ML19308B770
| ML19308B770 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 10/02/1979 |
| From: | Liberman J BERLACK, ISRAELS & LIBERMAN |
| To: | Evans D NRC - NRC THREE MILE ISLAND TASK FORCE |
| References | |
| TASK-TF, TASK-TMR NUDOCS 8001170271 | |
| Download: ML19308B770 (1) | |
Text
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9 l5 BERL ACK,lS R AELS & LIBER M AN 26 8 ROADWAY I
NEW YORK 10oo4 Mranis.EnLAcn coanEN
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CA.LOS L.tSRAELS aANE MLEIN 248*6900 CABLE! BERILf g
NICHARO J. LUGASCH WASHINGTON, D. C. kOO36 uAnca.LASur (aDa) est.9eoc October 2, 1979 David Evans, Esq.
NRC/TMI Special Inquiry Group U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Re: NRC/TMI Special Inquiry
Dear Mr. Evans:
This will confirm for our respective records that, during the course of Mr. Graham's deposition on September 26th, he furnished to you at your request copies of the applications submitted prior to the TMI-2 accident to Standard & Poors and Moody's by Met-Ed.
(Copies of those documents are being furnished to Mr. Wilson for the TMI document room.)
You also requested, and there are enclosed, the
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following:
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[i[g}S 1.
A memorandum, dated December 28, 1978, by Messrs. Daley and TF.ren to Messrs. Condon, Dieckamp, Graham, Holcombe and Kuhns relating to an IRS private %y N d
ruling [actually an IRS National Office Technical Advice Memorandum], dated May 8, 1978, and a copy of that private ruling; and 2.
A copy of the billing statement of the Pennsylvania-New Jersey-Maryland Interconnection for the month of July 1979.
Ve truly yours,
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mes B. Liberman JBL/ac Enclosures cc: Mr. John Wilson (w/ encl.)
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..e U. S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT REGION III Report No.
50-346/79-06 Docket No.
50-346 License No.
NPR-3 Licensee:
Toledo Edison Company Edison Plaza 300 Madison Avenue Toledo, OH 43652 Facility Name:
Davis-Besse Nuclear Power Station, Unit 1 Investigation At:
Davis-Besse Site, Oak Harbor, OH Babcock & Wilcox Office, Lynchburg, VA Investigation Conducted: January 6, 14,.29, 1979 Investigator:fy.4?.-f. 7lwi -
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Nuclear Support Section 1 Invest 12ation Summary Investigation on Januarv 6,14 and 29,1979 (Report No. 30-346/79-06)
Areas I vest 12atecI Inspector concerns regarding loss of pressurizer level indication and violation of technical specification table 3.3-4 involving setpoint settings to 90% undervoltage relays.
The investigation involved 72 inspector-hours onsite by two NRC personnel.
Results:
No ite=s of noncompliance were identified.
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Toledo Edison Company In accordance with Section 2.790 of the NRC's " Rules of Practice,"
Part 2, Title 10, Code of Federal Regulations, a copy of this letter and the enclosed inspection report vill be placed in the NRC's Public Document Room, except as follows.
If this report contains information that you or your contractors believe to be proprietary, you must apply in writing to this office, within
~~
twenty days of your receipt of this letter, to withhold such information from public disclosure.
The application must include a full statement of the reasons for which the information is con-sidered proprietary, and should be prepared so that proprietary information identified in the application is contained in an enclosure to the application.
Vs will gladly discuss any questions you have concerning this inspection.
Sincerely, James G. Keppler Director
Enclosure:
IE Investigation Report No. 50-346/79-06 ce v/ encl:
Mr. T. D. Murray, Station Superintendent Central Files Reproduction Unic NRC 20b PDR Local FDR NSIC TIC Harold W. Kohn, Power Siting Commission RIf,,,
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INTRODUCTION f
licensed to the Toledo The Davis-Besse Unit 1 Nuclear Power Plant, Edison Company, is an operating plant located near Oak Harbor, Ohio.
The facility has been in operation for approximately two years, and utilizes a Pressurired Water Reactor desirred by the Babcock & Wilcox Company (B&W).
Bechtel Power Corporation was the Architect-Engineering Firm for the plant.
REASON FOR INVESTIGATION Subsequent to his review of first cycle power operations at the Davis-Besse Nuclear Power Plant, an NRC Region III (RIII) inspector indicated concern s relative to operation of the facility.
The inspector indicated two areas of concern warranted an NRC investigation, as that he felt they appeared to reflect a lack of timely analysis of a possible safety The first problem, and possible unsafe operation of the facility.
area of concern was related to a loss of pressurizer level indication The (LOPLI) which occurred during a loss of offsite power transient.
the plant had operated with its 90%
second area of concern was that under.oltage relay setpoints below those specified in the Plant Technical 5,eci'.ications, which could have resulted in delayed e=ergency system Discussions with the inspector developed specific questions response.
within each broad area of concern.
An investigation was initiated into these concerns.
"^= P00R~0RIGINAL on Dece=Ser 19, 1978, the RIII inspector advised the Chief, Reactor Operations and Nuclear Support Branch RIII, of concerns related to LOPLI and pressurizer voiding.
On February 29, 1979, discussions with the inspector indicated that he was also concerned that the licensee
- change, had delayed i=ple=entation of an undervoltage relay setpoint possibly delaying Emergency Core Cooling System (ECCS) response had'it been needed prior to the change.
Within the area of LOPLI, the inspector indicated that he questioned whether a timely analysis of the phenomenon had been perfor=ed, and if it was a generic occurrence at Babcock & Wilcox (B&W) reactor facilities.
He also questioned whether feedwater design was unique, and whether
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's LOPLI indicated a' violation of General Design Criteria 13 (instrumen-cation and control).
With the area of the undervoltage relay setpoint, the inspector questioned whether the setpoint delay was deliberate, and if ECCS would have been delayed prior to the setpoint change.' He also questioned the relationship of the setpoint imple=entation delay to a Safety Features Actuation System (SFAS) test.
RIII personnel visited the Davis-Besse site on two occasions, and reviewed records related to the undervoltage relay setpoint change.
Correspondence between the licensee and NRR related to the relay was also reviewed.
A visit was cade to the B&W office in Lynchburg, Virginia where discussions were held with B&W and representatives of several utilities operating B&W plants.
Docu=ents related to analysis of LOPLI were also reviewed during these visits.
It was found that LOPLI has occurred at several B&W plants, with an analysis of the pheno =enon being performed by B&W in 1975.
A letter indicated that B&W ud advised Davis-Besse of the possibility of LOPLI prior to operation.
B&W personnel: advised that their analysis of LOPLI indicated core coverage would be =aintained during analyzed reactor transients, ECCS would initiate when pressure dropped to the ECCS setpoint, and f unction properly.
Discussions with Toledo Edison (TECo) representatives, and doce=ents reviewed indicated that TECo discussed LOPLI with B&W shortly after LOPLI was exper-1enced at the Davis-Besse facility, and had been pursuing =easures to limit LOPLI with the vendor.
Discussions with B&W personnel indicated the feedwater system for the Davis-Besse facility differs from that of other B&W plants.
The auxiliary feedwater pu=p system for Davis-Besse consists of two 100% pumps, each feeding a stea= generator (a connecting pipe and valve is designed to open only should one pu=p fail).
At other B&W plants, B&W personnel advised that the auxiliary feedwater syste= consists of three pumps of approxi-mately 80% capacity, which feed a co==on header to the steam generators.
B&W personnel stated that the LOPLI was an operational probles, not a safety problem, since the pressurizer cannot fully e=pty without a drop in the main reactor coolant syste= pressure.
They advised that such a pressure drop would cause the High Pressure Injection system (HPI) to function, =aintaining core coverage.
A recent submittal to the Office of Nuclear Reactor Regulation (NRR) by Toledo Edison, (Dece=ber 22, 1978) contains their analysis, and indicates that if the pressurizer should void, small voids would form and flow through the RCS system without i= pairing cooling flow.. Discussion with NRR on March 13, 1979, indicated there are no open ite=s relative to LOPLI.
P00R.0RGIM.
With regard to the undervoltage relay setpoint, it was found that the licensee had requested a change to the facility Technical Specifications to revise the setpoints of the 90% undervoltage relays as final resolu-tion to NRR's questions on undervoltage protection.
The NRC granted this change, but the relays were not reset for approximately 7 =onths, apparently due to oversight and failure to control Facility Change Requests on the part of the licensee.
A review of the chronology of events related to the relay setpoint change
~
l revealed that the relays had been set to the figure required by the licensee's
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analysis of undervoltage conditions.
However, this setpoint did not in-clude cargin for setpoint drift, a consideration which was included in the Technical Specification change request.
The result of this condition was that theoretically, for one sequence of events, ECCS might have been de-layed one-half second.
The licensee had reported to the Com=ission the discovery that the relays had not been reset, found during a review of an SFAS test.
The relays were correctly set shortly after this discovery.
CONCLUSIONS 1.
Toledo Edison perfor=ed a proper review of LOPLI following its occurrence at the Davis-3 esse plant.
2.
B&W personnel advised that LOPLI had been analyzed, and was not
- a. safety problem.
3.
NRR has reviewed the B&*4 analysis and concurred with its conclusions.
4.
The licensee 'did not i=ple=ent a revised setpoint for the 90% under-voltage relays for approxi=ately 7 =enths, after receiving a Technical Specification change they had requested.
5.
No evidence could be developed to indicate the licensee knowingly delayed i=ple=entation of the revised relay setpoint, and the licensee reported the discovery that the relays had not been reset.
6.
