance .
-requirements or alignments are being imposed on the CV;5 or RMWS such that any design criteria will be exceeded. The-reconnended chemistry
- guidelines'will continue to be adhered to, precluding the creat4on of an adverse chemical ~ environment which may prematurely affect component performance - This dilution flow pathe lthough a administrative 1y.
precluded in Modes Eb.and 4.- was previously considered for Modes 3, 4 5 and-6.in Chapter 15 of the FSAR. The classification of the boron I L M11ution event continues to be an Pts conditiot.11 incident, one of __ moderate frequency.- Other. boron dilution flow paths will continue to
-be preied by the technical specifications.
L 2. The t . snces of an accident previously evaluated-in the FSAR are not in s A due to this chemical addition procedure. The results _ presentee in the-FSAR for- the Modes 3, 4 and la dilution events remain
- valid, -Soren dilution' as a' result of chemical addition in Modes 5b and 6 A ll not create more severe dose consequences..
=3r . This chemical addition-procedure does not' create the possibility of an accident which:is different than,any already evaluated in the FSAR.
' BoronLdilution configurations in Hodes 5b ~and 6 have been previously considered and evaluated in the FSAR. The conclusion-was-to keep the flow paths isolated so that no dilution flow-was possible. In order to support the chemical- addition. procedure, an alternative approach, which utilised specific analyses that are bounding for the injection path configuration,1was used.' The results indicate that the required l-operator action time is available given the expected dilution flow rates. Therefore, the Modes 5b and 6 boron dilution analyses meet the l' -Plant Vogtle licensing basis acceptance criteria for this event.. L -Other baron-dilution flow paths will continue to be precluded by the technical _ specifications. l
. . , . + . __ _ . , - , _ . , _ ,. , . _ . ,_ _ . . , _ _ _ , , , , - _
# ROM 8 LEST/FOCUCVSET/uC3 70:G4 M = epsy ygy g3, g9g9 3,,gpM , . i, SECL 89 943
- 4. The margin of safety it the plant Itcensing basis for boron dilution is defined as operator act on time between the high flux at shutdown j alarm and loss of shutdown margin (criticality). The high flux at shutdown alarm setp'. int defined in Technical Specification Table 4.31 l Note 9 is 2.3. For Mooo Sb, the operator action acceptance criteria as defined in SRP 15.4.6 is fifteen minutes and for Mode 6 $RP 15.4.6 i defines the acceptance criteria as thirty minutes. Th6 analysis criteria is desigt.4d to provide sufficient time fur the operator to j mitigate the event and prevent the complete loss of shutdown margin, Prevention of the loss of shutdown margin ensures that all ANS Condition !! criteria are met. Therefore, the cargin of safety is not reduced.
fonclusion Based upon the preceding entlysis, it has been determined that the proposed change to the technical specifications does not involve a significant increase in the probability or consequences of ar. accident previously evaluated, create the possibility of a new or different kind of accident from any accident previously evaluated or involve a significant i reduction in a margin of safety. Therefcas it is concluded that the proposedchangesmeettherequirementsofthCFR50.92(c)anddonot involve a significant hazards consideration, i - i P 3 ~ _ , s , - _ _ . - _ . _ _ _ , - _ . , _ . , . - . . , - -. , . - - - . , , . ,.- --._ ..
fro %ESMOCLP./ SET /WO3 tos ca pgs c 433s. w t), t9g, 3,, p , SECT. 89 943
- 4. The nrgin of safety in the plant licensing basis for boron dilution is defined as operator action time between the high flux at shutdown alarm and loss of shutdown margin (criticality). The high flux at shutdown alarm setpoint defined in Technical Specification Table 4.31 Note 9 is 2.3. For Mode 5b, the operator action acceptance criteria as :lefined in SRP 15.4.6 is fifteen minut64 and for Mode 6 $RP 15.4.6 defines the acceptance critaria as thirty minutes. The analysis criteria it det,lgned to provide sufficient time for the operator to mitigate the event and prevent the complete loss of shutdown margin.
Prevention of the loss of shutdown margin ensures that all ANS Condition !! criteria are met. Therefore, the margin of safety is not l reduced. Conclusion Based upon the preceding analysis, it has been determined that the proposed change to the technical specifications does not involve a significant increase in the probability or consequences of an accident previously evaluated, create the possibility of a new or different kind of accident from any accident preytously evaluated or involve a significant reduction la a margin of safety. Therefors, it is concluded that the proposedchangesmeettherequirementsof10CFR50.g2(c)anddonot , involve a significant hazards consideration.
i,I . .. ..,[', UNITED STATES g NUCLEAR REGULATORY COMMISSION o {o ,cf w u m atow,o.c. m n - k...+,/ e February 20, 1990 Dockets Nos. 50-424 and 50-425 Mr. W. G. Hairston, III Senior Vice Prcsident - Nuclear Operations Georgia Power Company P.O. Box 1295 Birmingharn, Alabam 35202
Dear Mr. Nairston:
SUBJECT:
ISSUANCE OF AMENCHENT NO.28 TO FACILITY OPEPATING LICENSE NPF.C8 AND AMENDHENT NO. 9 TO FACILITY OPERATIFG LICENSE NPT V0GTLE ELECTRIC GENERATING PLANT, UNITS 1 AND 2 (TACs 75320/75321) The Nuclear Regulatory Comission has issued the enclosed Araen: bent No. 28 to Facility Operating License No. NPT-68 and /cendment No. 9 to facility Operating License NPF-8) for the Vogtle Electric Generating Plant Units 1 and 2. These amendments consist of changes to the Technical Specifications (TSs) in response to your application dated November 21, 1969. The amendnents enable nor-borated chemical additions to be ude to the Reactor Coolant System (RCS) under administrative control during Mode Sb (cold shutdewn, locps not fillec') and Mode 6 (refueling) using a flow path via the Reactor Nkeup W6ter Storage Tank (RMkST). A copy of the related Safety Evaluation is also enclosed. Notice of issuance of the anenar,wnts will be included in the Comission's biweekly Federal Fegisty notice. Sincerely, Timothy A. Reed, Project Manager Project Directorate 11-3 Division of Reactor Projects - 1/II Office of Nuclear Reactor Regulation
Enclosures:
- 1. Amenament No. 28 to NPF-68
- 2. Amendnent No. 9 to NPF-81
- 3. Safety Evaluation cc w/ enclosures:
See next page
Mr. W. G. Hairston, !!! Georgia Power Company Vogtle Electric Generating Plant CC: Mr. J. A. Bailey Resident Inspector Manager - Licensing Nuclear Regulatory Comission Georgia Power Company P.O. Box 572 P.O. Box 1295 Waynesboro, Georgia 30830 Birmingham, Alabama 35201 James E. Joiner, Esq. Bruce W. Churchill, Esq. Troutmen, Sanders, Lockerman, Shaw, Pittman, Potts and Trowbridge & Ashmore 2300 N Street, N.W. 1400 Candler Building Washington, D.C. 20037 127 Peachtree Street, N.E. Mr. G. Bockhold, Jr. General Manager, Yogtle Electric Hr. R. P. Mcdonald Generating Plant Executive Vdce President - P.O. Box 3600 Nuclear Operations Waynesboro, Georgia 30830 Georgia Power Company P.O. Box 1295 Regional Administrator, Region !! Birmingham, Alabama 35201 U.S. Nuclear Regulatory Comission 101 Marietta Street, N.W., Suite 2900 Mr. J. Leonard Ledbetter, Director Atlanta, Georgia 30323 Environmental Protection Division Department of Lttural Resources Office of the Countv Commissioner 205 Butler Street S.E., Suite 1252 Burke County Commi.sion Atlanta, Georgia 30334 Waynesboro, Georgia 30830 Office of Planning and Budget Attorney General Room 615B Law Department 270 Washington Street, S.W. 132 Judicial Building Atlanta, Georgia 30334 Atlanta, Georgia 30334 Mr. C. K. McCoy Mr. Alan R. Nerdt, Chief Vice Presient - Nuclear, Vogtle Project Project Branch #3 Georgia Power Company U.S. Nuclear Regulatory Comission P.O. Box 1295 101 Marietta Street, NW, Suite 2900 Birmingham, Alabama 35201 Atlanta, Georgia 30323 4 4
.,w-. . g ,,.. A UNITED STATES 1 e. ' i;
{ f NUCLEAR REGULATORY COMMISSION WAsHINotoN, o. c. ossi
- s. .....f G_EORGIA POWER COMPANY OGLETHORPE POWER COR70 RATION HUNICIPAL ELECTRIC AlfTHORITY OF GEORGIA CITY OF DALTON, GEORGIA V0GTLE ELECTRIC GENERATING PLANT, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 28 License No. NPF-68 J. The Nuclear Regulatory Comission (the Comission) has found that:
A. The application for amendment to the Vcatie Electric Generating Plant, Jnit 1 (the f acility), Facility Operating License No. NPF-68 filed by the Georgia Power Company, acting for itself, Oglethorpe Power Corpo-ration, Municipal Electric Authority of Georgia, arid City of Dalton, Georgia (the licensees), dated November 21, 1989, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Comission's rules and regulations set forth in 10 CFR Chapter I;
- 8. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulad ons of the Comission; C. Thereisreasonableassurance(i)thattheactivitiesauthorizedby this amendment can be conducted witt.out endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Comission's regulations set forth in 10 CFR Chapter I; D. The issuance of this license amendment will not be inimical to the comon defense and sccarity or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirements have been satisfied.
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- 2. Accordingly, the license is hereby amended by page changes to the Technical !
Specifications as indicated in the attachment to this license amendment ! and paragraph 2.C.(2) of facility Operating License No. NPF 68 is hereby l amended to read as follows: l Technical Specifications and Environmental Protection Plan
)
The Technical Specifications contained in Appendix A, as revised ; through Amendment No. 28 , and the Environmental Protection Plan 1 contained in Appendix B, both of which are attached hereto, are hereby incorporated into this license. GPC shall operate the facility in accordance with the Technical Specifications and the ' Environmental Protection Plan.
- 3. This license amenJ*4nt is effective as of its date of issuance and shall be implemented witain 30 days of issuance.
FOR THE NUCLEAR REAULATORY COMMISSION
/ 1)
David B. Matthews, Director Project Directorate II-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation
Attachment:
Technien1 Specification Changes Date of Issuance: February 20, 1990 I 4 t y- - v-- ,,c-4 , .r, - - - .- - - - +-w-----_- , .--y.-,
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GEORGIAPOWERCOMPAy OGLETHORPE POWER CORPORATION MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CITY OF DALTON, GEORGIA y0GTLE ELECTRIC GENERATING PLANT, UNIT 2 AMENDMcHT TO FACILITY OPERATING LICENSE Amendment No. 9 License No. NPF-81
- 1. The Nuclear Regulatory Comission (the Comission) has found that:
A. The application for amendment to the Vogtle Electric Generating Plant, Unit 2 (the facility), Facility Operating License No. HPF-81 filed by the Georgia Power Company, acting for itself Oglethorpe Power Corpo-ration, Municipal Electric Authority of Georgia, and City of Dalton, Georgia (thelicensees),datedNovember 21, 1989, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Comission's rules and regulations et forth in 10 CFR Chapter I; B. The facility will operate in confomity with the application, the
,nrovisions of the Act, and the rules and regulations of the Commission; C.
Thereisreasonableassurance(i)thattheactivitiesauthorizedby this arrendment can be conducted without endangering the health and safety of the pubile, and (11) that such activities will be conducted in ecepliance with the Comission's regulations set forth in 10 CFR Chapter I; D. l The issuance of this license amendment will not be inimical to the comon defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 1 of the Commission's regulations and all applicable requirements have l been satisfied. 1 .
2 2.- Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this lleense amendment and paragraph 2.C.(2) of Facility Operating License No. NPF-81 is hereby amended to read as follows: l Technical Specifications and Environnental Protection Plan The Technical Specifications contained in Appendix A, as revised i through Amendment No. 9 . and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated into this license. GPC shall operate the ; facility tai accordance with the Technical Specifications and the Environmental Protection Plan. <
- 3. This license amendment is effective as of its date of issuance and shall be implemented within 30 days of issuance.
FOR THE NUCLEAR REGULATORY COMMIS$10N 4./ . David B. Matthews, Director Project Directorate !!-3 Division of Reactor Projects - 1/II , Office of Nuclear Reactor Regulation
Attachment:
Technical Specification Changes Date of Issuance: February 20, 1990 i b_
ATTACHMENT TO LICENSE AMENDMENT NO. 28 FACILITY OPERATING LICENSE NO. NPF-68 AND LICENSE AMENDMENT NO. 9 FACILITY OPERATING LICENSE NO. NPF-81 DOCKETS NOS. 50 424 AND $0-425 Replace the (c11owing pages of the Appendix 'A' Technical Specifications with the enclosed pages. The revised pages are identified by Amendment nurber and contain vertical lines indicating the amas of change. The corresponding overleaf pages am also provided to insintain document co@leteness. 1 Avended Page Overleaf Page 3/4 4-6 3/44-5 3/4 9-1 , 83/4 4-1 B3/4 4-2 83/4 9-1 83/4 9-2 e , ,...,-sm -
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REACTOR COOLANT SYSTEM COLD SHUT 00WN - LOOPS FILLED LIMITING CONDITION FOR OPERATION 3.4.1.4.1 At least one residual heat removal (RHR) train shall be OPERABLE and ! in operation *, and either: i
- a. One additional RHR train shall be OPERABLE **, or !
- b. The secondar" side water level of at least two steam generators shall be greater than 17% of wide range (LI-0501, LI-0502, LI-0503,
~LI-0504).
1 APPLICABILITY: MODE 5 with reactor coolant loops filled ***. ACTION:
- a. With one of the RHR trains inoperable or with less than the required steam generator water level, immediately initiate corrective action to return the inoperable RHR train to OPERABLE status or restore the required steam generator. water -level as soon as possible.
- b. W' 1 no RHR train in operation, suspend all operations involving a -
r uction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required RHR : train to operation. SURVEILLANCE REQUIREMENTS 4.4.1.4.1.1 The secondary side water level of at least two steam generators when required shall be determined to be within limits at least once per 12 hours.
' 4. 4. L 4.1. 2 At least one RHR train shall be. determined to be in operation and circulating reactor coolant at least once per 12 hours. :
L
*The RHR pump may be _ deenergized for up to I hour provided: (1) no operations are permitted that would cause dilution of the Reactor Coolant System boron concentration and (2) core outlet temperature is maintained at least 10'F belowsaturatIontemperature.
**0ne RHR train may be inoperab1e for up to 2 hours for surveillance testing provided the other.RHR train is OPERABLE and in operation.
***A reactor coolant pump shall not-be started unless the secondary water i
.. temperature of each steam generator is less than 50'F above each of the Reactor Coolant System cold leg temperatures.