A review of the events surrounding the undervoltage relay indicates that the relays were set in accordance with the licensee's analysis of undervoltage conditions, but did not include margin for setpoint drift.
P00R ORIGINAL ~
7.
Delay o'f implementation of the relay setpoint indicated lack of control of facility changes.
8.
No items of noncompliance are cited within this report.
i 1
POOR ORIGINAL
DETAILS 1.
Personnel Contacted Toledo Edison Company T. Murray, Station Superintendent W. Green, Assistant to Station Superintendent
- C. Doceck, Nuclear Proj ect Manager, DB-1
- F. Miller, Plant Nuclear System Engineer
- E. Novak, Euperintendent Power Engineering and Construction
- S. Jane, System Engineer
- C. Calcameggio L. Stalter, Technical Engineer T. Beeler, Assistant Engineer J. Lingenfelter, Nuclear Engineer Babcock & Wilcox E. R. Cane R. C. Luken S. H. Klein F. R. Faist B. M. Dunn J. T. Willse L. R. Cartin Metropolitan Edison Cocoany J. F. Hilbish, Superintendent, Licensin's Sacramento Municioal Utility District R. A. Dietrich, Senior Nuclear Engineer Arkansas Power & Light M. O. White J. T. Enos NRC Region IV D. G. Anderson, Inspector
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Scope This investigation focused on two areas of concern indicated by an RIII inspector; loss of pressurizer level indication (LOPLI), and noncompliance with a Technice) Specification regarding undervoltage -
relay setpoints.
Emphasis was'placed on the timeliness of the licensee's actions (evaluation of LOPLI, implementation of facility changes) rather than on technical aspects of the events.
Ihe in-vestigators did not =ake technical evaluations of the information supplied by TEco or B&W as this had been accomplished by NRR.
3.
Loss of Pressurizer Level Indication A.
Conce rn:
Is LOPLI a generic occurrence at B&W facilities?
Findings Loss of pressurizer level indication during certain transients has occurred at the following B&W plants:
Arkansas Nuclear 1 Three Mile Island 2, Rancho-Seco, and Davis-Besse 1.
Details RIII investigators cet with representatives of B&W at the Lynchburg, Virginia facility on February 14, 1979 to discuss LOPLI at B&W Plants.
Present at this meeting were representa-tives of four similar B&W facilities as follows:
Metropolitan Edison Co=pany (Three Mile Island 2), Sacra = ento Municipal Utility District (Rancho-Seco), Arkansas Power and Light Company (Arkansas Nuclear 1), and Toledo Edison Company (Davis-Besse 1).
Each utility =ade a brief presentation regarding LOPLI.
Each indicated they had experienced LOPLI periodically early in plant life following certain reactor transients.
The LOPLI at these facilities was attributed to less than ideal main steam safety settings and feedwater flowrate.
Documents provided indicated that B&W infor=ed Davis-Besse 1 in 1976, during final construction, that =ain steam safety relief valve blowdown settings should be codified to reduce occurrence of LOPLI.
However, modification was not perfor=ed until after power operation, early in 1978 (Exhibit 3).
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Discussion indicated that, in the case of Davis-Besse 1, LOPLI was found to be attributable to main steam safety relief settings and the following compounding conditions:
1.
Overcapacity of auxiliary feedwater pumps.
2.
Makeup pumps tripping on loss of offsite power.
3.
320-inch pressurizer level indication span.
The investigators were advised that changes had been initiated to modify the auxiliary feedwater system which addresses items 1 and 2 above.
However, at the time of this investi-gation, these facility changes had not been implemented; however, Davis-Besse personnel advised that they were operating the auxiliary feedwater system with administrative controls to reduce the probability of LOPLI.
B.
Concern:
Is there a possibility that voiding of the pressur-1:er during a transient could occur which would adversely affect emergency core cooling system (ECCS) injection?
Findings The inspectors reviewed memoranda from Toledo Edison Company (TECo), the Nuclear Regulatory Co==ission, Arkansas Power and Light, and Babcock & Wilcox.
The conclusion drawn in these memoranda is that LOPLI was not a safety question.
B&W's analysis concluded that if the pressurizer should void, high pressure ECCS injection would automatically be initiated maintaining core coverage.
The vendor concluded that ECCS injection would not be affected.
t Details RIII personnel had previously requested TECo to determino what the actual level was in the pressurizer during the LOPLI which occurred at Davis-Besse on November 29, 1977.
The licensee was also requested to determine whether an unreviewed i
safety question existed.
Two analyses were provided RIII: with makeup flow, and without makeup flow.
These analyses, provided in September and October 1978, indicated that the pressurizer did not empty during the November 29, 1977 transient.
Furthe rmore,
l the conclusion drawn by Toledo Edison was that if the pres-i suri:er were to empty, high pressure injection would actuate, t
because the reactor coolant system (RCS) would have depre-ssurized to the 1600 pounds per square inch high-pressere safety. injection I. _.
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setpoint. Therefore, core coverage would be maintained.
The licensee concluded, with NRR concurrence during December 1978, that LOPLI did not represent an unreviewed safety-question, because HEI would be available to maintain core coverage should RCS depressurize to 1600 pounds per sq. in, and ECCS injection would not be af fected.
As of March 13, 1979, NRR advised
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RIII that they had no more questions regarding LOPLI at Davis-Besse Unit 1.
C.
Concern: Were the design requirements for the Davis-Besse Unit 1 auxiliary feedwater system unique, resulting in a unique design of two 100% steam driven auxiliary feedwater pumps?
Findings The Davis-Besse Unit 1 auxiliary feedwater system was apparently not designed against any unique NRC criteria.
A decision was made to supply two pu=ps as opposed to three pu=ps at other B&W facilities.
During plant review, this design was found to be acceptable.
Details The licensee review of the November 29, 1977, transient resulted in a deter =ination that one of the causes of LOPLI was an exces-sive auxiliary feed pump flow rate.
The auxiliary feedwater system had been progra=med upon actuation to maintain 120-inch levels in the two steam generators automatically after certain reactor trips.
The investigators discussed with utility representatives at the B&W =eeting of February 14, 1979, design requirements for the auxiliary feedwater system.
These discussions indicated that the feedwater system at Davis-Besse Unit 1, designed to meet the limiting case specified by B&W (small break), was different than other plants represented.
They advised that most B&W plants have three auxiliary feed pumps with approximately 80% capacity each.
Davis-Besse Unit 1 has two 100% steam driven pumps with each pump feeding one steam generator.
The decision to design two large capacity pumps as opposed to three l
lesser capacity pu=ps uas apparently not based on any unique B&W or NRC requirements, but was an engineering decision by the architect-engineer.
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The present design of two 100% capacity pumps was found acceptable by NRR in the Davis-Besse Unit 1 FSAR issued December 1977, with one exception.
The auxiliary feed pump control valves are to be modified from AC power to DC power j
on one _ train during the first refueling outage, in order to meet diversity of power requirements as specified by NRR.
Through discussion it was found that the licensee has investi-gated several different modifications to the auxiliary feed-
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water system in order to better control the flow rate.
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Possible modifications involved:
1.
Orificing.
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2.
Installing a flow control valve.
3.
Modification of the auxiliary feed pump level controller by installation of a dual setpoint (35 inches /120 inches)
TECo personnel advised the decision had been to engineer a dual setpoint controller which would automatically control at the lower level of 35 in~ches unless the steam and feedwater rupture control system activated and was followed by a safety features actuation.
Then, the level of the steam generator would be auto =atically co : rolled at 120 inches.
In the interim, until this facility change is implemented, ad=inistrative controls have been developed to control steam generator levels.
NRR has reviewed and approved the licensee's corrective action involving a dual setpoint.
In addition, NRR has reviewed and approved the interim administrative controls on manual operation of the auxiliary feed pumps and has found that there is reasonable assurance that operators have enough time to respond adequately to a transient.
D.
Concern: Was the licensee's analysis of the LCPLI experienced on November 29, 1977 performed in a timely fashion? Was LOPLI considered as a possible unreviewed safety question?
Findings Toledo Edison's review of loss of pressurizer level was timely, based on the following facts:
1.
Loss of pressurizer level indication was previously analyzed at Arkansas Nuclear 1 (ANO) in 1975 and it was concluded to not represent an unreviewed safety I
question by B&W and ANO (Exhibit 5).
2.
Toledo Edison was in contact with B&W soon after the event and determined that a setpoint change to the auxiliary feed pump level controller would enhance auxiliary feedwater system performance (Exhibit 4).
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i Details During the meeting with B&W and other utility representa-tives, LOPLI was discussed.
Arkansas Nuclear 1 provided documentation of the analysis performed by B&W on the LOPLI which occurred during the 1975 startup of ANO 1 (Exhibit 5).
This analysis stated that core coverage would be maintained because high pressure injection actuation would occur well before pressurizer voiding.
In addition, the representative from Metropolitan Edison described a transient which occurred on the Three-Mile Islatu. it 2 station caused by excessive feedwater flow and main steam safety valve lifting.
This event caused rapid cooldown of the primary system and pressurizer level indication was lost briefly.
However, as the RCS pressure dropped to the 1600 pound per square inch setpoint for high pressure injection, the high pressure injection system actuated and pressurizer level indication was restored.
This event substantiated the 1975 ANO 1 analysis, and appears applicable to the Davis-Besse Unit 1 station.
Statements and documents indicate Toledo Edison was in contact with B&W after the Nove=ber 29,'1977 transient to discuss LOPLI.
Since 36W ha'd concluded in 1975 that LOPLI did not represent an unreviewed safety question, they indicated that no new analysis of LOPLI was performed.