.. 1 V0GTLE UNITS .1 & 2 3/4 4-5
l REACTOR COOLANT SYSTEM _ COLD SHUTDOWN - LOOPS NOT FILLED LlHITING CONDITION FOR OPERATION i 1 3.4.1.4.2 Two residual f. sat removal (RHR) trains shall be OPERABLE
- and at I least one RHR train shall be in operation.** Reactor Makeup Water Storage Tank i (RMdST) discharge valves (1208-04-175, 1208-U4-176#, 1208-U4-177# and j l 1208-U4-183) shall be closed and secured in position.
APPLICABILITY: MODE 5 with reactor coolant loops not filled. ACTION:
- a. With less than the above required RHR trains OPERABLE, immediately initiate corrective action to return the required RHR trains to OPERABLE status as soon as possible,
- b. With no RHR train in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required RHR train to operation.
- c. With the Reactor Makeup Water Storage Tank (RMWST) discharge valves -
(1208-U4-175, 1208-U4-176#, 1208-U4-177#, and 1208-U4-183) not closed l and secured in position, immediately c)ose and secure in position the RMWST discharge valves. SURVEILLANCE REQUIREMENTS 4.4.1.4.2.1 At least one RHR train'shall be determined to be in operation and circulating reactor coolant at least once per 12 hours. 4.4.1.4.2.2 Valves 1208-U4-175, 1208-U4-176#, 1208-04-177#, and 1206 U4-183 l shall be verified closed and secured in position by mechanical stops at least once per 31 days.
*0ne RHR train may be inoperable for up to 2 hours for surveillance testing provided the other RHR train is OPERABLE and in operation.
**The RHR pump may be deenergized for up to 1 hour pro.ided: (1) no operations are permitted that would cause dilution of the Reactor Coolant System boron concentration, and (2) core outlet temperature is maintained at least 10*F below saturation temperature.
#RMWST discharge valves 1208-U4-176 and 1208-U4-177 may be open under administrative control provided the Reactor Coolant System is in compliance with the SHUTDOWN MARGIN requirements of Specification 3.1.1.2 and the high flux at shutdown alarm is OPF.RABLE with a setpoint of 2.30 times background in accordance with Note 9 of Table 4.3-1. I V0GTLE UNITS - 1 & 2 3/4 4-6 Amendment No. 28 (Unit 1)
Amendment No. 9 (Unit 2)
3/4.9 REFUELING OPERATIONS 3/4.9.1 B0kON CONCENTRATION l LIMITING CONDITION FOR OPERA'i!ON 3.9.1 The boron concentn tion of all filled portions of the Reactor Coolant System and the refuelit./ aal shall be maintained uniform and sufficient to ensure that the more res :..tive of the following reactivity conditions are met:
- a. A K,77 of 0.95 or less, or
- b. A boron concentration of greater than or equal to 2000 ppm.
Additionally, valves 1208-U4-175, 1208-U4-177#, 1208-U4-183, and 1208-U4-176# l shall be closed and secured in position. APPLICABILITY: H0DE 6. ACTION:
- a. With the requirements of a. and b. above not satisfied, immediately suspend all operations involving CORE ALTERATIONS or positive reactivity changes and initiate and continue boration at greater than or equal to 30 gpm of.a solution containing greater than or eat:a1 to 7000 ppm boron or its equivalent until K,ff is reduced to less than or equal to 0.95 or th6 boron concentration is restored to greater than or equal to 2000 ppm, whichever is the more restrictive.
- b. With valves 1208-U4-175, 1208-U4-177#, 1208-U4-183, and 1208-U4-176# l not closed and secured in position, immediately close and secure in position.
SURVEILLANCE REQUIREMENTS L .:.
- 4. 9.1.1 The boron concentration of the Reactor Coolant System and the refueling canal shall be determined by chemical analysis at least once per 72 hours.
4.9.1.2 Valves 1208-U4-175, 1208 U4-177#, 1208-U4-183, and 1208-U4-176# shall l be verified closed and secured in position by mechanical stops at least once per 31 days. RWST discharge valves 1208-04-176 and 1208 '.,4-177 may be open under administrative control provided the Reactor Coolant System is in compliance with the requirements of Specification 3.9.1 and the high flux at shutdown alarm is OPERABLE with a setpoint of 2.30 times background. For the purpose of this Speciff vtion, the high flux at shutdown alarm will be demonstrated
- OPERABLE pursua..L to Specification 4.9.2.
I V0GTLE UNITS - 1 & 2 3/4 9-1 Amendment No.28 (Unit 1) Amendment No.9 (Unit 2)
3/4.4 REACTOR COOLANT SYSTEM BASES 3/4.4.1 REACTOR, COOLANT LOOPS AND COOLANT CIRCULATION The plant is designed to operate with all reactor coolant loops in operation and maintain DNBR above 1.30 during all nornal operations t.nd antici-pated transients. In H0 DES 1 and 2 with one reactor coolant loop not in operation this specification requires that the plant be in at least HOT STANDBY within 6 hours. In MODE 3, two reactor coolant loops provide sufficient heat removal capability for removing core decay heat even in the event of a bank withdrawal accident; however a single reactor coolant loop provides sufficient heat removalcapacityIfabankwithdrawalaccidentcanbeprevented,i.e.,by opening the Reactor Trip System breakers. In MODE 4, and in MODE 5 with reactor coolant loops filled, a single reactor coolant loop or RHR train provides sufficient heat removal capability for remc.ing decay heat; but single failure considerations require that at least two trains / loops (either RHR or RCS) be OPERABLE. In MODE 5 with reactor coolant loops not filled, a single RHR train provides sufficient heat removal capability for removing decay heat; but single failure considerations, and the unavailability of the steam generators as a heat removing component, require that at least two RHR trains be OPERABLE. The locking closed of the required. valves, except valves 1203-U4-176 and 1208-U4-177 for short periods of time to maintain chemistry control, in Mode 5 (with the loops not filled) precludes the possibility of uncontrolled boron dilution of the filled portion of the Reactor Coolant System. These actions prevent flow to the RCS of unborated water in excess of that analyzed. These limitations are consistent with the initial conditions assumed for the boron dilution accident in the safety analysis. The operation of one reactor coolant pump (RCP) or one RHR pump prov. des adequate flow to ensure mixing, prevent strrtification and produ e gradual reactivity changes during boron concentration reductions in the Reactor Coolant System. The reactivity change rate associated with boron reduction will, therefore, be within the capability of operator recognition and control. The restrictionis on starting an RCP with one or more RCS cold legs less than or equal to 350'F are provided to prevent RCS pressure transients, caused by energy additions from the Secondary Coolant System, which could exceed the limits of Appendix G to 10 CFR Part 50. The RCS will be protected against overpressure transients and will not exceed the limits of Appendix G by restricting starting of the RCPs to when the secondary water temperature of each steam generator is less than 50'F above each of the RCS cold leg temperatures. V0GTLE UNITS - 1 & 2 B 3/4 4-1 Amendment No. 28 (Unit 1) Amendment No. 9 (Unit 2)
REACTOR COOLANT SYSTEM BASES 3/4.4.2 SAFETY VAtVES The pressurizer Code safety valves operate to prevent the RCS from being pressurized above its Safety Limit of 2735 psig. Each safety valve is desig..d to relieve 420,000 lbs per hour of saturated steam at the valve Setpoint. The relief capacity of a single safety valve is adequate to relieve any overpressure condition which could occur during shutdown. In the event that no safety valves are OPERABLE an operating RHR train, connected to the RCS relief capability and will prevent RCS overpressurization., provides overpressure In addition, the Cold Overpressure Protection System provides a diverse means of protection against RCS overpressurization at low temperatures. During operation, all pressurizer Code safety valves must be OPERABLE to prevent the RCS from being pressurized above its Safety Limit of 2735 psig. The combined relief capacity of all of these valves is greater than the maximum surge rate resulting from a complete loss-of-load assuming no Reactor trip until the first Reactor Trip System Trip Setpoint is reached (i.e., no credit is taken for a direct Reactor trip on the loss-of-load) and clso assuming no operation of the power-operated relief valves or steam dump valves. required During for shutdown conditions overpressure in Mode 5 only one pressurizer code safety is protection. valve an unisolated and unsealed vent pathwayIn lieu of an actual operable code s of equivalent size can be taken as synonymous w(ith an OPERABLE t. o Demonstration of the safety valves' lift settings will occur only during shutdown and will be performed in accordance with the provisions of Section XI of the ASME Boiler and Pressure Code. 3/4.4.3 PRESSURIZER The 12-hour periodic surveillance is sufficient to ensure that the param-eter is restored to within its limit following expected transient operation. The is notmaximum watersolid a hydraulically volume ensures that a steam bubble is formed and thus the system. The requirement that a minimum number of pressurizer heaters be OPERABLE enhances the capability of the plant to control Reheter Coolant System pressure and establish natural circulation. V0GTLE UNITS - 1 & 2 8 3/4 4-2
3/4.9 REFUELINGOPEQLI,01NS BASES
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3/4.9.1 BORONCONCJNJAJI,0N l The limitatilns on reactivity conditin% during REFUEtWG ansu.'e that: ' (1) the reactor will remain suberitical during CORE ALTERATI04S, and (2) a uniform boron concentration is maintained for reactivity control in the water volume having direct access to'the reactor vessel. The lor. king closed of the i required valves, except valves 1208-U4-176 and 1203-04-177 for short periods of time to maintain :hemistry control, curing refueling operations precludes the possibility of uncontrolled boron dilution al the filled portions of the Reactor Coolant Systca.. These actions travent flow to the RCS of unborated water in excess of that annlyzed. These liuitations are consistent with the initial conditions atswed for analysis. The Boroi, tow.entratiot.- the Boron Ullution Accident in the safety of 0.95 or ins and int.ludes a conservative allowance for calculationa)value of.4000 p uncertainties of 100 ppm of boron. 3/4.D.2 INSTRgEN'lio ION The OPERABILTTY of the Source Range Neutron Flux Monitors unsuras that reclundant monit7 ting caphbility 4 available to detect enanges in the reactivity condition of tM cere. 4 3]/4.9.3_fLEfAYTIME . The minimum requirement for c) actor subtritit alf ty prior to n*wement of irradiaced fuel assemblies in the reactor vnisel ensures that sufficient time has elapsere to al'?w the radioac*.lvo decay of the short-lived fission products. thir, decay tire is condistent with the assumptions used in the safety analysr.s. 3/4.9.4 CONTAINMENT BUILDING PENETRATt0lls The requirements on containment building penetration closure and OPEP/BILITY ensure that a release of radioactite materiel within containment will be ristricted from ieakuje to the envirorrent. The OPERABILITY and closv'e rest. ictions sre sufficient to restrict radfoartive material rein.ser from a fuel eleu nt rupture based upon the lack of containment pressurization potantial wHle in thn REFUEt.ING H00E. 3/4.9.5 ,COMM'JN1(ATIONS The requirement for communications capability ensures that refueling station personnel can be pronrtly informed of Significant changes in the facility status or core reactivity conditions during CORE ALTERATIONS. V0GTLE UNITS - 1 & 2 B 3/4 9-1 Amendment No.28 (Unit 1) Amendment No. 9 (Unit 2)
1 REFUELING OPERATIONS BASES 3/4.9.6 REFUELING MACHINE The OPERABILITY ensure that: requirements of the refueling machine and auxiliary hoist (1) The refueling machine will be used for the movement. of fuel assemblies and/or rod control cluster assemblies (RCCA) ur th!mble plug assemblies, and the auxiliary hoist will be used for the movement of control rod drive shafts, (2) the refuelink machine will have sufficient load capacity to lift a I
~
fuel assembly and/or a rod control cluster assembly or thimble plug assembly, and t.he auxiliary hoist will have sufficient load capacity to lif t a control rod drive shaft and attach &d RCCA, and (3) the core internals and reactor vessel are protected from excessive l - Ilfting force in the event they are inahertently engaged during lifting operations. 3/4.9.7 CRANE TRAVEL - SPENT FUEL._ST0AAGE AREA 0 The restriction on movment of loads in excess of the nominal weight of a fuel and control rod assembiv and assrciated handling tool over other fuel assemblies in the storage pool ensurou that in the event this load is dropped:
' (1) the activity release will be limited to that contained in a single fuel assembly, and (2) any possible distortion of fuel in the storage racks will not result in a critical array. This as we release sssumed in the safety > 11yses.ption is consistant with the activity 3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION The requirement that at least one residual heat removal (RHR) train be in operation ensures that: (1) sufficient cooling capacity is available to remove decay heat and maintain the water in the reactor vessel below 140'F as required-during the REFUELING MODE and (2) sufficient coolant circulation is maintained throughthecoretominimIzetheeffectofaborondilutionincidentandprevent boron stratification.
The requirement to have two RHR trains OPERABLE when there is less than 23 feet of water above the reactor vessel flange ensures that a single failure of the operating RHR train will not result in a complete loss of residual heat removal capability. With the reactor vessel head removed and at least 23 feet of water above the reactor pressure vessel flange, a large heat sink is avail-able-for core cooling. Thus, in the event of a failure of the operating-RHR. the core, train, adequate time is providad to initiate emergency procedures to cool l_ i .. V0GTLE UNITS - 1 & 2 B 3/4 9-2 _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . __ ._ _ __. 2
[i f, UNITED STATES
- v. NUCLFAR REGULATORY COMMIS,SION g f CMm NZ N. O. c. mt.s
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SAFETY EVALUATION BY THE Of f!CE OF NUCLEAR PEACTOR REGULATION RELATED TO A N NEHENT NO. 28 TO FACILITY OPERATING LICENSE ltPF '8 AND .J 1NDMENT NO. 9 10 FACILITY OPERATING LICENSE APF.y GEORGI A P0k'ER COMPANY. ET AL. DjtKETS NOS. 50-424 AND 50-425 _YOGTLE ELECTRIC GENERATING _ptANT, UNITS 1 AND,,2 1.0 INTR 000L'i10H By lette dated Hoverber 21, 1989, Georgia Power Cocpany (the li ensee) requested changen to Techrical Specifications (TSs) J/4.4.3.4.2 nd 'J/r 9.1 for the Yogtle Electric Generating Plant, Units 1 And 2. Thesc chas qv: enable non borated chemical additions to be made to the Reactor Conlant Syste.a (RCS) curing Mode $b (cold shutdown, loops not filled) and Mode f 'refuelinr1 usirg 4 ilow path via the Peactor Hakeup Water Storage Tank (LMW$T), Use o1 this flow prth requires that valves 1208-U4-176 and 1208-UA-177 Se openeo periodically under administrative control. The existin; TSs require that these vah'es be closed and secured. 2.0 EVALUATION Of the accidents and transients addressed in the hgtlt Final i fety Analysis Report (FSAR), the borer, dilution event is the only trans%nt that ci 'la be a ffected by the pr g( sed TS revisions. The prolonged and urionttoce addition of an unborated chemical solution into the RCS for purposu ( / controlling RCS chemistry could lead to a conplete loss of shutdown nargin. FSAR Sectfun 15.4.6 presents boron dilution analyres for Mades 3. 4, a. 4 Sa (loops filled) in accordance with Standard Paview Plan 'SRP) Sect.or 15.4.6. The analyses verify that adequate operator tire (at leasi.15 minutes) is available to terminate the dilution flow between the tire a "high f1 a at shutdown" alarm is received and when criticality occurs. However . baron dilution analyses for Hodes $b and 6 do not exist beruse TS 3/4.4.'.4.2 and 3/4.9.1 assure that possible diluticn flow paths are isoleted by chning and securing the appropriate valves, thereby administr ativ 11y precluding a borun dilution event. To permit chemical additions to be cade to the RCS during Asdes 5b and 6 using a flow path via the RMWST through *he chemical mixing tank, valves 1208-U4-176 and 1206-U4-177 cust be opened. In this rJgard, tht. licensee has proposed revisions to the above refoxnced TSs and has performed boron vilution analyses for these nodes and this particular dilution path in accordance with SP Section 15.4.6. The SRJ acceptance criteric for Modes Sb and 6 are m t.icum operator action tiras cf 15 minutes and 30 minutes, respectively.