In February 1978, B&W and Toledo Edison were exploring ways of enhancing pressure level indication and had decided on a dual level setpoint (Exhibit 4).
The investigators found the following:
The safety-related analysis regarding possibic voiding of the pressurizer during certain transients was first reviewed by B&W in 1975 for Arkansas Nuclear 1 and the conclusion was that no unreviewed safety question existed; that the safety-l related analysis regarding possible voiding of the pressurizer performed at ANO 1 in 1975 was applicable to Davis-Sesse Unit 1 (as stated in vendor meeting of February 1979); that the licensee began investigating corrective action regcrding auxiliary feedwater system as early as February 1978.
l The Toledo Edison review of the Nove=ber 29, 1977 tran-sient which resulted in LOPLI was not untimely based on the following considerations:
1.
No new information was provided by Toledo Edison regarding the safety significance of worst casa voiding of the pressurizer during certain transients.
2.
Exhibit 9 shows that the licensee began corrective action discussions with B&W soon after the event.
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l 3.
NRR concluded that no unreviewed safety problem existed at Davis-Besse Unit 1.
E.
Concern:
Did the loss of pressurizer level indication at Davis-Besse Unit I repr,esent a violation of General Design Criteria (GDC) 13?
Findings Pressurizer level indication loss at Davis-Besse Unit 1 was similar to the event which occurred at Arkansas Nuclear 1 in 1975.
Arkansas Nuclear 1 concluded that GDC 13 was not violated because RCS pressure indication was never lost, and there was a correlation between pressuri:er level indication and KCS pressure.
Details During the meeting held at B&W, General Design Criteria 13 and loss of pressure level indication were discussed.
Representatives from Arkansas Nuclear 1 stated that although pressurizer level indication had been lost during certain loss of offsite power transients, reactor coolant pressure indication was never lost.
ANO stated that the correlation involved to relate pressurizer level to RCS pressure is sufficient to meet GDC 13 requirements.
This argument appears applicable to Davis-Besse Unit 1.
The investigators were advised by B&W personnel that the following additional measures had been taken by B&W to i= prove the performance of pressurizer level indication:
1.
Re, titioning of the pressurizer level taps which presently spans 320 inches to incorporate a larger span (new plants).
2.
Reco=mendations to licensees regarding main steam safety relief blowdown settings.
3.
Reco=mendations to licensees regarding auxiliary feedpump flow.
F.
Sea 11 Break Analysis Documents reviewed indicated that during the licensee's review of LOPLI, it was discovered general operating procedures and emergency procedures governing manual, operation of the auxiliary feedwater system violated certain B&W assu=ptions used in the FSiR analysis of the.
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small treak.
Davis-Besse. personnel advised they had corrected these procedures.
The item was licensee identified and reported in LER 50-346/78-117.
4.
90% Undervoltage Relav Setpoint Concerns A.
Concern:
Technical Specification Table 3.3-4 was amended effective November 29, 1977, and changed the setpoint associated with the 90" undervoltage relay; however, '
the facility change was not performed until June 15, 1978.
The plant was in noncompliance with Technical Specification Table 3.3-4 for a period of 7 months.
Was implementation of the setpoint change deliberately delayed?
Finding The licensee operated in noncompliance with the noted Technical Specification for 7 months.
The licensee reported this to the NRC when discovered.
No evidence was developed to show that the setpoint change delay was deliberate.
Details The investigators found that the 90% undervoltage relay and its associated setpoints had been the subject of much correspondence over a one year period spanning October 1976 to Nove=ber 1977 between Toledo Edison and NRR.
Review 'of the correspondence indicates that the relay in question was installed in the plant in response to an NRR generic letter on degraded grid voltage (Exhibit 6).
As NRR had not co=pleted its review of Toledo Edison's 90% relay submittal at the time the safety evaluation report was issued, (December 1976), the plant was licensed with an offsite poser grid stability requirement.
At the time of an IE verification inspection, Technical Specification Table 3.3-4 called for a 10 t 1.5 second delay setting for the undervoltage relays.
The setpoint j
safety analysis for the 90% undervoltage relay called i
for a 9 second setpoint.
Site records indicated the 9 second setpoint was installed at that time and was in compliance with the existing Technical Specifications.
l (S.ee Exhibit 9).
l In Nove=ber 1977, NRR finished its detailed review of the Toledo Edison 90% undervoltage relay protection system and issued Amendment 7 to the facility Technical Speci-fications whic;. accomplished the following:
i l l
Approvtd the licensee's analysis for a 90% under-a.
voltage relay with a 9 second maximum time delay for starting diesel generators and tripping in-coming 4.16 KV source breakers.
b.
Referenced an IE memo dated October 31, 1977, (Exhibit 6) which verified that the 90% relay had been installed.
Dropped License Condition 2.C.3.q regarding the c.
offsite network during power operation.
d.
Changed Toledo Edison's Technical Specification Table 3.3-4 per their request, dated October 27, 1977, (Exhibit 7) from starting the diesel generator at 10 seconds i 1.5 seconds to 7 seconds i 1.5 seconds.
State =ents received and documents reviewed indicated that Toledo Edison made the request to change Tech-nical Specification Table 3.3-4 for the following reasons:
Their NRC approved 90% und'ervoltage relay setpoint a.
analysis was based upon starting the diesels in 9 seconds (maximu=).
Although 9 seconds was within the existing Technical Specification limit of 10 i 1.
seconds, the existing Technical Specifi-cation would have permi.cted a setpoint of up to 11.5 seconds which would violate their 9 second under-voltage relay setpoint analysis.
To comply with the 9 second maximum analysis, Toledo Edison would need a 7.5 i 1.5 second setpoint.
b.
Toledo Edison was required to comply with Regulatory Guide 1.105 " instrument spans and setpoints."
Regulatory Guide 1.105 requires an extra margin to be added to a setpoint for drift allowance.
Com-pliance with Regulatory Guide 1.105 then lowered the required 90% undervoltage relay setpoint from 7.5 i 1.5 seconds to 7.0 1 1.5 seconds.
Since 7.0 1 1.5 seconds was below the bounding condi-tion of 10 1 1.5 seconds existing in the Technical Specifications, 7.0 t 1.5 seconds became the new Technical Specification requirement for Table 3.3-4 and was granted by the NRC effective Nove=ber 29, 1977.
Documents reviewed in'icated that when Amendment 7 to the Technical Specifications became effective, Toledo Edison had not completed the detailed engineering.
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required to change the setpoint from the then existing 10 + 1.5 second specification to a new 7.0 1 1.5 second specification.
During January 1978, Toledo Edison contracted with the Bechtel Corporation to provide the set-point package ~ fer the revised delay setting.
This package was, completed by Bechtel on February 19, 1978, and was forwarded to Toledo Edison. Following Toledo Edison's schedule, the earliest they could have been able to implement the change would have been after February 1978.
This change was designated Facility Change Request No.,77-430 and was assigned a priority of "7" defined as "the work is required at the earliest convenience", a low priority.
The following events took place which aff,ected the plant during this time:
Coal' strike of 1978.
The plant management a.
advised during this period they wished to maineain a 70% power level without tripping.
b.
Toledo Edison's (corporate) apparent judge-ment that installation of the facility change would require the plant to go off the line, as well as perform an installation test which i
would be equivalent to the major 18-month integrated safety features actuation test, due in June 1978.
c.
An unplanned outage from April 1978 to July 1978, when the plant was in cold shutdown for 3 months for removal of all burnable poison rod assemblies from the core.
While Toledo Edison was in cold shutdown, the quality assurance department generated a memo dated April 1978 which identified various facility changes that were still open.
FCR 421, involving development of the undervoltage relay setpoint table for submission to NRR, was l
one of those identified (Exhibit 8).
In June, 1978 Toledo Edison performed the integrated l
safety features actuation system (SFAS) test.
This l
test failed initially (TE Notice of Violation, Sep-tember 1, 1978).
Toledo Edison was required to per-l form a review of their safety features actuation system in order to determine if any other deficiencies in
the SEAS system existed.
TECo advised that during this review on June 12, 1978, they realized that FCR 77-430 had not been implemented, and reported they had been in noncompliance with Technical Specifica-tions (LER 50-346/78-061).
Toledo Edison changed the priority of FCR 77-430 from "7" to "4", which meant the facility change should be implemented as soon as possible.
Corrective action implementing FCR 77-430 was completed on June 15, 1978.
The successful 18 month integrated safety features actuation test was performed on June 21, 1978.
Investigators concluded that Technical Specifica-tion Table 3.3-4 was violated for a period of 7 months from November 29, 1977 to June 1978.
The event is described in LER 50-346/78-061, was licensee identified, and corrective action has been taken to implement the FCR.
This item is classified as a licensee identified item.
The revi'ew of this event identified a failure to control and implement a facility change request.
Similar failures have been the subject of discussions with the licensee and were referenced in a management meeting of August 1978, as well as inspection report 50-346/79-05.
B.
Concern:
The licensee's delay in taplementing the set-point package associated with the 90% undervoltage relay was related to the unsuccessful 18 month SFAS test first performed on June 2, 1978.
Findings A review 'f the SFAS test information apparently led to o
the licensee's discovery that the undervoltage relay set-point h 3 not been changed as previously noted.
No other relationship was indicated.
Details l
Toledo Edison corporate personnel initially advised IE l
investigators that the 90% undervoltage relay with 7.0 t 1.5 second time delay was not implemented i= mediately because the integrated SFAS test would have to be performed as a verification of installation.
TECo personnel stated that the SFAS test would require the plant to be shutdown i
at what was thought to be an inopportune time (during a coal strike).
This information regarding testing was i
later found to be incorrect.
Documents, procedures, and statements indicated that the 90" undervoltage relay is not functionally tested during the SFAS test and has no l
bearing on the success or failure of that test.
The l l
=.-
- o
- e relay setpoint can be changed during power operation.
Procedures indicate that since June 1978, the licensee has included the 90% undervoltage relay setpoints in their surveillance procedures.
C.
Concern:
The licensee did not meet
_..e FSAR assumption of 30 second injection of ECCS following a loss of coolant accident (LOCA).
This prompted the licensee to change the setpoint from 10 seco,nds 1 1.5 seconds to 7 seconds i 1.5 seconds.
Findings The 90% undervoltage relay setpoint is not coraidered in the FSAR and was added to the plant as a result of an NRR letter.
The delay setpoint was changed to 9 seconds to assure 30 second ECCS injection, then changes to 7 seconds i 1.5 seconds to account for setpoint drift.
Details The FSAR cons'iders the design basis accident in which there is a total loss of all offsite power coincident with a loss of coolant accident.
The loss of offsite power trips an installed 59*. undervoltage relay, starts the diesel generators, and begins sequencing all necessary equipment.
ECCS is assumed to begin injection approximately 30 seconds after the 59% relay trips.
TECo's response to the NRR letter resulted.in an instal-lation of an additional relay set at 90%.
This relay would trip af ter "X" seconds when voltage on the incoming 4.16 KV source buses had fallen between 59% and less dian or equal to 90%.
The plant went into power operation with a 90,% relay installed and functioning, set at a 10 second time delay period.
The time delay was later changed co 9 seconds to support the Toledo Edison 90%
undervoltage relay safety analysis.
During plant operation, before NRR completed their detailed review of the Toledo l
Edison submittal, the plant operated with an additional l
requirement as follows:
power operation would only be permitted during times when offsite 4.16 KV grid voltage was between 98.3% and 102.3% of rated voltage.
After Amendment 7 was issued, the 4.16 KV offsite power stability requirement was dropped.
NRR concluded that installed undervoltage protection was sufficient to isolate safety related equipment from a degraded offsite power condition.
As stated above, the licensee did not implement Amendment 7 for a period of approx 1=ately seven months.
The result of this oversight is as follows:
The 90% undervoltage relay was calibrated at 9 a.
seconds and verified by RIII to be 9 seconds to
~
support the Toledo Edison safety analysis.
b.
A half-second drift was not included in the setting, and nonconservative drift could have theoretically pushed the action setpoint to 9.5 seconds thereby delaying starting of the diesel generators by a half second.
5.
Toledo Edison Management Deficiencies The review of the delay in undervoltage setpoint implementation indicates that weaknesses exist in areas of nuclear license administration, facility change tracking, and engineering for facility changes.
A.
Engineerine for Facility Changes Review of events related to the 90% undervoltage relay setpoint revealed two instances where engineering for a facility change had not been completed when the facility change was re' quired to be implemented as follows:
1.
7.0 + 1.5 stcond setpoint for the 90% undervaltage relay.
2.
Pushbutton defeat of 90% undervoltage relay.
(Covered in II inspection report 50-346/79-30).
During discussion; with TECo stafi the investigators were advised that engineering to support facility change re-quests involving Technical Specifications changes had not been performed until after NRC approval was granted.
Detailed engineering supporting the 90% undervoltage re-lay setpoint was not performed until after NRC grantad approval.'
The practice of delaying performance of engineering for Technical Specification-related facility changes indicates inadequate facility change administration.
- Reviews, administration and perfor=ance of engineering to support Technical Specification modifications were apparently not performed on a timely basis.
B.
Nuclear License Administration Toledo Edison did not identify to the NRC that an imple-mentation date would be required for Amendment 7, thus the amendment became effective the day of issuance even though Toledo Edison had not performed the necessary revision to the 90% undervoltage relay setpoints to be in compliance with the new license requirements.
This resulted in noncompliance with the Facility Technical Specifications as amended.
C.
Review of Tacility Changes Review of the 90% undervoltage relay event indicated that noncompliance with Technical Specifications occurred.
because of inadequate adminstrative procedures for carrying out facility changes.
This noncompliance was the result of
~
failure to implement the FCR related to Amendment 7 in a timely fashion.
Attachment:
Exhibits 1 through 9 e
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- TOLEDO
-3
)h June 23, 1978 L78-278 FILE:
RR 2 (NP-32-78-07)
Docket No. 50-346 License No. NPF-3 be. James G. Keppler Regional Lirector, Region III Office of Inspection and Enforcement U. S. Nuclear Regulatory Commission 799 Roosevelt Road Glen Ellyn, Illinois 60137
Dear Mr. Keppler:
Reportable Occurrence 78-061 Davis-Besse Nuclear Power Station Unit 1 Date of Occurrence:
June 12, 1978 Enclosed find three copies of Licensee Event Report 78-061 with a supplemental infor=ation s.heet, which is being submitted in accordance with Technical Spect -
fication 6.9 to provide 14 day written notification of the subject occurrence.
Yours truly,
..erry D...urray Station Superintendent Davis-3 esse Nuclear Power, Station TDM/JRL/ljk Enclosures ec: Dr.' Irns t volgenau, Director Office of Inspection and Enforcement Encl:
40 copies LIR 78-061 Mr. William G. Mcdonald, Director.
Office of Managenent Information and Program Control Encl:
3 copies LER 78-061 2 copies telecopied report l
l bec:
J.R. Barker J. C. Buck EXHIBIT.'1 P. P. Anas
- T. P. Beeler page 1 of 3 R. E. Lapp Edison Electric Institute W. E. Nyer Training Department C. M. Rice CNRB Mcabers THE TCLECO EDISCN COMPANY EOISON PLAZA 300 MaOISON AVENUE TOLEDO. CHIC 43552
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This event is being reported in accordance with Technical Seecifica-l ; tion 6.9.1.8f.
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CAUSE DESCRIPTION AND CORRECTIVE ACTIONS
] l?acility Chance Recuest 77-430 was i==ediatelv issued for i=clenentation to adiust l l:he time delay and voltage setooints.
One relav was found to be defec Hve ed vae l l replaced.
The relay settings were changed to co=oly vith Technical Soecification lrecuirenents. A new survei.llance test procedure v411 % ar-wa n
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a vusvu cutav.i ovnran s i DA'VIS-BESSE UNIT ONE NUCLEAR ~ PCUER STATION SUPPLEMENTAL INFORu.ATION FOR LER NP-32-78-07 DATE OF EVENT:
June 12, 1978 FACILITY:
Davis-Besse Unit 1 IDEXTIFICATION OF OCCURRENCE:
Incorrect setpoints on essential bus undervoltage relays Conditions Prior to occurrence:
The unit was in Mode 6 with Power (MWT) = 0, and Load (MWE) = 0.
Description of Occurrence:
On June 12, 1978, during the Station Review Board revLs of the " Safety Features Actuation System (SFAS) 18 Month Test", ST 5031.07, it was found that the ti=e delay setpoints of the essential bus undervoltage relays were incorrect and that the monthly channel functional test was not being performed.
The initial investigation showed the Facility Change Request (FCR)77-217 which was i=ple=ented on October 4,1977, called for the time delay to be set at 9 seconds.
FCR 77-430 was prepared on October 28, 1977, to correct the setpoints to 711.5 seconds, but had not yet been issued for i=plementation on June 12, 1978.
This occurrence is being reported in accordance with the provisions of Technical Specification 6.9.1.8f.
Designation of Apparent Cause of Occurrence:
The cause of this occurrence is procedure inadequacy.
Analysis of Occurrence:
There was no danger to the health and safety of the public or to unit personnel.
The intent of the 711.5 second time delay setpoint is to ensure that a bus trip will occur in 9 seconds af ter the bus voltage degrades to less than 902 of 'the nor=al voltage.
The average time delay setting of the relays was found to be 8.99 seconds.
, Corrective Action:
FCR 77-430 was 4--ediately i=plemented and at that time it was also found that the voltage setpoints veru incorrectly set to a maxi =um of 2.5%
'ess than the technical specification =ini=um.
One relay was found to be defective and was replaced.
The time delay and voltage setpoints were adjusted to values in co=pliance with Table 3:3-4 of Technical Specification 3.3.2.1. A modification (T-2870) was prepared for a test to be perforned in conjunction with ST 5031.07 to satisfy the monthly functional check.
A new surveillance test procedure vill
^ be written to assure the monthly functional test is. completed when the unit is in the applicable modes.
This work was co=pleted on June 15, 1978 under Maintenance KorkOrder 78-1397.
EIRIBIT 1 Failure Data:
This is not a repetitive occurrence.
page 3 of 3 LER #78-061
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MET HOPOLil AN EDISON COMPANY TELEPHONE 215 - 929 3C01 T OFFICE SOX 542 READING.PENNSYLVANI A 19603
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July 214, 1978 GQL 1227 Mr. B. H. Grier, Director Office of Inspection & Enforcement Region 1 U. 5. Nuclear Regulatory Corsnission 631 Park Avenue King of Prussia, Pennsylvania 19406
Dear Sir:
Three Mile Island Nuclear Station Unit 2 (TMI-2)
Operating License No. DPR-73 Docket No. 50-320 In accordance with the require =ents of Section 6.9.2. A of the TMI-2 Technical Specifications, enclosed please find a Special Report concerning the TMI-2 j
ECCS Actuation which occurred on April 23, 1978.