; l. < L*Y j ,(. o '
-2 The Itcensee's analyses to determine minimum operator action tires mak use of i conservative assumptions regarding boron dilution rate and active reactor coolant volume, as suggested in the SRP. A dilution flow rate of 3.5 gra, representing the maximum rate possible via the proposed flow path under any operating condition, has ieen assumed. Additionally, the minimum cold drained reactor vessel volume has been utilfred in the analyses, and the active RCS volume further minimized by assuming only one res1Wal heat renoval train in operation, considering miniflow and bypass lines to be egty, and reglecting reactor coolant loop voluses. Also, t % source range "high flux at shutdown" alarm is assured to be operable with a setpoint of 2.3 tisas background, as required by TS Table 4.3-1, Note 9. Shutdown margin ruc uiremnts, as specified by TS 3.1.1.2 for Mode 5 and TS 3.9.1 for Mode 6, are al so unchanged. The results of the licensee's analyses indicate that the minimum acceptable operator action times of 15 minutes for Mode 5b and 30 minutes for Mode 6, as specified in the SRP, are ret.
We have reviewed the licensee's analyses as provided in the Noverter 21, 1904, submittal and find that conservative assuntions have been used, the SRP acceptance criteria have been ret or exceeded, and that the pro)osed 15 changes will not have any adverse affect on safety. Any other boren dilution paths will continue to be precluded by the TSs. On the basis ol the above evaluation, the NRC staff concludes that the proposed TSs changes are acceptable. 3.0 EINIRONMENTAL CONSIDERATION The amenonents involve changes in requirtments with respect to the installation or use of facility components located within the ristricted area as defined in 10 CFR Part 20 and changes in surveillance requirements. The staff has determined that the amendments involve no significant incrwase in the amounts, and no significant change in the types, of arty effluents that say be released offsite and that there is no si ificant increase in indiv1&al or cun.lative occupational radiation exposure.gnThe Commission has previously issued a proposed finding that the anandnents involve no significant hazards considera-tion, and there has been no public coment on such finding. Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environrental im)act statenent or environrental assessnent need be prepar,ed in connection witi the issuance of the amendnents.
4.0 CONCLUSION
The Comission rede a proposed determination that the rmendments involve no significant hazards consideration which was published in the Federal Register on Decerber 27,1989 (54 FR 53205), and consulted with the State of Caorgte. No public comcents were received, and the State of Georgia did not have any coments.
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l 1
- 3- ;
The staff has concluded based on the considerations discaissed above that (1) there be endangered is reasonable by operation assu,rance in the proposed that manner the andhealth and safety (2) such 1 be conducted in compliance with the Cosesission's r,egulations, and the issuance : of the asundments will not be inimical to the cosmon defense and security or to the health and safety of the public. Principal contributor H. I.. Abelson, SRXB/ DST ' Dated: February 20, 1990 l I i I l .' s . i . 4
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, GP 15309 Westinghouw Energy Systems Waer semes omse Electric Corporation % 35 ,
mwerennsmnotm em August 16, 1991 NSL 0PL 1-91 490 Ref: 1) Log: ELV-03040 Mr. C. K. McCoy 2) GP 14649 Vice President, Nuclear, Vogtle Project 3)WCAP11338 Georgia Power Company - P. O. Box 1295 Birmingham, AL 35201 V0GTLE ELECTRIC GENERATING PLANT UNIT 1 Mode Sb Boron Dilution
Dear Mr. McCoy:
Georgia Power Company has requested that Westinghouse examine the effect of opening Chemical and Volumo Control System Valves (CYCS) 1208-U4176 ud 177 during Mode 5b (RCS drained to mid loop) operation at the end of Cycle 1 for Vogtle Unit 1. The Boron Dilution event in Mode 5b, with the above valves open, was not specifically analyzed for Cycle 1 because it was administratively precluded from occurring. Thus, Georgia Power Company requested that the event in this mode f Cycle 1 be specifically addressed, as outlined in Reference 1. Analyses performed for Vogtle Unit I demonstrate that the Mode 5b boron dilution event, with the above mentioned valves open and the Cycle I high flux at shutdown setpoint of 3.16, will yield accaptable results for Cycle 1. The analyses used assumptions consistent with those presented in Reference 2, but with a high flux at shutdown setpoint of 3.16. The analyses were performed with initial baron concentrations specifically requested by Georgia Power Company. Two cases were examined. Case 1 assumed an initial boron concentration of 774 ppm and Case 2 assumed 1130 ppm (see Reference 1), based or the time that the CVCS valves were open. T' .se two cases also assumed a critical boron concentration of 515 ppm (see Table 6.1 of Reference 3 for End of Life Londitions, 68 F), 0 per Georgia Power's request.
*The mssuon ofNSD is to provsde our customere u sth pople, equspment and senkes that set the esandards of excellence sn tse nuclear sndustry.*
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GP 15309 i Mr. C. K. McCoy ** i The results of the Case 1 and 2 analyses are sumarized in Tcble 1 on the following page. Specifically, the analysis demonstrates that there was more than 15 minutes (minimum acceptance criterion) from the time of alarm arior to criticality for the operator to take appropriate actions to mitigate t:1e Boron i Dilution event. ! If there are any questions, please contact Steve DiTomaso at (412) 374 5277. Sincerely,
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WESTINGHOUSE ELECTRIC CORPORATION
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J. L. Tain, Manager Georgia Power Company Projet.ts 4 Attachment cc: C. K. McCoy IL, IA R. J. Bush IL, lA NORMS (Vogtle Site) IL, IA G. L. Greenwood IL,- 1A .. : P. D. Rushton IL, IA ' W. B. Shipman IL, lA L. A. Ward IL, lA A. E. Cardona IL, IA R. Florian IL, IA
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i.- I-MICIEWr/041691
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T Table 1
- Boron Oilution Results for Mode 5 - Orained Down L11g Initial Boron Cone. Total Time Time from Alarm to Crit.
! 774 ppm 2900 min '
$38 min 2 1130 ppm $593 min .
>1000 min Acceptance Criterion 15 minutes I
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STS, Section T. 0 Voluntary Entry into Action Statements issue Date: 1/1/82 Interpretation: Voluntary Entry into Action Statement Conditions of the Technical Specifications (TS). Eurpose: To provide the NRC position concerning Voluntary Entry into TS Action Statement Conditions. Discussion: 10 CFR 50.36(c)(2) desci-ibes the limiting conditions for operation as the lowest functional capability or performance level of equipment that is required for the safe operation of the facility. Paragraph 50.36(c)(2) also states that the licensee shall shutdown the reactor or follow any remedial action permitted by the TS whenever a limiting condition for operation cannot be met. the MC endorses Voluntary Entry into the Action Statement Conditions and has structured the TS to permit the licensee to exercise judgment within the latitude permitted by the Action Statement language in the TS. The TS also restricts facility operation in the specified degraded mode of operation to the limited period of time designated in the related TS, In addition, Item 3.0.4 of the STS prohibits entry into an operational mode unless the conditions for the limiting condition for operation are met without reliance on provisions c:r.tsined in the action requirements. This latter ites provides assurnice that all operability requirements are satisfied prior to the r,ost recent startup.
Reference:
Hemorandum, B. K. Grimes to S. E. Bryan; dated June 13, 1979. l I l 1 l . 1
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, ,\, llNitt0 STATES i , c( ; NUCLEAR REGULATORY COMMISSION l n Amect oN. o, c. 2 ossa 3,(
%'cr{ llj June 13, 1979 MEMORANDUM FOR: Samuel E. Bryan, Assistant Director for Field Coordination FROM: Brian K. Grimes, Assistant Director for Engineering and Projects . l
SUBJECT:
CLARIFICATION OF STS: AC AND OC DISTRIBUTICN l As requested in your memo dated March 8,1979 (wnich forwarded J. Streeter's memo dated January 29,1979), we have reviewed the STS relative to AC and CC electrical power distribution. In the development of these specific technical specifications, as well as throughout the entire STS package, it has been our intent that the licensee not be required to assume a snowooll effect of the type suggested in J. Streeter s memo. It has been our intent that 8 i when an item is addressed in a LCO, the specific Action statement proviced for that LCO be the governing requirement for continued plant operation. The Action statements in the STS are provided in response to 10 CFR Part 50.36(c)(2) which states in part: "When a lim
- ting condition for operation of a nuclear reactor is not met, the licensee snall shut down the reactor or follow any remedial action oer-nitted by the :echnical soecification until :ne concit1on can ce met". We oelieve tn t for a relatively snort l time pertoo (witnin the time limits specified 'n the various STS Action l statements) it is usually safer to permit plan operations to continue
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ratner than to require initiation of a shutdown transient. A second concern expressed in J. Streeter's memo was that the STS do not preclude having a diesel generator associated with one AC/DC tus train
-inoperable and concurrently an inoperable battery in :he other DC train.
This scenario was recognized and considered during the cevelcoment of the STS. We do not believe that any further actinns art required nor are any further actions planned at this time since coertti:n in the pcs:blated conditions would be very limited. The Action statement for Soecificatien 3.8.2.3 permits plant operation to continue for a maximum of 2 hours af ter wnich the inoperable battery must either ce returned :: cuerat** status or a plant shutdown must be initiated and the enit must ce in not standoy within the following 6 hours. The allowaole wt of service times soect'ied in the STS for the AC and DC elettrical power supplies are corsistant j with the recommendations of Regulatory Guide 1.93. l The tnird concern expressed in J. Stret:ter's memo was tn:t licersees any l voluntarily enter technical specification actir,n statements w ,:iated witn AC and DC distribution by closing tie breakers between recur. car.t suses.
- In response to this concern, it should be noted that throughou: the STS, and typically in the custem technical specifications, the litem ce is l
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Samuel E. Bryan June 13. 19/9 t not prohibited from voluntarily entering action statements. We believe I-it is necessary and desirable to structure the technical specification l to cemit the operator to exercise judgment within the latitude permitted by Technical Specifications, it should be further noted that during operation in a degraded mode under the provisions of an action statement, the facility may not be capable of respondirg to an initiating event plus a concurrent or subsequent single failure of an active component. Therefore, the actiun statements restrict operation in the specified degraded mode of operation to a limited period of time. We are not aware of instances ! in which licensees have abused the provisions of being able to volunarily enter Action statements; however, if a licensee should frequently initiate i such activities, please bring it to our attention and we will consider i further actions on a c$se basis. Additionally, we would call your attention to Specification 3.0.4 in the STS which prohibits entering an operational mooe unless the operability requirements of the limiting condition for operation are satisfied without reliance on the provisions of the associated Action statement. This prevents startup when the opportunity is available l to meet the operability recuirements without initiating a shutdown transient. ; A fourth concern expressed was that the acceptance c.-iteria of 1.200 for the battery specific gravity was overly restrictive. This item is a plant specific value in the STS and the value of 1.200 was supplied by the applicant / licensee as being the applicable value, in accordance with the recomendatNs of Regulatory Guide 1.129, for thu subject battery. This i value was reviewed by NRR during the preparation of the subject technical l specifications and no further actions are considered necessary at this i time. i I We hooe that these coments have resolved the problems you raised. D. Brinkman is available for further clarificati as necessary. j
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@NC Brian K. Grimes Assistant Director for Engineering and Projects Division of Operating Reactors cc: V. Stello
- 0. Eisenhut DOR Project Branch Chiefs l STS Group Memeers j
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- F ' CLEAR REOULATORY 0044Ml8810N waanneevou,e,e,seses ;
e...* December 27,1990 ! t l
- i Mr. Kenneth A. Straha !
tascutive Vice president l Institute of Ilselaar power Operations : 1100 circle 75 parkway ' Atitatt,GA30839 ; Dear Mr. 8trahat . The NRC staff has noticed an increased tendency to eerfers preventive maintenance < during power operation. This includes maintenance of equP,eent requind to be operable by technical specifications. In order to omform this maintuence, > vtilities enter action statements of the Limiting Condniens for Operation (LCOs) in their technical specifications. While t apesars that- utilities are f attempting te limit the amount of time spent in an LC0 to a Masenable fraction of the total outage time allend by the LCO, in seen- cases the i maintenance say be repeated several t"mes during an Thisoperating Inds cycle to a concern that the total unavailability of sportant plant equipment may be ! higher than originally centemplcted. Of special concern is the entering into an LCO near the end of an operating cycle for the eriatry purpose of torfoming ' preventive matetenance in enter to shorten the nfueling outage. A frequently . encountered esemple is the overhaul of diesel generators. . . Several factors may have contributed to this increue in en-line reventive natntenances among thes6. appears;to be-the influence-of INp0 in encourastag- , _J utilities to limit the length of outa s. For example, INp0 8f 017, pg. 8,
. enc 9erages,utt11 ties, '...te maximite tge amount of work,de.e-en-line.'