Sincere'ly,
/
J. G. Herbein Vice President-Generation JGH:RAL:tas
Enclosure:
Special Report concerning the TMI-2 ECCS Actuation of April 23, 1978 f
EXHIBIT 2 page 1 of 5 I
(
SPECIAL REPORT CONCERNING THE TMI-2 ECCS ACTUATION OF 4/23/78 EXHIBIT 2 page 2 of 5
At 1651:23 on h-23-78, TNI, Unit 2, experienced a reactor trip while at 30%
Rated Thermal Power with 3 reactor coolant pd=ps in operation (RCP-2A secured) due to a noise spike on NIB power range detector.
The reactor tripped because E?S Cht=nel C was already in the tripped state as required by Technical Specifi-cation 3.3.1.1 due to the inoperability of NI-7
" hen the reactor tripped, the turbine tripped causing a very rapid pressure increase in the 3 steam generater and a slightly slover pressure increase in the A generator.
Four of the six =ain steam relief valves lifted en the 3 steam generater and very rapidly blev 3 side stea= pressure down.
One =ain steam relief valve en the A steam generator lifted and also caused a rapid pressure bicvievn but about h0 seconds delayed fro = the 3 steam generator.
The 3 Tur-tine Bypass valve received a signal to go full open but almost 4-'ediately received a signal to go full closed due to the rapid depressurization in the 3 stea= generator.
The A Turbine Bypass valve received a signal to open at the proper pressure but the signal to open the bypass valve was lower in =ag-nitude than it should have be'en.
The four 3 side =ain stea= safety valves and the one A side valve failed to preperly reseat.
The safety valves on the 3 side started to reseat just prior
'- ^ es into the event with the re=ainder of the 3 safety valves and the A safety valve resesting al= cst four =inutes into the event.
The stea= gener-a:cr pressures were between 550 and 600 psig when all safety valves reseated.
The operater took the proper i==ediate action in =anually cutting back feedvater de=and, shutting the letdev: isolation valve, starting a second makeup pu=p, and cpening the high pressure injection valves en the side of the operating =akeup pumps.
The cperator failed to initially recognize that the feed pu=p vas in
=t.usi a.i did not run the feed pu=p speed back until apprcximately 1 =inute and 20 secends had elapsed.
The. :ntegrated Centrol of the feedvater valves had not yet been initially tuned at the ti=e of the event.
Integral vice propertional centrol was the dc=inating signal of the feedvater valves and although the valves responded in the picper direction, they respended =uch sicver than the traditionally expected response.
Thus, the feedvater valves sicvly going shut, rapidly decreasing stes= generator pressure and a constant feed pu=p speed,too =uch vater was fed into the steam generators.
The safecy valves failing to reseat at the proper pressure coupled with overfeeding
-* ' ** generaters caused a rapid depressurization and cooldown of the reacter 0
ecclant syste=.
The reactor coolant te=perature varied frc= 583 7 to h6hc? in 3 minutes.
The BCS shrinkage frc= the cooldown caused the pressuri:er volu=e to drop telev tha
'-4-"-
indicated level range approxi=ately ene minute after the l
reac cr trip.
Due to the rapid depressurization.of the R.C.S. SFAS safety injectig l
^--"--*' approxi=ately cne minute after the trip.
By present design this injected l
" ACE inte the reacter c'colant systa= through the high pressure injection lines.
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t Pressurizer level was restored two =inutes into the event as a result of safety injection, the Turbine 3ypass valve going shut and so=e of the 3 side Main Stea=
..elief Valves going shut.
Feedvater latch occurred 2 minutes into the event and teminated feedvater flov to the stea= generators.
Feedvater latch was the key event in te =inating the transient.
"he rapid depressurization and cooldown event caused violations of the following Technical Specifications:
1.
RCS Cooldown limit of 100 F in any one hour was exceeded (actual 13h in one hour) T.S. 3.h.9.1.
0 2.
Pressurizer cooldown li=it of 100 F in any one hour was exceeded (actual 1360F in one hour) - T.S. 3.h.9.2 3
Pressuriser volu=e was less than that required by Technical Specifi:ation 3.h.k.
Ca.lculatiens vere perfo =ed 4 ediately after the event and subsequent chemistry analysis shoved that the core re=ained covered at all ti=es thrcughout the tran-sient.
Iva'uatiens of the excessive cooldovn rates on the reactor vessel, reactor coolant piping, pressurizer and stea= geners. tors have been perfo =ed by 3abeeck and Wilcox e.nd have been reviewed by Metropolitan Edison.
These evaluations conclude that the structural integrity of these reactor coolant syste= cc=ponents is acceptable fer resuming no=al plant operation.
In addition, evaluations have been perfo=ed on the reactor coolant pumps, control
- d drive =ea'-a-* es, and fuel eladding.
It has been concluded that these co=-
pcnents should continue to perfom as designed.
EXHIBIT 2 page 4 of 5 P00R'0RIGINAL e
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- rear of Corrective Action 1.
prior to criticality, the relief valves will be tested for proper lift pressure and also to ensure that blevdown'is not excessive.
NI-7 power range detector has been replaced.
The source of the noise.
fren N -8 is being investigated.
Tests vill continue in order to' deter =ine the cause of the inter =ittent noise.
3 Discussions are underway with the Co-4 ssion to change the SFAS logic to prevent 4 ediate injection of NaOH through DE-V8A & B upon receipt of a safety injection signal.
h.
S ning of the Integrated Control Syste= vill continue throughout initial plant startup to achieve balanced tuning for transient operation.
5 plant operating procedures vill be changed to reflect experience gained as a result of the transient.
.1 M
P00R BRIBlE
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EXHI3IT 2 page 5 of 5
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Subject:
Eccc==endations for Avoiding Pressurizer Off-Scale Indications
Dear Jack:
F.xperience h.s : horn that the 3L*.1 177 Fuel Assc=bly Plan s with the prer.suricer level indication rant;c of only 320 inches are succeptible to belev tero level indientiens on reactor / turbine trips and lead rejecticn tre.:ient:.
Our Cen-rel Analysis Unit in Lynchburg has reviewed this problem and provided the fel-1cvin6 Generic resolution:
For a plcr.t with no:::al operatin$ level of the pressurizer of ico +ho 1.
-20 inches, raise the nc=inal level to 200 + 20 inches rather than 150 inches.
Operating history of autc=stic p:essurizer level control shevs a deviation of acc.roxi=ately.+_ 10 inches.
An" additicnal increa e in level vill be in conflict with the a su=ptic::s c= ployed in the Anticipated Transient Without Scra= study for the ImC.
2.
Tne== cunt of blevdevn of the steam safety relief valves has been assu.cd to be 5% or approximatel'/ 50 psi for the cafety valves with the lowest setting (1050 psig).
Measured c cen line precsures at operating plants of this type indicate that the actual blowdown is about 75 cr 75 p:i and even as large as 8.55.
Tne minimu= reactor coolcnt syste= average te=perature following a react.or trip shoul:1 not decrease belev Sh8*F and the mini =u= ctea= cenerator dischar.,e
/
pressure shoulf. c.:ge.ci.9.75. psic at the sc=c ti=c.
Snould the =ea-sured stca safety valve blevdown exceed 75, the valve b1cvdov:.
should be readjusted to approximately 5% at your earliest convenience.
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Reference:
1.
Letter Bh*T-1609, J.A. Lauer to C.R. Do=eck, T1.2/123, dated December 5, 1977.
Engineering has evaluated the transient described in SPR 396 re'sulting in the following co==ents:
1.
The classifibtion o the transient in Reference I was correct and no further coc=ent on this aspect is required.
2.
The decrease in pressurizer level (off-scale low) is indicative of rapid steam generator level increases following the initiation of AW. This undesirable effect is sy=ptomatic of high level setpoints.
Conversations with Fred PJ.11er of TECO Engineering have confirmed TECO's awareness of this problem and their desire to have it rectified.
In view of the fact that Davis-Besse I has elevated loops, there should be little difficulty in decreasing tha level setpoint with appropriate analysis. The funding for this work will be pursued through Project Management.
3.
Engineering has been tinable to satisfactorily resolve the dissimilar behavior of the two OTSG's during the transient.
During the 5 to 15 minute period of the transient, the two steam pressures moved in cpposite directions and were considerably apart.
The plant co=puter printo'ut says a main steam line" warm up isolation valve was open during this ti=a ("22:55:56 2688 FN STM Line 2 WU ISO YLV CLOS"), but TECO Engineering says the valve indicator is wired backwards, indicating %at it actually was closed until 22:55:56, when an operator openedit.lf indeed it was closed until this time, there appears to be no logical explanation for the steam pressure differences.
This should be passed on to TECO Engineering, since Plant Lesign has no further information with which to investigate this anomaly.
h.O C.W.
a EXHIBIT 4 it n'
P90R'0RIBlE J.A. Lauer R.W. Winks
-r.-
"ARKANSASP WER S. LIGHT COMPANY
~
8NTRA COMPANY COR AECPONO5NC3 April 15, 1975
=ist?
.h Yh t-5
{
g,, v -
g [G 1975 NDC 2719
,4 gg, ARK.esAs POWG e,.g.,;g,t,; gu,}39 MEWRMSU'4 g
)
1V:
J. W. Anderson FROM:
William Cavanaugh
SUBJECT:
Arkansas Nuclear One-Unit 1 Pressurizer Level Setpoint
, (File: 3740)
Reference:
- 1.
JWA-848 2.
NDC-2360 3.
Letter, Govers to Cavanaugh 3/3/75 Attached is reference 3 from B6W which provides their answers'to PSC cor.ments on loss of level indication in the pressuri:er following a reactor trip.
From that letter, it can be seen that j
.as long as water remains in the pressurizer the core will remain i
covered and the HPSI setpoint will not be reached.
If the pressuri:er e=pties, HPSI will be automatically initiated due to the rapid pressure drop mentioned in their letter.
~
.~
If you have further questions, please contact us.
l c
WC:Dp:1s
~~
Attachment MnAn'~nnInIEIA{f g ggg ec: Mr. D. A. Ryeter Mr. M. L. Pendergrass EXHIBIT 5 page 1 o'f 3 e
9 G
e
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1
.i Babcock & Wilcox
%, c.,,,,2, c, o, P.O. Bos 1260, Lynchburg. va. 2450_.
Telephone: (SO4) 384 5111 April 3, l'975
~
.r. V. Cavanaugh, Ill t
Manager, Nuclear Services Arkansas Power 51.lght Company P.O. Box 551 If little Rock, Arkansas 72203 l
~
Subject:
Arkansas Nuclear dne - Unit One Pressurizer Level Setpoint (8N 11$7b O' b gGS 3cV Reference NSS-8 M
gom%@s stW" QM.
i
Reference:
NDC 2360, 3/3/75 M
Dear Mr. Cavanaugh:
NOC 2360 expressed concern over the momentary loss of pressurizer level indication following a reae. tor trip and requested additional Information to clarify that raintaining RC pressure above 1500 psis (HPSI automatic actuation setpoint) would ensure that the reactor core remains covered with water.
This protection can be demonstrated by using a very simple principle:
coolant system pressure reactor water in the reactor coolant system.is determined by the saturation pressure for the In all operating situations except extreme accident conditions, this water is, of course, pressurizer water at about 6500 corresponding to a saturation pressure of 2155 psig while the average water F,
temperature in the reactor core of 573 F has a saturation pressure of about D
p's i g.
1300 Within about 20-30 seconds after a reactor trip, all water in the reactor coolant system (except pressurizer water) will be belcw 579 F as the reactor p<:wer-Sustained differential temperature across the core collapses and as the reacter coolant system is cooled to about 550 F (due to turbine bypass valves being set to control OTSG pressure at 10'10 psig). -Even though the pressurizer water out-surge during system cooldown will allow system pressure to fall below 2155 psl.3, remains we, data from reactor trips at ScV's operating plants.shows that RC pressure I above 1500 psig.
With the RC cooldown established by means of the
', t 'iss the pressurizer' is completely drained. ' If the pressur c o letely, RC pressure would drop rapidly to the saturation pressure for the hottest water remaining in the RC system.
The temperature of this water would be between 550 F and 579 F with 'a resulting RC pressure of 1010 psig to 1300 psig.
i This resulting RC pressure band if the pressurizer were to empty following a reactor trip is we;11 bel.ow the 1500 psig HPSI automatic Initiation setpoint.
Thus 1500 psig is an adequate low pressure setpoint for ensuring the the reactor core remains covered with water.,
EXHIBIT 5 maae 2 of 3'
5 (c.
(..
id:& Wilcox
.nney/ Covers to Cavanaugh
-2,
April 3, 13p you have any further questions in this matter, please advise.
.Very truly yours, J. D. Phinney', Manager Operating Plant Services & Maint.
'8y:
fe c.py R. A. Govers JDP/ RAG /cs
-Service Project Engineer cc:
J. W. Anderson J. A. Bailey R. P. Lockett, Jr.
.s,
.4
$XHIBIT 5
,page 3 of 3 g
e 8
1 L
lwr 1 File t.L o R. C. DeYoung IE (3)
F. J. Williams ACRS (16)
J. Stolz J. Miller E. Hylton Docket !o. 50-346 L. Engle R. Heineman D. Ross Toledo Edison Cocpany J. Knight, SS ATTN: Mr. Lowell E. Roe R. Tedesco Vice President, Facilities V. A. tiocre Developcent H. Denton Edison Plaza 300 !'.adison Avenue J'. R. Buchanan, NSIC bec-Toledo, Ohio 43652 T
B. Abernathy, TIC Gentleman:
EQUIPMEtiT FAILURES OURItiG A DEGRADED GRID VOLTAGE CONDITIO!! AT MILLSTONE, UllIT 2 Provided herein as Enclosure 1 is a description of events which occurred at Millstone Unit' Ho. 2 during July 1976 relating to plant operation and equipment failures during a degraded grid voltage condition.
On July 27, 1976, all utilities with operating reactor facilities
. received telephone notification from the i!RC of the events at the Millstone Unit No. 2 facility. At that time members of your staff were asked to investigate the vulnerability of your facility to similar degraded voltage conditions and to previde a resconse by telephone within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
As a result of our initial investigation and evaluation of the potential generic implications of the events at Millstone and our preliminary discussions with several licensees, we consider it necessary to require all plants presently in review for an operating license to conduct a thorough evaluation of the probica and to submit fonal reports. Therefore, we request that you conduct an investi-gation of the issue as it affects your facility using the Request for Infur ation detailed in Enclosure 2 as a guide, and provide the analyses and results within 30 days of receipc of this letter or explain why you cannot meet this schedule and provide the schedule you will meet.
EXHIBIT 6 Page 1 of The signed original and 39 copies of your response will be necessary.
l CCI 151976 P00r0RlGlNR
o 1
Toledo Edi::en Company z
ocr r
This request for generic infomation was approved by GAO under a bla6ket clearance nur.ber B-130225 (R0072); this clearance expires July 31, 1977.
Sincerely, pristnal signed br.
_Igha F. Stolz
._1.
John F. Stolz, Chief Light k'ater Reactors Branch No.1 Division of Project l'anage:r,ent
Enclosures:
1.
Description of Events
~
Hillstone Unit tio. 2 2.
Request for Infamation cc:
Mr. Cona'd H. Hauser. Esq.
The Cleveland Electric Illu:ninating
~
Ccepany P. O. Box 5000 Cleveland, Ohio 44101
' Gerald Charnoff, Esq.
Shaw, Pittr.an, Potts and Trowbridge
?'" 17th Street, H. E -
Washington. D. C.
20036 Leslie Henry, Esq.
Fuller, Seney, Henry and Hodge 300 Madison Avenue 4
Toledo, Ohio, 436G4.
~
I
- .XHIBIT 6 page 2 of 5
-i, DESCRIPTION OF' EVENTS
.~
~~
'HILLSTONE UNIT NO. 2_
l On July 2b,.1976, Northeast Nuclear Energy Compariy (NNECO) reported that, following a trip of Millstone Unit No. 2 on July 5,1976, several mtors powered from 480 volt (v) motor control centers failed to start The failure of the 480 y motors to start was traced to as required.
l These blown control power fuses on the individual motor controllers.
ontrollers receive control power through 480 v/120 Y transformers within die controller.
NNECO's investigation disclosed-that, as a result of the plant trip, This voltage drop, the grid voltage dropped from352 ky to 333 kv.
in conjunction with additional voltage drops associated with the transformers involved, reduced the control power and voltage within
~
indiYidual 480 y controllers to a voltage which was insufficient to actuate the main line controller contactors.
As a result, when the mtors were signalled to start, the control power fuses were blown.
Subsequent testing by NNECO showed that the contactors required at least 410 y to function properly.
NNEC0 concluded that under similar low voltage conditions, the opera-bility of 450 v Engineered Safety Feature equipment could not be assured.
NNECO's irmediate corrective action was to raise the setpoint of the Engineered Safeguards Actuation System (ESAS) " loss of' power" under-Yoltage relays to assure thac the plant would be separated from the grid and emergency power system (dual) operation would be initiated before the control voltage fell below that required for contactor operation.
A trip of the undervoltage relays causes the emergency buses to be de-energized and a load shed signal to strip the emergency buses, the diesel generators to start and power the emergency buses, and required safety related loads to sequence start on the buses.
21, 1976, NNECO reported that the earlier corrective action taken
~ On July was no longer considered appropriate because during starting of a circulating water pump, the voltage dropped below the new ESAS under-Yoltage relay setting.
This de-energized the emergency buses, caused load shedding to occur, started the diesel generators and began sequencing i
loads onto the emergi:ncy buses in accordance with the design.
- However, l
during sequencing of the loads onto the buses, the voltage again dropped below the undervoltage relay setting which caused the load shed signal to strip the busr.s.
The result was energi.ed emergency buses with no' loads supplied. -
EXHIBIT 6
~
page 3 of 5 l
' " ~
nroucsr res,,,,,0. ',re,,-
1.
Evaluate the design of your facility's C1sss IE electrical distribUtfon system to detemine if the operability nf safety related equipment, including associated control circuitry or instrumentation, can be adversely affected by short tem or long tem degradation in the grid system voltage within the range where the offsite power is counted on to supply important equipment.
Your response should address all but not be limited to the following:
a.
Describe the plant conditions under which the plant auxiliary systems (safety related and non-safety related) will be supplied by offsite power.
Include an estimate of the fraction of nomal p1 ant operating time in which this is the case.
b.
The voltage used to describe the grid distribution system is usually a ' nce.iin al " val ue.
Define the nomal operating range of your grid system voltage and the corresponding voltage values.at the safety related buses.
j i
t c.
The transfomers utilized in power systems for providing the required voltage at the various system distribution ievels are nomally provided with taps to allow voltage adju.stment.
Provide the results of an analysis of your design to determine if the voltage profiles at the safety related buses are satisfactory for the full load and no load conditions on the system and the range of grid voltage.
-1 d.
Asst. ming the facility auxiliary loads are being carried by the station generator, provide the voltage profiles at the safety buses for grid voltage at the n'omal maximum value, the nomal minimum value, and at the degraded conditions (high or low voltage, current, etc.) which would require generator trip., j r
e.