The NRC staff is concemed that the impetus to perform more preventive - maintenance on-line may not have been thoroughly considered from the safety (risk) perspectlys. In seen instances the increase in en-line preveni a maintenance which requires entering LC0 action statements may centribute to art e n11able en-line performance of important plant equipment and enhuse eve safety. However, on line paintenance primarily for ub purpose of limiting pie eutate t*me er other operational convenience, should not be undertsken without 4 full appreciation of the effects of this practica en plant asfety. It should be kept in mind that the allowed outaga time set by an LC0 takes inte account the single failure criterien, which is an important assumption in the overall facility safety analyses. Ve the n fore consider the frequentperfoming entering i of an LC0 action statement to perform preventive maintenance, or extensive preventive maintenance en important safety equipment for tie purpose of reducins eutage time, to be outside of the original intent of the technical specifications allowed outage time. Although we believe a well founded preventive maintenance program can contribute to plant safety and reliability, we also believe that licensees should develop INNb- __ RECEIVED C 2 8_1990_
k ' Mr, Kenneth strahn a2o d 7 Decencer 27,1990 i a full understanding of the impact on plant ufsty when removing sculpment from
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service for preventtve maintenance. This may be an area where INP0 could take a significant leadership role. / I would be plassed to discuss this matter further at your convenience. 3 Sincerely,
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[ jmlW,ifdt!!I VMputyExecutiveDirector
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for Nuclear Reactor Regulation Regional Operations an8 Research cci Z. Pate, INPO J. Colvin, NUMARC i 0 KM p .;
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n. f' stTto STATIS gsslON NUCLEAR]R [oo (h' u*)f., zma OS NRC INSPECTION Ml}NUAL PART 9900 TttMMICAL GUIDAM6 MAlHTENANCE - VOLUNTARY ENTRY INTO LIMIT!IG CONDITIONS FOR OPERATION ACTION STATEMENTS TO PERFORM PRfvENTIVE MAINTENANCE A. PURPOSE To pro' tide a set of safety principles for guiding the performance of preven-tive maintenance (PM) at licensed nuclear reactor facilities when the performance of the PM requires rendering the affected system or equipment inoperable (on-l.ine PM). Although these principles apply primarily to PM during power operation, they also apply to PM on equipment that must be OPERAGLE operation. during shutdown evolutions such as fuel handling or mid-loop This guidance provides qualitative criteria to assist in recognizing abuses of on-line PM. If such abuses are noted, they should be discussed with NRC management before they are discussed with the licensee. This shoula e uure that the licensees. guidance is applied in a reasonable and consistent manner for all B. BACKGROUND The NRC has not previously established guidance on taking equipnant out of service to perform PM because the NRC did not expect licensees to routinely perform such PM when tech %.al specifications require the equipment to be OPERAEli.- Rather, it wa' emnted that' most PM that necessitated taking equipment out of service wep. De accomplished at a time when tne safety function performed by the equipment was not needed, (e.g., when the f acility is shutdown). Performing such PM (e.g., emergency diesel generator overhaul at powe6) requires intentionally entering the technical soecifications (TS) limiting conditions for operation (LCO) for the affected system. If a licensee does this, it must complete the PM and restore compliance with the LCO OPERABILITY requirements within the time specified in the appropriate action statement of the LCO. (i.e., the allowed outage ;ime (A0T)). Inten-l tional ;'ntry into an action statement of an LCO is not a violation of the TS (erret in certain cases, such as intentionally creating a loss of func. ' tion situation or entering LCO 3.0.3). For example, TS allow licensees to perform much surveillance testing during power operation, even though such testing requires entry into LCO action statements. TS permit entry into LCO action statenents to perform surveillance testing for a number of reasc .s. l One reason is that the time needed to perform most surveillances is usushy only a small fraction of the A0T specified in the action statement. Issue Date: 04/18/91 1
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f;j Another reason is that the benefit to safety (increased level of assurance of relianility and verification of OPERABILITV) derived from meeting surveil-Woca reautrements is considered to more than compensate for the risk to safety from operating- the f acility in an LCO action statement for a small fcaction of the A0T. The NRC staff has noticed a trend at many licensed nuclear f acilities - to perform increasing amounts of PM during power operation (on-line PM) rather , than- curing shutdown conditions. By performing more on-line PM, licensees must intentionally enter into LCOs more frecuently than before ano use more of the A0Ts than would normally be used by surveillance testing alone. This could cause thc total unavailability of ecutoment over each operating cycle (or the total time that a facility ooerates at increased risk because it is not complying with LCO OPERABILITY requirements and is vulnerable to single failures) to become greater than originally contemplated when TS were estab-lished. Of special concern is intentional entr into LCOs to perform PM near the end of an operating cycle primarily in car o shorten the refueling
.?u ta ge. .
The NRC is only beginning to quhnutatively study the significance to safety (risk) of the trend to perform more PM during power opJration. Therefore, the NRC can not yet establish quantitative criteria by which the NRC or a licensee can determine the net effect on safety that oo-lina PM would have at a facility. Until studies concerning the risk of on-lint PM are comoleted, this guidance establishes conservative principles for safely performing PM that involves entering into LCO action statements. C. DISCUSSION A - licensee may take ' equipment out of service to perform PM during power operation of the f ac'ility (on-line PM) if it expects the relia tility of the equipment to improve such that the overall risk to safe operation of the f acility - should decrease. Licensees' expectations should take into account that such practice miy increase the unavailability of - the equipment. When performing PM on equipment not in TS (i.e., equipment that has no TS A0T), licensees should be sensitive to the principles embodied by the TS definition of OPERABILITY and the effect upon the OPERABILITY of TS equipment. If a licensee has a reasonable expectation that an on-line PM program will improve.' safety by making equipment 'more reliable, then the licensee can implement that program even though -it may increase the unavailability of equipment. The licensee should be able to justify such an expectation of improved safety. Part of this justification should be based upon adherence to the following conservative safety principles:
- 1. Performance of a PM action on-line rather than during shutdown thould improve safety (as described above) and be warranted by operational necessity, not just by the convenience of shortening a refueling outage.-
- 2. Th: licensee should not abuse the allowance to perform a PM action on-line by repeatedly entering and exiting LCO action sutements. The licensee should carefully plan the PM action to prevent such abuse.
i Issue Date: 04/18/91 9900
- 3. While performing an on-line PM action, the licensee should avoid removing other eculpment from service. Confidence in the OPERABILITY of the independent equipment that is redundant (or diverse) to the affected equipment should be high, if a piece of equipment is OPERA.
BLE, but is degraded, or is trending towards a degraded condition, the licensee should not remove its redundant counterpart equipment from service for a routine PM action. 4 While performing an on-line PM action, the licensee should avoid per. forming other testing or maintenance that would increase the likeli. hood of a transient. The licensee should have reason to expect that the f acility will continue to operate in a stabl. manner. (The tasis of this expectation should include a considerat.Jn of degraded or out of service balance of plant equipment.) END 9900 Issue Date: 04/18/91 e
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)(* sumussuumuBI U.s. Nuc i none "A iEI NM"taAn artestenMfMLatomy enamen commesNw . TECHNICAL SPECIPICATION IMPROVEMENT PROGRAM This is theThese second issue highlights areof theissued being TECMICAL $PECIFICATIONS regularly by the Technical Ile20VEME HIGHLIGHf3. 5pecifications tranch in an effers to keg both HeadquartW and Regional staff informed of important developments in the joint NRChrJustry program to implement the recently issued Commission Comments Policy for er suggestions 5tatement future issues an Technical should / Specifications !aprovement.be referred directly to Millard Wohl, Mall 5 top 515,
' 1TAFF APPROVE;MI5"JL* SWR CER5 GROUP TOPICAL REPORT MEDC-10
.Y515 70R BWR REAGIUE PsWTtGTION 5Y5 TEM" SPEGUIGATION IMPROVEM The staff issued an SER en the above topical report to the gWR OwnersThe Group chairman en July 15,1987.
report will permit certain gWR licensees to extend the carnnt weekly and monthly RPS sensor channel functional test repair Allowable intervals andtotest guarterly times ofinter-(*. vals for gWR relay-type AP5 plants. 1 hour and I hours for the SWR APS nlay senser channels are extended to
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CiNffACTS:7. Collins, x29463 x27 tit
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- STAFF REVISES TECm! CAL $PECIFICATION 119110VEMENT PR A revised NRC Technical Specification Isorevement Program Plan has been developed in response to the Comeission's recently promulgated InterieThe Pro Policy Statement en Technical Specification Improvement.as devolep) the Ceesission's Policy 5tatteent.
One section of the Program Plan lists these tasks rewritten along with a schedule Standard for coupletion Technical necessary(to specifications develop STS) called the complete licy Statement. The for in the object,$ve of rewriting the STS is to reduce their site human factan and other general 1sprovements in o dJ more effective tool for assuring plant safety.STS will be tapleme ( anatuleents. { Another section of the Program Plan is devoted to activities aimed at j ( improving the technical substance of specific line itse requirem the Technical Specifications. I
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E reevelustion of the appropriateness of current action statements, allowed estage tiess, and surveillance intervals. The Prrgree Plan, new in its early stages of implementation, carries witA ' it a central thoes of the Cameisslen's policy statement, that.ef a volun-t,afy, cooperative,Martf joint ef NRCthe and industry activities-in approach the Plan to Technical require detailed Specifica-tiens improvement. These activities were discussed subalttale free industry working groups. eith the npropriate industry representatives while they were beina defined and the JdtC espects the full-support of the industry in this important progree. CONTACT: D. Fischer, a27465 YOLUNTARY ENTRY INTO TECHNIM SPECIFICATION ACTION STAT di l ionaStatements n Lietting Conditionestablish time limits for imis(LCO) for Operation not eeE. This time limit plementine reme a is jsessenly referred to as the Allowable Outate Time (ACT) since it defines a limittne ties duration for which a system or cesponent may be out of. service for corrective maintenance when it is found to be inoperable. 'The
, ACTS also estabitsh the limiting time durations for which a systen er com-ponent say be voluntarily resored free service for surveillance testing L
er investigation of operational problems. Generally the T L within the limits of the A07. Specification 3.0.3 in the Standard Tech *nics' Specifications establishes the time limits for an orderly plant shutdown unich apply when the action . requirements de not specify a remedial sessure for a conditten
- LCO haveisvolunterity not set. entered the forced plant An shutdown esseple is the requirements neoval of- of 5pecifica-
- tien 3.0.3 as an operationel convenience.
b: redundant systems from service to perfere a serve 111 has alerted Regions! Ahtnistreters* that voluntary use of Specifica-
.tien 3.0.3 is unaccettable as an operations) convenience in lieu of nther Tae updated Bases for the general requirements that courses of estion.
are applicatie.to LCOs and surveillance requirements included in Generic Letter 87-09 reflect these posittens.- aManoranche free Themes E. Nurley, Director, MR to Regionel Achitaistrators, dated June 17. 1987. CONTACT: T, $ 9maafng, n20434
*t* TION EMBIMERINt IVALUATION
. NaC sTRAsivi CL**.ETES 'A REVIEW ff THE t
( Fox mRNDInE THE U5 nND UFA5 Ta5' IMIENV?M" On T/20/87 the staff received a draft Techrdcal Evelection Report (TEA) en the CE dwners Group topical report CEN-3tt. "kp5/E5FAS Extended Test Interval Evaluation." The IG&B
i 23 Southampton Court . Newport Beach, CA 92000 July 2,1991 Mr. Geofgo Hairston Senior Vice President -
. Georgis Power Company P. O. Box 1296 Birmingham, AL 36201 Deer George, it was rWoe talking to you again after all these years. As hootic as k was, I remember my period with Westinghouse on the Standard Tech Specs as one of the most exciting periods in my earty l oareer. I'm sony to hear of your probioms with them after all these years but feel good about the fact that work we did in the earty 1970's is still important to the nuclear industry -It somehow makes all the lon g days over the years somehow worthwhNo. As you now reallre lleft this arena later in the 1970's although I remained at Weetinghouse in other capaoltles until late in 1900 i when 1 joined my current sipep .
As we discussed this week, I remember many of our discuselons with the NRC concoming the use of the term 1MMEDIATE'in any enforceable ' REQUIRED ACTION". As we jointly discussed with the NRC in the 1970's, in nuclear power plants the asfoot sciullon is not always a precipeous F action taken based on incomplete data. We debated long and hard over this issue with the NRC - and, se i remember 11, they ultimately agreed that we wotAd have to better define our intent in using the term 'IMMEDIATE". At first i benevo may proposed to define the' term in tL, t " DEFINITION" sootion of the tech spec and that we talked in terms of 10 20 minutes as an appropriale immediate response for moet occurrenose requirin0 prompt dociolon maidng and oction. Utimately, I thought the NMC decided to discontinue use of the word "lMMEDIATE" and place actual time limite in each action item so that operatore would not be leoed with M4 in their minds, whBe under pressure, the Intent of the NAC. As far as I can remember, the term
~1MME0 LATE" was removed from aN spediloations.
If I can be of further assistance, please feel free to cas me again veey truly yota,_ Y . Charles C.
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STATEMENT July 12,1991 1, the undersigned, was_ on the staff of the United States Nuclear Regulatory Commission (USNRC), formetty the Af4mic Energy Commission (AEC), from August 1968 through October 1978. During the period of time from 1973 through 1978, I conceived, developed and implemented the Standard Techn' .cal Specircation Program for the Commission. There were a number of objectives to be achieved in developing the STS's. Obviousy, the primary objective was to have consistent specifications among the vanous plants being placed into service by each of the reactor vendors. Thors were however, secondary objectives to be achieved. One of these was to have specifications which were clear and unambiguous and easily understood by an operator faced with a situation seguiring action at 3:00 AM in the moming. This issue of clarity is the subject of this statement. One of the first draft issues of the STS's had a r. umber of action statements which required operator action on an 'immediate* basis. As the STS's evolved, it became apparent that trying to define
'immediately* was an impossible task given the varying degree of severity the ' Action' statement was being required to cover, Eventually, the term *1mmediately' was replaced by a series of time dependent 'Actiorf statements which were tailored to the severity of the situation and took into account the ability of the physical plant to respond to the required change in a given time period. This change represented a substantial improvement in the STS's and was endorsed by the ANS 58.4 Standards Committee on Standard Technical Specifications.
Mb J.M. McGough ' 1
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- s NUCLEAR MoVLAfoRY c0MMiss10N wAsmotom.o c.neen
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May to. Ig77
; MEMORANDUM FOR:
G. Fiore111. Chief. Reactor Operations and Nuclear Support Branch. #!!! FROM: J. H. Snitzek Assistant Director for Field Coordination. R0!/IE
SUBJECT:
OPERABILITY DEMONSTAATION OF REDUND We have April 27,1977.discussed with DDR the issue raised in your memorandum of' The NRC philosophy of testing redundant systems when one system fails is undergoing ,a change. The current feeling is that to take its redundant system out of service for testing if the first system fatis, creates W risk of the second system also, failing. It has been obse'rved that failures of the second system are often related to the test itself and is not an indication that the system would have failed should it have been needed.-
.- All current to improve STS older T3.reflect this thinkins and some 75 changes are occu 1 \ Some older facilities however, are reluctant to
- testing the redundant saccept this improvement because in order to justif an increased interval. ystem, that system sust be routinely tested at g 00R will not accept a deletion of imediata redundant testing without improved routine surveillance frequencies, i
To specifically answer your mquest that 'imediate" be interpreted as In some-casss it might be too long while in other cas period might create a rushed situation that would result in an increased Nov soon the test should be conducted will depend o system failure. As a guideline, if the failure was generic ' the redundant syatem might not function for the same reason,such then the that is not likely that the second. system will fail by the s there is less urgency to conduct the test. . NRC a will relybasis. case-byacase on the technical judgment of the HItC inspection staff on P - 9
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- n. snicaek 0 for Field ordination
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%L m rc$ovgh< NRR G. L. Madsen RIV
^ E. J. Brunner RI J. L. Crews. RV Q F. J. Leng R!! X, Y. Seyfrit. IE 1 CONTACT:
p C. L. Constable 49 27451 ( l- - , .-- . . .