Identify the sensor location and provide the trip setpoint for your facility's Loss of Offsite. Power (undervoltage trip) instrumentation.
Include the basis for your trip setpoint selection.
3 f.
Assuming operation c n offsite power and degradation of the grid system voltage, provide the voltage values at the safety related buses corresponding to the maximum value of grid voltage and the degraded grid voltage corresponding to the undervoltage trip setpoint.
g.
Utilizing the safety rei$ted bus voltag'e values identified in (f),
evaluate the capability of all safety related loads, including related control circuitry and instrumentation, to perform their. safety functions.
Include a definition of the voltage range over which the safety related c:mponents, and non-safety canponents, can operate continuously in the performance of their design function.
e 0
EOR;0RIGINAL b%
~
e
. t.
.d.
h.
Describe the bus voltage monitoring and abnormal voltage alams ava.ilable in the control room.
2.
The functional safety requirement of the undervoltage trip is to detect the loss of offsita (prefer d) peger system voltage and initiate the necessary actions requirer u transfer safety related buses to the onsite power system.
Describe the load shedding feature of your
~
design (required prior to transfering to the onsite [ diesel generator]
systems) and the capab4'ity of the onsite systems to perfom their function if the loac'
.wdding ' feature is maintained after the diesel generators are connected to their respective safety buses.
Describe the bases (if any) for retention or reinstatement of the load shedding function after the diesel generators are connected to their respective buses.
3.
Define the ' facility operating limits (real and reactive power, voltage,.-
frequency and other) established by the grid stability analyses cited in the FSAR.
in effect for assuring that your facility is being operated with limits.
4.
Provide a description of any propesed actions or modifications to your facility based on the results of the analyses performed in response to-items 1-3 above.
~
{
EXHIBIT 6 l
page 5 of 5
4a $
SON Docket No. 50-346 Serial No. 396 LOWELL E. ACE October 27, 1977 l* *,,,7,,';',",',,,,,,
14153 239 *242
.s t I 'iG f x ~ ~ '/
k!C6y[g, %'
Director of Nuclear Reactor Regulation Ty Attention:
Mr. John F. Stolz, Chief fjg /
1977 P Light Water Reactors 3 ranch No. 1 D,
f Division of Project Manage =ent
,"'#'T,$4ua %,,
s United States Nuclear Regulatory Co==ission k.G,,
Wr :
~ %
Washington, D. C. 20555 Q,-
v,
Dear Mr. Stolz:
Ni16,
Our letter to you dated July 18, 1977, regarding grid stability at Davis-3 esse Nuclear Power Station Unit No. 1 proposed some =edifications to increase certain safety =argins.
One of the changes requires a change to the Davis-Besse Nuclear Power Station Unit No. 1 Technical Specifications.
Inclosed is the requested change to Page 3/4 3-13 and associated safety evaluation.
This change is requested on an energency basis to allow operation of Davis-3 esse Nuclear Power Station Unit No. 1 in a sanner which better assures plant operability during grid voltage
. degradation.
Yours very truly, d
Vs-~
1
]
Attachnents:
Davis-Besse Uni No. 1 Technical Specification Page 3/4 3-13 Safety Evaluation bt c/4
(
EXHIBIT 7 page 1 of 3 f'
773060215 l
tkE TCLECO ECtSON CCMPANY ECISCN PLAZA 3CO MACISCN AVENUE TCLECC. CHIC 43552
Safety Analysis A result of our review of " Millstone G' rid Stability Syndrome" was addi-tional undervoltage relaying on the 4.16 KV essential switchgear.
Serials 179 and 226 to the NRC explained that the relays functioned on 90% voltage and a 10 second time delay to trip inecming 4.16 KV source breakers.
In addition a 1 second tLue delay was added to the diesel -
generator breaker closure, only if the diesel had been started and was ready to accept load.
In Serial 293 to the NRC we responded that the changes in 4.16 KV protec-tion did not adversely affect the safety analysis.
However, to increase our margin in the safety analysis we proposed slightly more conservative settings of less than 90% 4.16 KV for 9 seconds and diesel generator breaker closure delay of.5 seconds.
The reduction in trip time from 10 to 9 seconds on 4.16 KV voltage relays 27A-1 through 27A-4 and the reduction in close time from 1 to.5 seconds on the diesel generator breaker was to assure ECCS injection within 30 seconds.
The table below compares the old scheme with the new scheme.
Time After LOCA In Seconds l
Occurrence Old New l
LOCA occurs 0
0 LOCA detected and diesel generator started 5
5 System voltage less than 90%, greater than 59%
5 5
Voltage monitoring operates to open off-site source breakers 15 14 Diesel generator at voltage and frequency 15 15 Bus voltage decay and spurious dip allowance 16.5 15 Diesel generator breaker closed 16.5 15 High pressure injection pump starts - second step of diesel generator sequence 21.5 20 i
Low pressure injection pumps starts - third l
step of diesel generator sequence 26.5 25 High pressure injection pump up to speed 26.5 25 Low pressure injection pump up to speed 31.5 30 bt c/6 l
l l
/
EXHIBIT 7 l
page 2 of 3
?
n c.g y
E" TABLE 3.3-4
.-.7 y&
El SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION TitlP S[TPOINTS ca n.
"m FUNCTIONAL UNIT TRIP SETPOINT ALLOWARLE VALULS C
]
INSTRUMENT STRINGS a.
Containment Radiation
< 2 x llackground at RATED
< 2 x Rackground at YllERMAl. POWER liATED TilERNAL POWER, h.
Containment Pressure - liigh 1 18.4 psia
< 18.52 psla#
Containment Press.ure - High-liigh c.
1 38.4 psia
< 38.52 psia #
d.
RCS Pressure - Low
> 1620.75 p*sig
> 1615.75 psig#
w s
7 8.
RCS Prossure - Low-Low
> 420.75 psig g
w f.
IlWST Level
> 415.75 psig w
> 49.5 and < 55.0 in. 11 0
> 48.3 and 2
-< 56. 7 in.11 0 SEQUENCE LOGIC CllANNELS
^
2 Essential Bus Feeder Dreaker Trip (90%)
a.
2 3744 volte for 2 3558 volts for O
7,+ 1.5 see b.
Diesel Generator Start, Load Shed on for~7.1_1.5 sec#
Essential Bus (59- )
4
> 2071 and < 2450 volts
> 2071 and < 2450 for 0.5 + 0.1 sec
_ vol ts for _
INTERLOCK CilANNELS
~
0.5 + 0.1 sec#
a.
Decay lleat Isolation Valve
< 530 and > 413 psig
< 535 and > 408 psig#
s;j6ne,, awe de for CIMNNR RINCTIONAL HST and CWsHHR CAUHIM
s
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~.-..- r =:.~ ~.:: ~. '...
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Facility Chance Eequests for Clesecut I
'.tached are the following FCRs:
77-041 77-231 77-106 77-421*
77-182 77-509 These FCRs can be closed when all the correct documen:ation is included in the packages and/er deficiencies are resolved.
2.:: ached to each FCR is a lis: of the =issing 1: ens and/or deficiencies rela:1.e to that specific FCR.
5 :e of :he input to conpleta these FCRs =us: come free the S:ation and scre f: ?cwer In;ineering.
Please review the attached pacha;es and include the 1:ers for whi:h you are responsible.
1.~ hen :his is cc ple:ed,'please forward the e. ire pc:hage to ?cuer Engineering for their input.
If you haee cuesticas regarding the concents en any FCR, please feel free to call =e a: 5 57.
r. 7....... 3
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EXHIBIT 8 i
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m October 31, 1977 XDf0RANDUM FOR:
E. D. Thornburg, Director, Division of Reactor Operations Inspection, IE TROM Janes G. Esppler, Director SU3 JECT:
TOLEDO EDISON CCMPANT DAVIS--BESSE I DOCKE7 No. 50-346 l
\\
Based upon our inspection efforts, we have verified that Toledo Edison l
Company has modified the protective circuitry to provide breaker coordina-tion and isolation of the onsite electrical system to pernit the required Class 1E equip =ent to operate in the event of off site grid degradation in accordance with their sub4 teal of July 18,1977 (Serial Number 293) to J. E. Stoltz fron L. E. Roe.
This subetittal to NRR was made in accordance to the requirement ;t Facility Operating License No. NPF-3 condition 2.C.
(3) (9).
This infor=ation should be transmitted to 533 so that condition 2.C. (3) (q) of the license can be amended.
Janes G. Emppler Director cc:
N. C. Moseley, IE E. L. Jordan, IE POOR ORIGINAL.
~
-=
EXHIBIT 9
~
l
- TIT, E.
%p x
aJ u 1/~hass TO: t.tnited States Nuclear Regulatory Comtission Office of Inspection and Enforcement c[d'.[h Region 3 Aten: Tom Tambling
SUBJECT:
Reportable Occurrence SFRCS Actuation with Resultant Reactor Trip and SFAS Actuatio:t Davis-Besse No.1 Reactor in Mode 1 Operation Power 280 Mt? - Load 90 WE At 2134 hours0.0247 days <br />0.593 hours <br />0.00353 weeks <br />8.11987e-4 months <br /> on September 24, 1977, the Reactor Operator noticed Hain Fced Pu=p No. 2 Speed decreasing and received a low level alars on No. 2 OTSG.
At 2135 hours0.0247 days <br />0.593 hours <br />0.00353 weeks <br />8.123675e-4 months <br />, he received a low steam generator level SFRCS trip.
ne reactor was r.anually tripped at 2136 due to increasing pressori:cr 1cvel and at the same time the pressurizer ele.romagnetic relief lifted. Unknown to the operator the electromagnetic r-nef failed to reclose resulting in a decrease of RCS pressure and r:sultant SFAS actuation at 1600 pounds psig. As a result of the caectromagnetic relief staying open and the quench tank cooling being isolated by the SFA5 actuation, the quench tank pressure increased and the rupttrre disc ruptured.