C. Core Alteration - Core alteration shall be the addition, removal, ) ;l relocation, or movement of fuel, sources, incore instruments, or 4 reactivity controls within the reactor pressure vessel with the vessel head removed and fuel in the vessel. Suspension of core alterstk ns shall not preclude completion of the movement of a component to o safe conservative position. Desion oower - Design power refers to the power level at which the
')
D. reactor is producing 105 percent of reactor vessel rated steam flow. Design power does not necessarily correspond to 105 percent of rated reactor power. The stated design power in megawatts thermal (MWt) is the result of a heat balance for a particular plant design. For Hatch Nuclear Plant Unit 1 the design power is approximately 2537 MWt. 1 E. Enoineered Safety Features - Engineered safety features are those features provided for mitigating the consequences of postulated acc'. dents, including for example containment, emergency core cooling, and standby gas treatment system. F. Hot Shutdown Condition - Hot shutdown condition means reactor operation with the Mode Switch in the SHUTDOWN position, coolant temperature greater than 212*F, and no core alterations are permitted.* l G. Hot Standbv Conditio_q - Hot standby condition means reactor operation with the Mode Switch in the START & HOT STANDBY position, coolant temperature greater than 212'F, reactor pressure less than 1045 psig, ) critical. H. Imediate - Innediate means that the required action shall be initiated as soon as practicable, considering the safe operation of the Unit and the importance of the required action. I. Instrument Calibration - An instrument calibration means the adjustment l c5 ar. instrument output signal so that it corresponds, within acceptable I range and accuracy, to a known value(s) of the parameter which the instrument monitors.
. J. Instrument Channel - An instrument channel means an arrangement of a sensor and auxiliary equipment required to generate and transmit to a ,
- trip system a single trip signal related to the plant parameter l monito;ed by that. instrument channel.
l l h I *During the performance of inservice hydrostatic or leakage testing with i_ all control rods fully inserted and reactor coolant temperature > 212*F, l and/or reactor vessel pressurized, the reactor may be considered to be in l the Cold Shutdown Condition for the purpose of determining Limiting e I condition for Operation applicability. However, compliance with an ACTION requiring COLD SHUTDOWN shall require a reactor coolant temperature $ 212'F.
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HATCH - UNIT 1 1.0-2 Amendment No. 78, 102, 739, 160 1
5:-t S10 910410 867 r. A -
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Joseph R. Bynum vee Pose.9enL Nweet ooersuane April 10, 1991 t U.S. Nuclear Regulatory Consnission ATTN: Document Control Desk Washington, D.C. 20535 Gentlement TENNESSEI VALLEY AUTHORITY - SEQUOYAR NUCLEAR PLANT UNIT 2 - DOCKET NO. 50-328 - TACILIT! OPERATINC LICENSE DPR LICENSEE EVENT REPORT (LER) 50-323/91003 The enclosed LER provides details concv uing the discovery of the breaker for the Unit 2 No. 3 cold les accumulator isolation valve being in the locked closed (power on) position. Technical Specification (TS) Surveillance Requirement 4.3.1.1.1.c requires that the valvr be open with power removed. This event is being reporte<i in accordance with 10 CFR 50.73(a)(2)(1)(3) as an operation prohibited by TSs and 10 CFR 50.73(a)(2)(ii)(B) as a condition that was outside the design basis of the plant. . Mr. Bill Little, of your NRC staff, was notified on April 2 and again on April 5, 1991, that issuance of this LER was delayed, and that the LER vould be issued by April 12, 1991. Very truly yours, TDCfES'SEE VALLET AUTHORITY
. a. a F ,.
l . Enclosure ec: See page 2
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.- g U.S. Nuclear Regulatory Commission April 10,-1991 JLWiMAC:JWP:CC Enclosure .f ec (Enclosure):
Mr. D. E. LaBargo, Project Managar U.S. Nuclear Regulatory Comuirssion One White Tlint,.vorth 11555 Rockville Pike ' Rockville, Maryland 20852 --
-~~.
I:TPC Records Center Institute of Nuclear Power Operations 1100 Circle 75. Parkway, Suite 1500 Atlanta, Georgia 30339
.NRC Resident Inspector Sequoyah Nuclear Plant 2600 Igou Terry Road Soddy Daisy Tennessee 37379 .
/ 9 Mr. B. A. Wilson, Project Chief .
U.S. Nuclear Regulatory Commission Region II 101 Marietta Street, NV, Suite 2900 Atlanta.. Georgia 30323 RIMS, MR ZT-C ..",
. W. R. Cobean, Jr., LP 6A-C **
D L. Conner, SIC 2H-SQN M. A. Cooper,'0FS LC-SQN - fp gg , gg-(Attn: J. 5. Smith) J. H. Carrity, TSB 1A-WBN-R. L. Lumpkin, Jr., SB 1C-SQN R. W. Martin, OPS 45t-SON (Attn: ?. J.-'Hollomon) F. C. Mashburn, SBT 1A-SQN T. J. M:Grath. LP 6A-C k M. O. Medford, LP 4A-C Nuclear Experience Review Files, OPS AD-SQN P. Salas, FAB J-3FN R. 5. Shell, LP 58-C P. G. Trudel, DSE 1A-SQN E. C. Wallace, LP 5B-C J. L. Wilson, OPS 4A-SQN
, 1352h
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LICENSIN TRANSMI'TAL TO NRC
SUMMARY
AND CONCURT*NCE SHIEI TEE PURPOSE OF T1!IS CONCURRENCE SHEET IS TO ASSURE THE ACCURACY AND COMPLETENESS OF TVA SUEMITTALS TO THE NRC. CRIGINAL EXTENDED - DATE DATE DUE NRC h/1/91 - C DATE DUE NRC SUEMITTAL PREPARED BY Gregory S. Kniedler ACTION No. TEES REQUIRED YES _ No XX PROJECT /DOCUMENI I.D. Seouoyan Nuclear Plant (SON) - Licensee Event Report (LEf/) 50-328/91003 *
, PURPOSE /SUITiARY h rovide NRC with LER 50-328/91003 concernine the discovery of the breaker for 4he Unit 2 No. 3 cold let decumulator (CLA) isolation valve being in the lock closed position. Technical Speef fication Surveillance Reauirement 4.5.1.1.1.c recudres that the valve be neerable with power removed.
RESPONDS TO N/A (RIMS No.) COMPLETE RESPONSE YIS XX No PROBLEM OR DEFICIENCY DESCRIPTION Failure to remove power from the breaker of the isolation valve oeerator for the No. 3 CLA. therefore operating in a conditien orchibited by TS and outside of the design basis. CORRECTIVE ACTION / COMMITMENT See corrective action section. INDEPENDENT R; VIEW DATP. A concurrsace signature reflects that the signatory has assured that the subetttal is appropriate and consistent with TYa Policy, applicable comeltmoats are appreved for implementat. ton, and supporting s0Cumentation for submittal completeness and 40 Curacy ht2 been prepared. CONCURRENCE NAME ORGANIZATION __ SIGNAPURE DATE
-J. L. Wilsen SON site Vice Presidene ,5 %
['ff' il R. J. Beecken SUN Plant Manarer & - 4[/ 7/ _? ORC Chairman / / ///s/fs P. C. Trudel SQN Proieet Enrineer b '/ 8 9/ M. A. Cooper SQN Si,te Lie Mer Mb a -- /* / APPROVED _ M.h. u DATE 1352h
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- q. . n;,e e o cro Y9 3iTTA'o 31!9 ?C$ 6E'60 I66I M OO
Sequoyah Site Licensina *
- Concurrence Sheet 4
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ORIGINAL EXTENDED DATE DATE-DUE NRC 4/1/91 C DATE DUE NRC PROJECT / DOCUMENT I.D. __Sequoy,th Nuclear Plant (SQN) - Licensee Event Report:
.r (LER) 50-328/91003 Incident Investigation No. I1-3-91-017 Cross Reference Documents (PER, CAQR, etc.)
Verification by __ _ CONCURRINCE SIGNATURE OR NAME ORGANIZATION LETTER RETIRENCE DATE G. S. Kniedler SON Licensing Entineer _ - Y d f/ _.J. W. Proffitt SON Comoliance Lie Mer ;a, & -9 / M N 4 /, / ,_
- 2. S. Smith Y f $0N Site Licensins m n) h 4h l R. W. Martin / SON Site Controller
/
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i M. J. Lorek A_ SON Coerations Sunerintendent i %v ~ I O*9 I U. R. Lanerrren SON Coerations Manager b, L, 10 9( _ i ,_l uK. Cates SON Technfes! Scopert Manater [ b /d / li. NRC response or approval required? _ Yes X No
*** NOTE: This sheet should be removed by Corporate Licensing upon receipt.***
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- LICENSEE EVENT RENRT (LER)
FACILITY NAME (1) l DOCKET NUMBER (2) l_pA9=f3) 3msnevah Morlear__PJ, art _ Uait 2 _ 10l$10101013 !? 18 I!! Ort il 1 Ti1LE (4) Power not removed from cold leg accumulator tsolation valve as a result of trappropriate eersom1 mett ens . fVFMT DAY f?) 1 ( F R PetM ER f 6 ) 1 REPORT Daft f?1 l OTNER FAf f L f YY E5 f *'VDtVED f B 1 l l l l l5t0VENTIAL l lAEV!5!0Nl l l l FACILITT kAMt3 l0OCKET NUMBER (3) MDNTHi cay IYtsp lyrAR I 1 NuMe rn ! I NUMarR IMSNTMt nay IYEAR l lII I!l1 1 1 1 I l _I lI I I I l l Of 31 Of 11 91 il 9I 11 1 0 1 0 I3 I i 0l0 l of Al il of el 11 lI lIliI l OPERATING l lTHIS REPORT 13 $UBMITTED PUR$UANT TO THE REQUIREMENTS of 10 CFR 5: M)CE l l f fha elt eae ne enre of the f o11 ew4.n e ) ( 11 ) _ s '91 1 11 l20.402(s' ) l,.l20.40He) l_l50.73(al(2)(tv) l 173.71(b) POWER l l.,_l20.dO5(a)(1)(l) l _l$0.36(c)(1) l l50.73(,a)(2)(v) l l?3,71(c) LEVEL l l l20.403(a)(1)(II) l ,,150.36(c)(2) l ,l50.73(a)(2)(v1f) l 10THER (5eecify in
01 1 il el O! l20.405(a)(1)(ill) jZZl50.73(al(2)(1) l 150.73(a)(2)(viilitA) l Abstract below and in l__]20.405(a)(1)(iv) lZZl50.73(a)(21(li) l l50.73(a)(2)(viii)(s) l Teut, t.Ac forv 366A) i I?0. DOE (atft)fv) f fBS 73falf? tit 91) l I?O 73falf?)fr) I _
Lf FEN?fr CONTACT Foo THf ? trt (12) , NAM [ l_ 'ftt#* Q f ne M tt lAREACODEl Grecer z_3. Ke f edl er Cemeli nees tienesine Fseineer I4l1 1!lBld I3I I7 id l611 COMotfTE ONE LINF FOR EACM COMPONENT fAILU#f DE3tRf!Eh fH TMT3 REPORT (131 __ l l l lREPORfABLEl l { l l lREPORTA8LEl
,r.AU3t!3YSTfMl COMPONfMT lMANUf AETt' trol TO ND00$ j lCAU$fitV?TEMI fow*e4ENT l>ANuraCTU8fRl TO NrtD5 l I i i i l i I l l 1 1 I I I ! I I I I I I I l I I I ! I I I I I I I I I I I I I I I I I I I I
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$UD#t rwrNTAL REPORT EXPfETfD f id) __ l EXPCCTED lt*2NTHI DAY I YEAR l l$U5M:5510Nl l l l v's f f ' vet . eeaolete rXPECTED TUOMYH f 0N DA TE) I If 1 NO l DAfr f15) I l ! I I l A857RACT (Listt to 1400 spaces, i.e.. approvisately fif teen single-space typewritten lines) (IC)
On March 1, 1991, at 0127. Eastern standard time (EST) with Unit 2 in Mode 1 it was discovered that the breaker for the operator for the No. 3 cold leg accumulator (CLA) isolation valve 2-FCV-63-80 was locked in the closed position. This was discovered during the performance of Sur,reillance Instruction (SI) 0-SI-OPS-063-013.0, " Cold 1.eg Accumulator Valves Power Removal verification." The last documented manipulation of this breaker was on February 14, 1991, when an evolution was being perfor:ned in attempt to stop inleakage of reactor coolant into the C1.A. This evolution was initiated at l 2019 f.ST on February 14, 1991, and completed at 2032 EST with the components thought I returned to their required conditions / positions. No independent verification of the breaker's restoration was perfor:p% The cause of the event is atr< huted to inappropriate personnel actions edPediate corrective action was to restore the brea'cer to its correct position, <2diManal corractive actions include discussions with Operations personnel to clariry cequirements, disciplinary action, procedure l 1 clarifications, and further training. I 1 t
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DESCRIPTION OF Em!T 4 On March 1,1991, at 0127 Eastern standard time (EST), with Unit 2 operating in Mode 1 (100 percent power, 2,235 pounds per square inch gauge (psig], and 578 degrees Tahrenheit IF]), it was discovered that i.he breaker for the operator of the Unit 2,
. No. 3 cold leg accumulater (CLA) (EIIS code BQ) isolation valve. 2-TCV-63-80, was
' locked in the closed position. This was discovered during the perf*ormance of Surveillance Instruction (SI) 0-SI-OPS-063-013.0 " Cold Leg Accumulator Valves Power Removal Verification," which is required by Technical Specifica"clon (IS) Surveillunce Requirement (SR) 4.5.1.1.1.c. SR 4.5.1.1.1.c requires that: "At least once every 31 days when the RCS pressure is above 2000 psig by verifying that power to the isolation valve operator is disconnected by removal of the breaker from the circuit." The TS basis for the requirements of TS 3.5.1.1 is "The accumulator power operated isolation valves are considered to bat ' operating bypasses' in the context of IEEE Std. 279-1971, which requires that bypasses of a protective function be removed automatically whenever permissible conditions are not met. In addition, as these accumulator isolation valm s fail to meet single failure criteria, removal of power to the valves is required." The shift operations supervisor (SOS) was insnediately notified of this condition and TS Limiting Condition for operation (LCO) 3.5.1.1 was entered at 0127 EST. The breaker was unlocked, opened, and locked in the open position (i.e., power removed) at 0131 EST and LCO 3.5.1.1 was exited.
On February 1, 1991, 0-SI-OPS-063-013.0 was performed and the breaker for the operator to 2-TCV-63-80 was verified in the locked open position as required by T3 3R 4.5.1.1.1.c. On Tebruary 14, 1991, an evolution was initiated in an attempt to reduce the 0.21 gallons per minute (gpci) inleakage of the reactor coolant system (RCS) into the Unit 2, No. 3 CLA. The performance of this evolution was done in accordance with Administrative Instruction (AI) 30 " Nuclear Plant Conduct of Operatinn," which states: " Limited evolutions of short duration may be performed by an operaser without a procedure provided that positive configuration control is maintained in accordance with AI-58, a procedure does not exist for the activity and the operation is not cceplex. The SOS and unit assistant shift operations supervisor (ASOS) will determine if any operation will be allowed without a procedure based upon the complexity, ! duration of the operation, TS requirements and Tinal Safety Analysis Report Description / Bases / Assumptions. Any evolution performed without a procedura shall be l documented in the operator journal." The evolution to stop the inleakage of RCS into the No. 3 CLA was to consist of unlocking and closing the breaker for valve 2-TCV-63-80, the repositioning of four valves (2-TCV-63-80. -78, -71, and -84), and the operation of the 2A Safety Injection System (SIS) pump. Ite Unit 2 ASOS was to remain at the breaker throughout the evolution to maintain positive entrol and the Unit 2 lead main control room (MCR) unit operator (UO) would waintain positive control over the valve manipulations in the MCE. l l l NAC form J66(6-69) _.. _,_s ... -.- -,, a.- , e me $ ~ . c ri *ce' e ^3n
_ .~ __ _ - - - . - - . - - - . _ _ _ - _ . _ - . , - .__ - l-gesA U.S. NUCLEM REGULATORY topellS$10N - Approved 088 No. 3150-0104 [j LEDE tYDli REPORT (LDt) TtxT CONTINUATION-c.,i ,.. .mm - - i 3ACILITY Nant-(1) l003ETNUNett(3)I tra maman rs1 I I paar s3 l lyrAs lil$50UCNTlaL l latV!$10Nl l l l l l - l Segiseyah seclear F1 sat Un'!, 2 l I ammare i I meers I g g g l , 18Ie10101011 12 la le 11 1 1 a i a 1 3 I_I o I- e i of stort il i TEXT 11f more space is reesired. use additianal NaC Fere 346A's) (17) DESCRIPTION OF EVUfT
' 4 -
-Thiu lineup was f.ntended to vent pressure from the upstream side of check valve 63-424 o to the holdup tank and then nyply a large differential pressure to backseat the check ,
valve by startinnl the SIS pump. Refer to Updated Final Safety Analysis Report (UFSAR) ; 3- Tipre 4.3.T 't. lafern perferzing this evolution, the antivity was discussed with the Operations Superintendent, that off-going $05, the onshift SOS and the onshift Unit 2 A505. The ' activity was detersfned--to acastitute a limites evolution based on the small number of manipulatio.as, suticipated short duratitm, and positive controis that would be i implemented. The initial revies for the evolution by the onshift SOS and onshift Unit , 2 ASOS consf.sted 'of a review of flow prints, cettnical specifications, and procedures. Electrical prints were not reviewed. The evoJution was initiated at 2019 EST on February 14,4931, with entry in e tro 'lM - L. *. . Its se activities were *ogged into the or.oreter's log as required by AI-30 for limited evolutions. The Unit 2 A30S unlocked
- and closed the- breakair- for the 2-FCV-63-40 operator. the Unit 2-lead UO then shut 2-FCV-63-80:froa the MCA. : The isolation valve satomatically opened. This was reported to tLe A505 at the breaker. The A504 opened ant' then-closed- the control power breaker -
to the 2-FCV-63-40 operator to clear any possible istk-in-Safety injection signals. The A505 then requested the U0 to elose 2-FCV-43-80 sad it ag.in reopened
- automatically. The ASC1 =1ocked tje . rasker open,- then proceeded to L:.e MCA to review drawings to deternice what was preventing toe valve from remaining closed. The F-11 interlock oc 2-TCV-63-80 was identified by review of electrical prints. This intirlock ctuses.the valve to open automatically when the RCS pressure is greater than or aquel
.;o 1,970 pounda per squ re inch.seuse (psig). Discussion with the 505 and Unit i ASOS-took piecex to .dctermine a ecurse- of action to address the.7-11 interlock reistive to FCV43-50L = 2he Unit-12 A505 returned _ to lhe .lomtion of the besaker for valve 2-FCV-63 40 and us.locke:( and closed the breaker salve 2-FCV-6 b40 was then closed by Aho UO the ASOS opened the breaker as soon as . valve indicated closed, and the
? valve' remained closed. Tae Operations Superintendent was not recentacted or. consulted when the incuricek was encountered.
jL ~ The evolution 1mtisued with the opening of valves 2-FC/-43-78, -71, and -84 Once the pressure in tha line was relieved, valves 2-TCV-63-78 and -71 were closed, and the SIS pump 2A was started After this evalution, vaJ.vc 2-FCV-43-40_was opened, the STS pump
- 2A w a stopped, and valve 2-FCV-6'3-44 was closed.
The Unit 2 A50S who performed the manipulations of the valve's mater-operator supply {' breaker, remained in the vicinity o' the breaker when it was not is the locked open position. The evolution was completed with val res .vetvxned to their normal positions at 2032 EST, and 1.C0 3.5.1.1 was exited. To11cving the evolution the ASOS returned to the MCR. - The 505 asked the AS05 if power had beau removed from the operator to valve 2-FC"43-80. The A50S reported taat power had been remo-ed. This was logged in the . 508 and AS05 legs. However, no independent verification was performed following system 1. restoration as required by Al-37, " Independent Verification." AI-37, Section 6.1.2,
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4 l-twquirss thnt breakers in the D.sergency Ceue .'ooling Gyste.s (ICCS) shall be
\i independently verified to b6 in the correu, position anMor condition when the system j or colponent is being returnt.d to service ce restored to a stand-by line up. ne
. p. stated objective of AI-37 is to minimise thi psilbility of human error in the
<i performance of designated activitiec by veriffing that the activity canfor.as to specified requirements.
The nomal cathee cf doeveenting indepencient vartfication is to use clearance sheets, systes operating instruef; ion power availability and valve r:hecklists or AI-58,
" Maintaining C9snizance of Operation Status - Cemfiguration Status Control,"
i Appendix B, " Configuration File Sheets," /.n alluvahit e:4 caption to configuration control reqrirmnts, according to AI-%, was followed. AI-55, Section 2.2.2.1, allows . viceptions to requirese nts for configuration los entxies it "epipment involved is ecutinuously attitored by. operator at local site until it is returned to .40RMAL st.atus." The9e requiriacnts W ra net and accordir. gly no configuration log entries were , made. As a recult of the allowM exception of Al-Sh Operations personnel assumed that j independent verificatiet. was not absolutely esquired, i.e., since the evolution was not , documentd by use above noted normal methods; therefore, an independent verification ei was r.ot,performac, To11owing discovery of power on the v ive on March 1, 1991, an invustigation was , , crinducted to evaluate pote::tial causes _ of the mispositioning of the 2-FCV-63-80 motor ,3 'cycrator breaker. Opsrator lors were roriewed to determine if any manipulations of the bretker occurred between yebrvary 14 and March 1,1991. No e ridence was identified of e,5y 'operatient of the breaker or valve other than that on February 14, 1991. Ju-response to a concern that a manipulation of the breaker for the operator to 1-TCV-63-80-could have occurred but not been b ;rd, an extensive interview process was Jerformed. S054, ASOSs, lead 00s, and balance of planc C r who were assigned tc operate Unit 2 between yebruary la and March 1,1991, were inte: 7tewed. No evidence of any operations other than that on February 14, 1991, was identifieJ during the interview process. , The possibility of an unintenti,nal operation of the breaker to 2 F0V-63-eG. because of a entfusion between Unita 1 and 2, was evaluated. This possibility was considered because of the Unit i forewd outage that occurred between February 18 and 26,1991. No evidence was identified of an uni'ntantional operation. The Operations incident investigation team members performed a preliminary assessment and determined that the event was not reportable under 10 CTR 50.72. This determination was based upon the initial assumption that the event did not constitute a departure from the plant's design basis. As the investigation proceeded, a draft analysis of the event's safety implications was prepared by the incident investigation team. This draft analysis was sent to Nuclear Engineering (NE) for independent review. l 1st fore 364t6 49) LT*d 0";19 Et-9 "in _. M"i 'l.tg/ad'n 3115 HOS _ D :6_0 . . _ _T_66 T /W/M
, s'RC Fem 366A U.S. NUCLEAR REGutsf0RY CONN!5310N spproves OMB No. 3150-0104 (6 t)) Espiree 4/30/92 ** ' LKEEEE EVEU REPORT (LER)
TLIT CONTINuAf!DN FACit1TY hAMC (1) lD0;Ktf NUMBER (2) L '___ tFR NUMBf4 W l 1 PAf;f m l Segueyah Nuclear Plant Unit 2 l l l$[00tNTIAL i lREV!5!0Nl l l l l l { YEAR l l NUMafR l l NUmfr# l l l l l 101M010101312 le 1911 l-loIei11-IeI. O 111 stori 11 r MT (if more space is regvired, use additional NfC Fem 366A's) (17) DISCRipTION OF ICVDIY O On March 22, 1991, at 1646 EET after fi.rther investigation, it was determined that Unit 2 had operated in a condition outside the design basis during the time frame of February 14, 1991, to March 1, 1991, as a result of the bret.ker to 2-FCV-63-80 being in the locked closed position. The basis is that a single failure it, the operator breaker or control circuit could cause the valve to inadvertently close, isclatig the No. 3 CLA. Should this single failure occur following a Loss of Coolant Accident (LOCA), because of a rupture in RCS cold leg loops 1, 2, or 4, only two CLAs would be available for injection. The parameters used in the LOCA aralysis of Section 15.3 and 15.4 of the UFSAR, requires three CLAs to be available for injection. This determination was based on consultation with Westinghouse Elect-ic Corporation LOCA specialists. A one-hour notification phone call to the NRC m made in accordance with 10 1991. CyR 50.72.(b)(1)(ii)(3) as a result of this determination at 1737 EST on fiarch 22, Upon further review, it was determined that the evolution performed would not achieve its intended function to further backseat check valve 63-624 by startf a; of the SIS pump. The leakrate for the primary check valve 63-562 (0.68 rps) was evaluated to be greater than the leakrate for the secondary check valve 63-524 (0.21 spm), using results from the leak rate testing performed before restart from the Cycle a refueling outage. The measured leskrate from testing at reduced pressure is extrapolated to a leakrate at full pressure conditions. The leakage from the RCS into the CLA through this header and not by other means had been previously determined as a result of extensive troubleshooting activities and by confirmation that water samples from both the CLA and RCS were very similar. The pipe header pressure between check valves 63-562. -624, -634 (RER pump, loop 3 cold leg injection secondary check valve), and
-555 (SIS pump, Loop 3 cold leg injection secondary check valve) is therefore considered to have very likely been at approximately 2,235 psig, normal RCS pressure at 100 percent reactor power. Therefore, when the upstream side of check valve 63-624 was vented to the holdup tank the differential pressure across 63-624 was approximately 2,235 psig. Starting of the 2A SIS pump pressurized the line between the pump and check valve 63-555 to approximately 1,500 psig. As indicated, the pressure in the line downstream of check valve 63-555 was approximately 2235 peig. Since the piping between check valves 63-561. -624, -634, and -555 was already at a pressure greater than the SIS discharge pressure, starting the SIS pump would not have applied any further pressure differential across 63-624 It was not recognized at the time the evolution was planned and performed that the downstream side of valve 63-555 was at a higher pressure than what'the SIS pump could achieve.
Review of this evolution also considered whether starting of the SIP could have actuated the other three SIS secondary check valves 63-551, -553, and -557 for loops 1 2, and 4, respectively, necessitating leskrate testing in accordance with SP ; 4.h.6.2.2.d. As designed, the minimum pressure downstream of these check valves, ; assuming no primary check valve leakage, would be approximately 600 psig, the pressure of the CIA When the SIP was started with a 1,500 psig discharge pressure, a 900 paid ! could have been developed across the three SIS secondary check valves in the direction l ef the RCS. NRC (ess 366(6-e9) o7.s m.,o e o e,o ,,i mive r e n mite mv: t-m en TcAT nwon
~ -
pWtf Fcre 366A U.S. NUCLEAR REGULATORY C0fT115510N Approves oms C3, 3)30.ggg4 (6 49) Empires 4/30/92 #
$N N bb 7 CAT t0NTINUATION
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FACILITY h&Mt (1) M KET NUMBER {2) I tra NtsatrR #6) 1 i PAGF (1) l l Sequoyah nuclear Phat Unit 2 l lYEAsl l$EQUtMTIAt l lstV!510Nl l l l l i f Ntnert l l NLSGfR lllll 101sle101013 12 IB 19 11 l l 0 I o I 1 1-l 0 i o i of stori 11 i TEXT (!f more space is required, vse edettional NeC Fere 366A's) (IT) DESCRIPTION OF EvtNT y Bowever, since water is incompressible and the piping between the primary and secondary chec': valves is water solid, the volume of water moved across the SIS check valves
- would be extremely man 11. If it is conservatively assumed that the CLA check valves
(-622, -423, and -625) were leakins' back to the CIAs (although there has besh no indication of level or concentration changes), the most water that could have been noved across the SIS check valves would be approximately the leskrate of the CIA check valves measured during testa conducted at startup from the last refueling outage (on the order of 0.26 to 0.32 gpm). From this review it is concluded that the evolution did not result in actuation or " flow through the valve" as intended by SR 4.4.6.2.7.d and therefore testing to reverify check valve leskrate was not required. As a result of further review of this evolution and the associated TS and design and licensing basis, it- is concluded that the CLA isolation valve 2-FCV-63-60 should not have been closed. TS LCO 3.5.1.1, Action Statement "b" states: "With one cold leg injection accum.tlator inoperable due to the isolation valve being closed, either immediately open the isolation valve or be in 50T STANDlf within one hour and be in HOT SHUTDOWN within tha next 12 hours." The corresponding bases states t "If a closed isolation valve cannot be issoediately opeed, the full capability of one accumulator is not available and promat action is required to place the reactor in a mode where this capability is not required." The review of this TS action statement and bases by the involved Operations personnel, concluded that the isolation valve could be imusediately opened and the action could be met by stationing individuals at the valve contrel and breaker to isusediately reopen the valve in event of an accident, and' by ensuring that the evolution was completed well within an hour. It was further reasoned that this avointion was_less "sewere" than the periodic accumulator drain and refill evnlutions that were being necessitated by the check valve back-leakage. However, fo11owing further review of the technical specifit.ation action statemenc as written and the accident analysis, as further detailed in the analysis section..it is concluded that intentional closure of the isolation valves should not occur in Nodes 1, 2, 3, and with pressurizer pressure above 1000 pais. l CAUSE OF EVENT The idrect cause of this event is attributed to inappropriate perronnel actions in placing the breaker in the locked closed rather than the locked open position. The cause of that' incorrect action could not be' determined. Discussion with the A508 indicated his belief that the breaker was locked open. A contributo:- to the event is l lack of independent verification. Independent verification of manipulations of ECCS components is required by AI-37, however personnel believed that independent verification wcs not required given the process and procedures that were being used for this evolution. l l AI-37 rnquires independent verification for the temporary alterations of removing and returning ECCS systems from and to service. AI-30 provides infonnation relative to
" system configuration control of CSSC safety related systems" and controls for implementing limited evolutions without formal procedures. AI-30 also refers to AI-58 l NRC Torm 364t6 496 l
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NRC Foro 366A U.5, NOCIEAR RtGULATORY OMMIS$10N Apprew;d oms No. 3150 0103-(6-49); # ' Expires 4/30/92 (KENSEE EYST 00RT (LER) TEXT CONTINUAf!0N FACILITY NAME (1) l DOCKET Nutt9tR (2) ] t FR #ftPastR fi) l i PAPF f3) l l l l$t00 TNT [AL l l REY!SIONl l l l l Seeveysh Nuclear Plant (Mit 2 IVEAE I ! N18EER l I l NtMFR l l l l l f otstelchf 312 f e 19 11 lie!ol3 fIo! oIof7 tert 111 TEXT (If more space is re<tutred, use seditional NRC f pne 3t&A's) (17) CAU$3 0F EVENT 4 for a detailed description of maintaining the alignment of these systems in accordance with their appropriate valve and power availability checklists. AI-58 lista exceptions ' to configuration los entr;es for specific activities including limited evolutions. Implementing the subject evolution in this manner eliJninated the normal method of
- documenting independent verification and led the Operations personnel to believe that independent verification was not absolutely required. Additionally, the SOS had a high' level of confidence in the performance of the involved A505.