When the operator realized the electrceagnetic relief was not closed, the isolation valve was shut and RCS pressure stabilized.
High pressure injection which was initiated by SFAS was maintained in operation to assist returning the RCS pressure and pressurl:er level to nor:nal.
The e.ain steam isolation valves were reopened and the noraa'l Plant cooldown was started.
Tom Tambling, NRC Region III, telephoned at 1030 hours0.0119 days <br />0.286 hours <br />0.0017 weeks <br />3.91915e-4 months <br /> on Septerter'25, 1977.
/T2XH!ntT -
F R I ENilFICATIO'l ack Evans 7[ # M S. McCRYSTAL I
Station Superintendent Davis-Besse Nuclear Power Station Toledo Edison Company P00R ORIGINAL 1
9
UNITED STATES NUCLEAR REGULATORY COMMISSION 0FFfCE OF INSPECTION AND ENFORCEMENT
.,/Mpar WASHINGTON, D.C.
20555 Fnn toENTIFICATION IE Bulletin No.79-06A
- /7779 s. MccaysTAs.
Date:
April 14, 1979
-- / /
Page 1 of.5 REVIEN OF OPERATIONAL ERRORS AND SYSTEM MISALIGNMENTS IDENTIFIED DURING THE THREE MILE ISLAND INCIDENT Description of Circumstances:
IE Bulletin 79-06 identified actions to be taken by the. licensees of all pressurized water Erwer reactors.(except Babcock & Wilcox reactors) as a result of the Three Mile Island Unit 2 incident.
This Bulletin clarifies the actions of Bulletin 79-06 for reactors designed by' Westinghouse, and the response to this bulletin will eliminate the need to. respond to
~
Actions to be taken by Licensees:
For all Westinchouse pressurized water reactor facilities with an oper'ating license (the ahtions specified below replace those identified in IE Bulletin 79-06 on an item by item basis):
1.
Review the description of circumstances described in Enclosure 1 of IE Bulletin 79-05 and the preliminary chronology of the TMI-2 3/28/79 accident included in Enclosure 1 to IE Bulletin 79-05A.
~
This review should be, directed toward understanding: (1) the a.
extreme seriousness and consequences of the simultaneous blocking of both auxiliary feedwater trains at the Three Mile Island Unit 2 plant and other actions taken during the early phases of the accident; (2) the apparent operational' errors '
which led to the eventual core damage; (3) that the potential exists, under certain accident or transient conditions., to have a water level in the pressurizer simultaneously with the reactor vessel not full of water; and (4) the necessity to systematically analyze plant conditions and parameters and take appropriate corrective action.
Operational personnel should be instructed to: (1) not override I
b.
automatic action of ' engineered safety features unless continued operation of engineered safety features will result in unsafe plant conditions (see Section 7a.); and (2) not.make operational decisions based solely. on a single plant parameter indication when one or more confinnatory indications are available.
P00R:0RlGlNAl-G l
Date:
April 14,1979 Page 2 of 5
[
c.
All licensed' operators and plant management and supervisors with operational responsibilities shall participate in this review and such participation shall be documented in plant records.
2.
Review the 9.etions required by your operating procedures for coping with transients and accidents, with particular attention to:
Recognition of the possibility'of forming voids in t'he primary a.
coolant system large enough to compromise the core cooling capability, especially natural circulation capability.
b.
Operator action required to prevent the formation of such voids.
c.
Operator action requir'e'd to enhance core cooling in the event such voids are fonned.
(e.g., remote venting) 1 3.
For your facilities that use pres'surizer water level coi.ncident pressurizer pressure for automatic initiation of safety injection into the reactor coolant system, trip the low pressurizer level setpoint bistables such that, when the pressurizer pressure reaches the low setpoint, safety injection would be in tiated regardless of the pressurizer level.
In addition, instruct operators to manually initiate safety injection when the pressurizer pressure indication reaches the actuation setpoint whether or not the level indication i
has dropped to the actuation setpoint.
4.
Review the containment isolation initiation design and procedures, and prepare and implement all changes necessary to permit contain-ment isolation whether manual or automatic, of all lines whose isolation does not degrade needed safety features or cooling capa-bility, upon automatic initiation of safety injection.
5.
For facilities for which the auxiliary feedwater system is not l'
automatically initiated, prepare and implement imediately proce-1 dures which require the stationing of an individual (with no other i
assigned concurrent duties and in direct and continuous comunica-tion with the control room) to prcm
, feedwater to the steam generator (s)ptly initiate adequate auxiliary for those transients or acci-dents the consequences of which can be limited by such action.
l t
e
April 14, 1979 Page 3 of 5 6.
For you-facilities, prepare and implement imediately procedures which:
a.
Identify those plant indications (such as valve discharge j
piping temperature, valve position indication, or valve discharge relief tank temperature or pressure indication) which plant operators may utilize to determine that pres-surizer power operated relief valve (s) are open, and b.
Direct the plant operators to manually close the power operated relief block valve (s) when reactor coolant' system pressure is reduced to below the set point for normal. automatic. closure of the power operated relief valve (s) and the valve (s) remain-stuck open.
7.
Review the action directed by the operating procedures and training instructions to ensure that:
Operatorsdonotoverrideautomaticactionsofengibeered a.
safety features, unless continued operation of ' engineered safety features will result in unsafe plant condition,s.
For example, if continued operation of engineered safet'y features would threaten reactor vessel integrity then t.he HPI should.be secured (as noted in b(2) below).
b.
Operating procedures currently, or are revised to, specify that if the high pressure injection (HPI) system has been automatically actuated because of low pressure condition, it must remain in operation until either:
(1)
Both low pres'sure injection (LPI) pumps are in operation and flowing for 20 minutes or longer; at a rate which would assure stable plant behavior;.or.
(2)
The HPI system has been in operation for 20 minutes, and all hot and cold leg temperatures are at least 50 degrees below the saturation temperature for the existing RCS pressure.
If 50 degress subcooling cannot be maintained after HPI cutoff, the HPI shall be reactivated.
The degree of subcooling beyond 50 degrees F and the length '
of time HPI is in operation shall be limi.ted by the i
pressure / temperature considera,tions for the vessel integrity.
0 t b' l
.a
~
April 14, 1979 Page 4 of:35 Operating procedures currently, or are revised to, specify c.
that in the event of HPI initiation with reactor coolant pumps (RCP) operating, at least one RCP shall remain ope-ting for two loop plants and at least two RCPs shall remain operating for 3 or 4 loop plants as long as the pump (s) is providing forced flow.
d.
Operators are provided additional information and instructions to not rely upon pressurizer level indication alone, but to also examine pressurizer pressure and other plant parameter indications in evaluating plant conditions, e.g., water, inventory in the reactor primary system.
8.
Review all safety-related valve positions, positioning requirements and positive controls to assure that valves remain positioned (open i
or closed) in a manner to ensure the proper operation of engineered safety features.
Also review related procedures, such as those for maintenance, testing, plant and system startup, ar.d supervisory i
periodic (e.g., daily / shift checks,) surveillance to ensure that such valves are returned to their correct positions following necessary manipulations and are maintained in their proper posi-tions during all operational modes.
9.
Review your operating modes and procedures for all systems designed to transfer potentially radioactive gases and liquids out of the primary containment to assure that undesired pumping, venting or other release of radioactive liquids and gases will not occur inadvertently.
In particular, ensure that such an occurrence would not be caused by the resetting of engineered safety features instrumentation.
List all such systems and indicate:
a.
Whether interlocks exist to prevent transfer when high radiation indication exists, and b.
Whether such systems are isolated by the containment isolation signal.
c.
The basis on which continued operability of the above features is assured.
10.
Review and modify as necessary your maintenance and test procedures to ensure that they require:
a.
Verification, by test or inspection, of the operability of redundant safety-related systems prior to the removal of any safety-related system from service.
I I
.?
Date:
April 14, 1979 Page 5 of 5 b.
Verification of the operability of all safety-related systems when they are returned to service following maintenance or testing.
1 c.
Explicit notification of involved reactor operatienal personnel whenever a safety-related system is removed from and returned to service.
11 Review your prompt reporting procedures for NRC notification to assure that NRC is notified within one hour of the time the reactor is not in a controlled or expected condition of operation.
- Further, at that time an open continuous comunication channel shall'be-established and maintained with NRC.
12.
Review operating modes and procedures to deal with significant.
i amounts of hydrogen gas that may be generated during a transient or other accident that would either remain inside the primary system or be released to the containment.
j 13.
Propose changes, as required, to those technical specifications which must be modified as a result of your implement,ing the above items.-
For all light water reactor facilities designed by Westinghouse with an i
operating license, respond to Items 1-12 within 10 dayr of the receipt of this Bulletin.
Respond to item 13 (Technical Specif' cation Change proposals) in 30 dayt.
Reports should be submitted to the Director of the appropriate NRC P;gional Office and a copy should be forwarded to the NRC Office of Inspection and Enforcement, Division of Reactor Operations Inspection, Washington, D.C.
20555.
For all other power reactors with an operating license or construction permit, this Bulletin is for infonnation purposes and no written response is required.
l Approved by GAO, B180225 (R0072); clearance expires 7/31/80.
Approval was given under a blanket clearance specifict.11y for identified generic l
probiems.
l l
' - nclosure:
l List of IE Bulletins Issued in Last Twelve Months i
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