The root cause of this event, however, is considered to be the judgement made that this activity tonstituted a limited evolution not requiring a procedure. While AI-30 provides flexibility for licensed personnel evaluation of the condition and therefore did not specifically prohibit this judgement, TVA considers that this activity should clearly have been recognized as being outside the scope of the limited evolution process. Further, when the F-11 interlock was encountered during the evolution this should have further indicated to the personnel involved that the activity was not a limited evolution and that a procedure was-required. Had a procedure been prepared it is believed that the technical issues would have been appropriately-identified and addressed. Additionally any evolution involving manipulation of ECCS components would have required written independent verification of return to normal. A contributing f actor- to the incorrect judgement is considered to be an inadequate proevolution l review. The review performed consisted of review of the flow diagrams to assess the flow paths, the TSa, and peer review among several SR0s. However the review did not include review of electrical, control or logic prints nor did it adequately assess TS and TSAR impact / significance. As a result of discussions concerning this evolution sith Operations management and operating personnel it is concluded that inadequate . training has been provided to ensure appropriate and consistent implementation of l Usited evolutions. l- The error in the initial reportability determination is considered to have resulted I from lack of engineering involvement in the assessment relative to design basis. ! ANALYSIS Or gvENT This event is being reported in accordance with 10 CTR 50.73, paragraph a.2.1, as an operation prohibited by TS 3.5.1.1 and 10 CTR 50.73, paragraph a.2.11, as a condition that was outside the design basis of the plant. With the breaker for the isolation valve locked closed (i.e., power to the valve), instead of locked open, a potential exists that a spurious active . single failure in the ccmtrol circuit could cause the valve to inadvertently class, isolating the No. 3 CLA. Locking open the operator breakar'(i.e., power removed) prevents a spurious active
- single failure.
Should this single failure occur following a large break LOCA because i
- of a rupture in RCS cold leg Loops 1, 2. or 4; only two CLAs would be available ~ for injection. The parameters in the LOCA analysis described in UTSAR, Section 15.4, requires three CLAs to be available for injection; assuming one of the four CLAs is lost to the sump through the break in the cold leg.
MAC Foam 364 4 -49) pa . npo no ao w m ? v @ 31 M t fW "@ MWW 'T
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NeC Fore 366A U.S. I L R REGULATORY COMMISSION- Approved oms No. 3160-0104 (6 49) !=pires 8/30/92 *
- l LKRSEE EVM ltEE (Lat Ttxt CONTINUATION ;
FACILITY MAft (1) l00CKETNut9ER(2).I tra mLipara fa) l I pat:r f,L l J $egveyAh Nuclear Plant Unit 2 l l l3t90EllTIAL l l REY!510Nl-l l l l l . lyrAn I i nassats - 1 I wtmara l l g l l 1e1510101011 12 la le 11 l_I e I e 13 l_l cI e I of stori 11 1 ftXT-(3F more ssace is reevired vse addittenal Nat Form 366A's) (IT) ANALY5n 0F EVDfT
?
An example of spurious active single f ailure -is the unintended energising of a power-operated valve to open or close. Spurious f allures may occear independently of ' the component's environmental surroundings. Spurious operation is the change in equipment state because of electrically induced faults. Thus with power removed, no active failure of the valve may be postulated to occur. Upon swayover to recirculatida from the sump,=a passive failure may be assumed; however, the borated water in the
.CLAs would have already been discharged to the RC5.- Therefore removing power assures three C1.ts will be capable of injecting into the RCS An the event of a RCS cold leg LOCA,' and- thus the design basis will be satisfied.
With the breaker to, the operator of 2-TCV-63-80 locked closed, the postaccident peak clad temperature (PCT) could exceed the design limit, provided a_large break LOCA occurs in: the- RCS cold les pressure boundary piping -loops 1, 2, or 4, and a single spurious failure is applied to 2-TCV-63-80 (valve-fails to remain open).-thus resulting in the elimination of one.of the three-remaining available CLA's. An additional train of-ECCS (assumed to exist since the single failure occurred in the spurious actuation of 2-FCV-63-80) would be available, but would not supply sufficient. flow to substitute
-for the loss.cf a CLA. This is because of the-inability of the ECCS pumps to deliver
-the required' volume of water (equal to or greater-than an accumulator discharge) in the short time interval necessary. Because of the not loss in delivered flow, the time to resubmerge the bottom of the fuel af ter initial core uncovery, would be extended-by more than 12 seconds and PCT could exceed the design limit.
SQN's Indiv2 dual Plant Evaluation for COMPONENT TAILURE RATES generically documents failure rates for various type _ components ~in the plant. . The failure rate for a motor operated valve'(fr.iluro to: remain in its normal position open or close<!L is_ 1E-7/ hour. An additional analysie showed that the conditional _ probability of a'large break LOCA t and one CIA motor operated isolation valve -closing is negligible over .t Jeriod of :14 _ days. The conditiona1' probability of these two events, both occurring within a 14-day
- period, is 2.622-10.
The-limiting break sise in terms of-highest FCT for:a small break LOCA is a 3-inch
=diame ter break'. The depressurisation transient for this break is shown in UTSAR Tigure 13.3.1-1. -The extent-to which the core is uncovered is shown in UT5AR Tigure _15.3.1-3. - Tor a small- bteak: LOCA and -a failure of valve 2-FCV-63-80 to remain--
open,' the PCT'would not exceed 2,200 degrees T.
" Beyond purely spurious fallures, an evaluation was also conducted to determine whother closure of: the isolation valve- (which is not specifically environmentally qualified) could be expected to' result from-environmentally induced accident conditions. The results of this evaluation concluded that it is not expected that a' harsh environment
# would cause spurious actuation and closure of 2-TCV-63-80 during- the time period under which closure could adversely-affect calculated FCT.
I NRC form 346 M.43)
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2 . 8SC Fcre 3%A - U.S. ALCAR acGPLMCnY C0ml1310N
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MN N kk IExT tDNfIMUAIION FACIL17Y MAfC (1)- l00CKET NUtstR (2) I tra uusera es) 4 1 ,AGF
\ l lequerah Nuclear Plant Unit 2 l lyrAs lll$t90tMIIAL l uusera l l REVISION l l l l [
i l'uusera l l- { g l. teltlalale h 12 la le 11 1-1oIel 3 f ~l el e I el elort il f tXT (If more space is regetred, use addittenal NRC Fors 366A's) (17) MA1Y318 0F EvD_fT > 4 <' In review of t'.s actual conditions over the _ subject period, it is noted that valve 2-FCV-63-40_ remained open following this evolution during the time period - the bremar was in the locked closed (power on) position (February la to March 1,.1991). The-period of- time that the valve was closed during the evolution was a short duration and positive-controls were in place to inmediately reopen the valve in event'of an accident condition. There were no challenges to the ECCS during this time f rame and no accumulator failures occurred. Isolation valve 2-TCV-63-80 is checked each shift to , l eneure.that 1s required by theT5valve is open in accordance with 2-5I-OF5-000-002.0, " Shift Log," which-SR 4.5.1.1.1. No deviations of the valve from the open position were identified during the approximate two week time frare. Although the potential existed to challenge the design basis, there were no challenges to the ECC5 or failures of 2-rCV-63-80, and therefore this event did not adversely-affect the health and safety of the public. CORRICTIVE ACTIONS Isumediate corrective action was to place the breaker for the operator for 1-FCV-63-80 in the locked open position. 1: The Flant Manager'has-discussed with the Operations personnel involved with this event-the- importance- of performing independent verification for activities affecting nuclear safety. 1The Operations Superintendent has discussed with each of the Operations crews the: circumstances of this event and-the importance of performing independent verification in accordance with AI-37.- Additionally the-operations personnel involved I in this event will ret elve appropriate disciplinary action by April:19,1991. l-j' To provide interim controle until associated- procedures - are- revised.. a night order was issued-by the Operations Superintendent to (1) require the- Operations Superintendent's approval before performing a limited evolution (i.e., without a procedure) until further training $s'provided, (2) to require discussion with the operations
. Superintendent if so unexpected response is encountered during a limited evolution and L
! (3) to clarify' that the independent verification requirements of AI-37 applies- to; component manipulations regardless of the AI-58 method that is used to control the configuration. Associated procedures will be revised to further clarify the need_for [ t independent verification by May 15,.1991.
> While WA believes that tho' subject activity enculd have been_ eenducted with an
- approved procedure,- WA also believes there sti?.1; remain certain simple manipulations involving deviations from normal configurations:that-should properly be considered operation of the. facility rather than changes in the-facility. For certain simple, short duration-manipulations that will not require a bypass of permissives and for
'which direct positive control is maintained, generation of special procedures is not considered warranted and could impede reasonable facility operation. However TVA recognizes'that these evolutions must be adequacely and consistently controlled.
NRt form 344(6-e9)
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NAC F re 366A U.S.toutLEARREGUL/'ORYC0tv1'b!CN Appesved OMB N]. 3150-0103 4 49) tmPtre 4/30/92 " MN N Nf h TEXT CONTINUATION FACILITT NAME (1) l DOCKET NUP$tR (2) I tfR NtMFR f E1 l l PArr ts) l Segweysh suelear Plant Unit 2 l l l$EQUENTIALl lREVIIJNl l l l l lYfAR I I MtM rR l I I MusdrR _I l l l l 101510lgt10h 17 la 19 11 1-10 f a 11 l_t a ! O l 11 olori if TEXT (If more space is required, use additional NRt Form 366A's! (17) C010t!CTIVE ACTIONS q , Additional criteria for evaluation and conduct of limited evolutions is being developed by TTA based on Operations management end personnel input, regulatory requirements, and s input f roni other utilities. Bypassing of interlocks will be specifically disallowed ender limited evolutions. A resultant training package is being prepared which*will be provided to all licensed personnel. Additional guidance will be incorporated into associated procedures as appropriate. TVA is ndditionally evaluating whether an additional temporary procedure process shoult be established to handle activities / evolutions that are beyond the scope of limited evolutions but do not warrant development of a new formal procedure. To provide clarification and promote consictancy in future interpretation of T3 3.5.1.1 Action b, Operations management will review the position that intentional closure of the cia isolation valves in Modes 1, 2, 3, and with pressurizer pressure above 1000 psig should not occur with licensed personnel. TVA is additionally evaluating current processes / interfaces used to support initial reportability determinations, with particular reference to nuclear engineering involvement. This evaluation will be completed by April 15, 1991, end soverning procedures / processes will be revised as appropriate. ADDITIONAL INy0RMATION Previous mispositioning events were reviewed to determine if an event resulted from similar causes. None were identified such that corrective actions taken should have reasonably been expected to prevent this event. Inspection Report Nos. 50-327/89-15, 50-328/89-15, and Notice of violation 89-15-05 involved making a change to the facility as described in the FSAR without performing a written evaluation to determine whether the change involved an unreviewed safety question. The change involved taking the baron injection tank (BIT) out of continuous recirculation, resulting in the low flow alarm actuating and rendoring the BIT inoperable. There was no procedure used to initially isolate BIT recirculation. Corrective action for this violation included a revision to AI-30 to define the conditions and controls under which manipulations can be performed without procedures. This revision was tisde wiM the intent to provide flexibility to address any number of unforseen simple se g vica, however, in hindsight, additional detail or training should have been provided to susure appropriate and consistent irplementation._ CC19 FITMENTS
- 1. Associated procedures will be revised to further clarify the need for independent l
. verification by May 15, 1991.
l 884C form 366(H9) _. ,.,_,,,y . ..- ,,,e a ^ oivc*n- c *- c " ' c c ' *" "
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-LKENSEEEVENTREPORT7iER) .
TEXT conf!NuAf!M
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FACILITY NAMC (1) l00CKti NUMBER (2) i tFR gamera ft) l l PAff f1) l l _l-(StoutMTIALl: lnty!s!0nt - l:--l l (:: . i Segworen heclear Plant Unit, 2 l: ; lvr_Aa l I maare t; I annenra 1 l ~ l l l - 16!s101010l317 la le it i I o 10131 t n I e i 1I ilarl 11 , TEXT (If here space is reestree. use additlenal NaC Form 364A's) (17) C0tMIM >
.2. Additional criteria for evaluation and conduct of limited evolutions ~is being developed by TVA based en' operations management and personnel input, regulatory t rettuirenents, and input from other utilities. Bypassing of interlocks will be ,
specifically disallowed under Limited evolutions. A resultant training package is-
)
being prepared which will be provided'to all licensed personnel by April 26,J1991.
.3. Additional guidance-(regarding limited evolutions)-will be incorporated-into-associated. procedures as appropriate by April 26, 1991.
{
- 4. 'To provide clarification and promote consistency in future interpretation of T5'3.5.1.1, Action b, Operations management will review the position that .
intentional closure of-the C1.A isolation valves should not occur with-licensed personnel by April 19, 1991.
- 3. TVA-is-additionally evaluating current processes / interfaces used to . support initial reportability determinations, with-particular reference to nuclear engineering involvement. This evaluation will be completed'by April 15, 1991.
- 6. Governing procedures / processes will be revised.as appropriate as a result of comunitment Number S.
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-NRC fore 366(6-49)-
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~, NUCLEAR REGULATO3Y COMMissl0N mg GION 18 g 101 M ARIETT A STREET, N.W.
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..... # APR 2 51991 Docket Nos.: 50-327'and 50-328 License Nos.:- DpR-77 and OPR-79 Tennessee Valley Authority ATTN: Mr. D. A. Nauman .
Senior Vice President, Nuclear Power 6N 38A Lookout Place 1101 Market Square Chattanooga, TN 37402-2801 Gentlemen:
SUBJECT:
NOTICE OF VIOLATION (NRC INSPECTION REPORT NOS. 50-327/91-06 AND 50-328/91-06) This refers to the inspection conducted by P. Harmon of this of fice on March 6
- April 5,1991. The inspection-included a review of activities authorized for
- your Sequoyah 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 ere identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative racords, interviews with personnel, and observation of activities in progress. Based on the results of this inspection, certain of your activities appear to
- violae NRC requirements, as specified in the r- .osed Notice of Violation. -
We. are concerned Mut this violation bsccuse .. dependent verification is a very important step in providing adequate- aswrance that critical safety systems will-carry out their intended function. This concern is amplified by a recently reported additional example of lack of adequate second narty verifi-cation :that contributed to a carbon dioxide fire suppression system being inoperable for a year. In addition,' we are concerned with other. aspects of the
- operators '- perfonnance during this event including perfonning _ a non-routine evolution without a written procedure and byphssing a protective grade interlock without a detailed review. Please include a discussion of these issues with your response Jo the violation. - Because of these events and concerns we are not exercising discretion as allowed by Section V.G 1. of the Enforcement Policy even though- the events were identified and reported by TVA.
Two additional examples of apparent. violation 50-327, 328/3-04-01 were identified where operators failed to properly acknowledge control room alanns
. as required by AI-30. An Enforcement Conference was held on April 12, 1991 cor.cerning operator responsiveness to alarms as described in Inspection Report 50-327, 328/91-04 and the two examples described in this report were noted in
-99093>sco77-20*d 05/.,8 EP9 ST9 ~Jt7 3115/*d'A 3115 tt05 ECJ60 166 tern MO
AFM 5 6 155) Mr,'O. A. Nauman 2 that conference. Consequently, -these additional *=imples will be considered in our deliberations to determine the appropriate enforcement actions for operators failing to properly respond to control room alanns. You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response, in your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. Af ter reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements, in accordance with 10 CFR 2.790 of the NRC's " Rules of Practices," 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, PL 96-511. Should you have'any questions concerning this letter, please contact us. Sincerely, , 1 s cL
- J M uce A. Wilson, Chief
'TVA Projects
Enclosures:
- 1. Notice of Violation
- 2. NRC Inspection Report cc w/encis: _
(See page 3) bb a
_ . ~_ . . . . . . . .. ._. _ . . . . . . _ . . . . _ . - . . .. . ,. . [# v n d 3 lygt- : 5'4- : Mr.-D..A; Nauman-3 + s
-cc w/encis*
-M. Runyon; Chairman _
R.-BeeckenPlantManager-[ Tennessee Valley Authority Sequoyah Nuclear Plant . ETL12A-7A1 - Tennessee Valley Authortty 400 West Sumit Hill-Drive
- P. O. Pox 2000 -
-Knoxville, TN* 37902- - Soddy-Daisy, TN 37379 J. - 8. Waters', Director- _
E. G.1Wallace, Manager V
- TennesseeLValley Authority Nuclear Licensing and ET:12A 9A Regulatory Affairs
-400 West Summit Hill Drive Tennessee Valley At tority Knoxville,tTH =37902 :SN 157B Lookout P, lace
. Chattanooga, TN 37402-2801 W F. Willis
< Chief-Doerating Officer? M. Cooper-ET 128 168- .
Site: Licensing Manager / 400 West Su'mit Hill' Drive- Sequoyah Nuclear; Plan 0 > Knoxville, TN 37902? P. O. Box 2000
;D. Nunn,-_Vice President
- Nuclear Projects --- -.
TVA Representative
" Tennessee Valley' Authority. Rockville Office
- 1101 Market Street -11921 Rockville Pike 6A Lookout Place . Suite 402
- Chattanooga, TN ; 3740242801: Rockville, MD 20852
' Dr." M. O. Medford. General Counsel
!Vice~ President,-Nuclear Assurance, ' Tennessee Valley Authority
- Licensing and Fuels- . 1400 West-Sunnit Hill Drive
= Tennessee Valley Authority- ET 118 33H 6N?38A Lookout-Place Knoxville, TN' 37902
; Chattanooga, TN: 37402-2801
'*- . M'ichael H. Mobley,: Director _.
CountyJJudge- - Division of Radiological -Health-Hami1+.on County Courthouse 'T.E.R.R.Ae Building, 6th Floor-Chattanooga, TN 37402; 150 -9th Avenue North = Nashville, TN f37247-3201 N J. Wilson, Site Vice President Sequoyah Nuclear Plant TennesseeLValley Authority P. O. Box 12000-Soddy-Daisy, TN-.37379 State of Tennessee-m L
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EN_ CLOSURE 1 NOTICE OF VIOLATION Tennessee Valley Authority Docket Nos. 50-327, 50-328 Sequoyah License Nos. DPR-77, DpR-79 9 During the Nuclear Regulatory Connission (NRC) inspection conducted March 6, 1991, through April 5,1991, 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 (1990), the violation is listed below: Technical Specification 6.8.1 requires that procedures recommended in Appendix A of Regulatory Guide 1.33 Revision C, be established, implemented and maintained. This incisdes maintenance, operating, surveillance, adminis tra tive , and fuel handling procedures. The requirements of TS . 6.8.1 are implemented in part by Administrative Instruction AI-37 Independent Verification, sect. ion 6.1.2 which states that breakers in the Emergency Core Cooling System shall be independently verified to be in the correct position / condition when the system or component is being returned to service or restored to a standby line-up. Contrary to the above, on February 14, 1991, the breaker for the Unit 2, Number 3 cold leg accumulator isolation valve was manipulated during a non-routine evolution, without performance of any-independent verification as required by AI-37, Independent Verification. This resulted in the breaker being left in the energized condition during plant operation contrary to the FSAR desSo basis. This is a Severity Level IV violation (Supplement I) Pursuant to the provisions of.10 CFR 2.201, Tennessee Valley Authority is hereby required to submit a written statement or explanation to the Nuclear Regulatory Comnission, ATTN: Document Control Desk, Washington, DC 20555, with a copy to the Regional Administrator, Region II, and a copy to the NRC 81esident / Inspector, Sequoyah, within 30 days of the date of the letter transmitting this / Notice. This reply should be clearly marked as a " Reply to a Notice of Violation" and should include (for each violation): (1) the reason for the violation if admitted, (2) the corrective steps which have been taken and the results achieved, (3) the corrective steps which will be taken to avoid further violations, and (4) the date when full compliance will be achieved., If an adequate reply is not received within thr time specified in this Notice, an f fQ[K)$f ses e= ., - , m . . . ,= - ye 1mme -,
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Tennessee Valley Authority 2 Docket Nos, 50 3:7, 50 328 l Sequoyah License Nos. DPR 77, DPR.79 ; order may be issued to show cause why the license should not be modified, , suspenaed, or revoked or why such other action ct may be proper should not be i taken. Where good cause is shown, consideratiot will be given to extending i the-response time. ! THE NUCLEAR REGULATORY COMMISSION i
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rvce A. Wilson, Chief TVA Projects Dated at Atlanta, Georgia this_ll$kday of April 1991 ; Y t i y i e l' on ' 8 mt?o ego cvo , , ,, . y m gite p.a,.p y ite npy:_ . e77en _7 ec t f,,n fan
15 ; (Closed) LER 328/89-13, Incorreu Smake Detectors Located in Unit 2 Annulus Fire Zone 374 Due to Personn" Frror. The event 'vr4 the installation of three ionization detectors instead of phot
- er.c m-type devices. TS 3.3.3.8, Table 3.3-11 reouires 20 ,
photor'%.' 7 detectors to be operable in the subject fire sone. However , due to . ..:orrect replacement only 19 were installei and operable. The investigation determined two of the detectors were replaced in 1905 and the other replacement was unable to be established, in the time frame of the replacements, craftsmen had the responsibility for identification of the correct replacement part. The WR program at this time, as described , in Sequoyah Standard Practice $0M2 gives planners the responsibility for identification of the proper replacement part. Six other fire zones were . inspected to determine if any other incorrect type detectors were ' installed. No other problems were identified. The in!pector reviewed the corrective actions and the LER closecut package. This LER is closed. 1
- 8. EventFollow-up(93702)
On March 1,1991 at 1:27 a.m. the breaker for the motor operator on the Unit 2 no. 3 cold leg accumulator isolation valve was found locked in the closed position. 1he isolation valve, 2-FCV-63-80, was open. Ciscovery of the closed breaker was made during perfonnance of monthly surveillance SI-0PS-063-013,0, CLA Valves Power Removal , Verification.- Upon discovery of the closed breaker, operators , removed power and the breaker was locked in the open position at 1:31 a.m. An incident investigation into the event determined that the
?-FCV-63-80 operator breaker was manipulated on February 14, 1991 as part of an evolution performed to reduce the inleakage to the #3 accumulator. The evolution required the tempor?ry closure of the isolation valve, via the motor operator, in an f ttempt to seat the leaking check valve fsr that accumulator. The brecker fer the valve was energized and the valve closed, but an interlock, permissise P-11, actuated to reopen the valve imediately. P-11 operates to automatically open the isolation valves for the accumulator whenever RCS. pressere is above 1970 psig. Operators reviewed the logic circuitry and determined that the P-11 interlock had in fact reopened I the valve. A decision was then made to close the valve, and then 1enediately open the breaker to provont the interlock from reopening the v&lve. This was . done successfully, but without written procedures. After the avolution was cor.. 'eted, power was restored tc.
the breaker and the valve was _ r opened. 'he ASOS performing the evolution at the breake" then was requirec to remove power. from the breaker and lock the breaker open. The C J . ... sn later ' interviews that he was positive that he had reopened the breaker and locked it in the open position. The event investigation concluded that he had mistakenly locked the breaker in the closed (enercized) L position. L __ - > n * .s _ ove Ne me _ ._ _ y -* a i t e q.J 'o ylt e_ me, _ or_. crs__Jccq$NPn _ _ __
of . 16 '. h Several issues of concern were identified for this event:
- Operators did not provide independent verification of the position of the breaker as required by Al 37, Independent Verification.
- Non-routine evolution; were performed without written procedures.
- The Protective Grade interlock, P-11, was defeated by opening the breaker when tha isolation valve was closed without adequate review on theapart of the Operations crew. -
As the investigation into ti.e event continued, the Ifcensee determined, on March 22, 1991 that due to the breaker being energized, the plant had been operating ia en area outside the PSAR design basis from February 14 until March 1, 1991. The isolation valve is required to be open to meet the req'.lirements of TS 3.5.1.1 for operability of the cold leg accumulators. T5 surveillance requirement 4.5.1.1.1.c requires that each cold leg accumulator shall be demonstrated operable "At least once every 31 dm when the ?CS pressure is above 2000 psig by verifying that power to tne isolation valve operator is disconnected by removal of the breaker from the circuit." The TS Basis describes the reason for the requirements to remove power to the valve operator. Basis 3/4.5.1, Accumulators, states that 'The accumulator power operated isolation valves are considered to be operating bypasses in the conWt of IEEE std. 279-1971, which requires that bypasses of a protective function be removed automatically whenever permissible ' conditions are not met. In addition, as these accumulator isolation valves fail to meet single failure criteria, removal of power to the valves is required." The concern articulated in the basis is that a single failure in the operator breaker or its control circuit could cause the isolation valve to inadvertently shut, causing the loss of the accumulator during the postulated accident. . The various issues in this event were still under investigation by
'the licensee at the end of the reporting period and will be addressed in a final incident Investigation and a LER.
The inspector noted that there were elmnts of this event which were similar to the Boron injection Tank event described in IR 50-327,328/89-15. Bot 5 involved manipulation of ECCS equipment without approved procedures. e,j ., f,,~, --, - , ,,, ._,. y .,,, ,. ,- . .c , , c e , ,,,, , e,
17 Al-37, independent Verification, section 6.1.2 states that breakers in the Emergency Core Cooling System shall be independently verified to be in the correct position / condition when the system or component is being returned to service or restored to a standby line-up. Tailure of the oport t.'ng crew to follow the requirements of A137, independent verification is a violation and will be tracked as VIO 50-327,328/g1-06-01.
- 9. Exit Interview (30703)
The inspection scope and findings were sumarized on April 9 and 15; 1991, with those persons indicated in paragraph 1. The Senior Resident inspector described the areas inspected and discussed in detail the inspection findings listed below. The licensee acknowledned the inspection findings and did not identify as proprietary any of the material reYiewed by the inspectors curing the inspection. Inspection Findings: One violation was identified. VIO 327,328/91-06-01 Failure to Follow Requirements of Al-37, Independent Verifications for Accumulator Isolation Valve Breaker. Two additional examples of a previous violation (91-04-01) involving operators failirg to follow the requir*wents of Al-30, Conduct of Operations, in responding to alarms were identified. The actions taken during a turbine runback and subsequent actuation of a rod insertion limit alann were discussed. The Operations Supervisor agreed to review and revise the Annunciator Response Instruction and provide additional training for operators for responding to this alarm. TVA staff response to a reactor coolant pump oil leak was considered thorough and measured, with the proper safety consciousness applied to restore the oil level without a p' ant shutdown. A strength was noted in the ALARA preplan and radcon coverage for the necessary containment entries. During the reporting period, frecuent discussions were held with the Site Of rector, Plant Manager and other managers concerning inspection findings. The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspection.
- 10. List of Acronyms and initialisms AHU - Air Handling Unit Al -
Administrative instruction ALARA - As Low As Reascnably Achievable m.s , .- - _.- - . - . . . . . . . . , . . - , , - , ...c , ,c.,,,-, _,}}