ML20092F172

Power Reactor EVENTS.November-December 1983

ML20092F172
Person / Time
Issue date:	05/31/1984
From:	Massaro S NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
To:
References
NUREG-BR-0051, NUREG-BR-0051-V05-N6, NUREG-BR-51, NUREG-BR-51-V5-N6, NUDOCS 8406230294
Download: ML20092F172 (48)

Text

NUREC/BR-0051 Vol. 5, No. 6

,..,'i POWER REACTOR EVENTS e

/

United States Nuclear Regulatory Commission I

Date Published: May 1984 Power Reactor Events is a bi-monthly newsletter that compiles operating experience information about commercial puclear power plants. This inciudes summaries of noteworthy events and listings and/or abstracts of USNRC and other pocuments that discuss safety-related or possible generic issues. It is intended to feed back some of the lessons learned f rom operational experience to the various plant personnel, i.e., managers, licensed reactor operators, training coor-dinators, and support personnel Referenced documents are available from the USNRC Public Document Room at 1717 H Street. Washington, DC 20555 for a copying fee. Subscriptions and additional or back issues of Power Reactor Events may be requested from the NRC/GPO Sales Program. (301) 492-9530 or at Mail Stop 016. Washington, DC 20555.

Table of Contents Page 1.0 SUMMAPIES OF EVENTS 1.1 Inoperable Containment Spray Systems..

1 1.2 Total Loss of AC Power.

4 1.3 Isolation of Flow from Charging Pumps to the RCS.

6 1.4 Large Diameter Pipe Cracking in Boiling Water Reactors -.

7 1.5 Nitrogen Bubble Formation in Reactor Vessel Head During Extended Outage -

11 1.6 Failed Fuel Assemblies and Damaged Thermal Shield --

12 1.7 Damage to Optical isolator Output Cards and Solid State Devices 14 1.8 Temporary Connection Between Air Storage Tank and Division 1 Diesel Generator.,

15 1.9 Main Steam Line Radiation Monitor Found with Trip Serpoint Greater than Three Times NormalBackground..,

16 1.10 Load Reduction Transient at Salem Unit 2._.

17 1.11 Errata / References.

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2.0 ABSTRACTS OF O THER NRC OPERA TING EXPERIENCE DOCUMENTS 2.1 Abnormal Occurrence Reports (NUREG-0090)..

22 2.2 Bulletins and information Notices 23 2.3 Case Studies and Engineering Evaluations _

30 2.4 Generic Letters 34 2.5 Operating Reactor Ewnt Memoranda 39 2.6 Regulatory and Technical Reports (NUREG-0304) -

40 Editor: Sheryl A. Massaro

^ tsociate Editor: James T. Fry Office for e,.alysis and Evaluation of Operational Data U.S. Nuclear Regulatory Commission Period Covered: November-December 1983 Washington, D.C. 20555 8406230294 840531 UDR NUREO R-OO51 R PDR

1. 0 SUMMARIES OF EVENTS 1.1 Inoperable Containment Spray Systems Tha following events at Indian Point Unit 2 and McGuire Unit la involved insperable containment spray systems due to personnel errors.

Indian Point Unit 2 On November 29, 1983, during a routine surveillance test at full power, two ccntainment motor operated spray header discharge valves (one located in each of the two containment spray supply headers) were found locked closed instead of locked open as required, with the associated circuit breakers locked in the off/deenergizcd position. This condition rendered the containment spray system insperable for automatic operation during the safety injection phase of a postu-lated loss-of-coolant accident (LOCA), although manual operation was still evallable.

Technical specifications require that two spray pumps (together with their associated valves and piping) and five fan cooler charcoal filter units be operable with the reactor critical.

However, the licensee's procedures are more restrictive in that the containment spray system is to be operational prior to T-ave going above 350'F.

It should be noted that, without containment spray at the time of the event, adequate cooling could have been provided by the five fan coil units.

The licensee determined that the containment spray system had been inoperable since the reactor went critical on October 25, 1983, due to the two closed dis-charge isolation valves.

During this period, the reactor had gone critical five times, initially on October 25, and after four subsequent reactor trips.

After the initial startup on October 25, the unit T-ave was continuously main-tained above 350*F.

The licensee's failure to meet technical specifications rcquirements prior to taking the reactor critical constitutes a violation of tschnical specification limiting conditions for operation.

Tiie containment spray system at Indian Point has two functions.

It is used in cenjunction with the containment fan coil units to provide containment cooling in the event of a LOCA and it also reduces the iodine concentration to limit the offsite dose.

The iicensee stated that calculations by Westinghouse, the nuclear steam system supplier (NSSS), indicate that the offsite dose from a LOCA would be at approximately the allowable 10 CFR Part 100 limits, without j

spray during the injection phase but with all five fan coil units operating.

l If the control room operator became aware that the containment spray was not j

cperating, a field operator could have been sent to the affected valve and-l motor control center and returned the system to normal operation.

• Indian Point Unit 2 is an 864 MWe (net) PWR located 25 miles north of New York City, New York, and is operated by Consolidated Edison.

McGuire Unit 1 is a 1180 MWe (net) PWR located 17 miles north of Charlotte, North Carolina, and is operated by Duke Power.

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The cause of the event is attributed to personnel error.

Prior to the plant going critical on October 25, 1983, the two valves had been closed in prepara-tion for work on the reactor coolant system.

On October 28, prior to plant startup, operators were assigned to perform a safety injection system check-off list, which should have returned the valves to the open position.

It was noted that valve position could not readily be confirmed by inspection and, since power is removed by the operator, remote indication was also not available.

However, the operator assigned to ensure the valve positions assumed that the valves were positioned by another operator, and the operator assigned to verify the valve positions assumed the valves were locked open because the breakers were locked and deenergized.

Although during an accident the reactor operators would be expected to recog-nize in a timely manner that the containment spray isolation valves were closed, the NRC staff performed bounding calculations to predict worst case conditions i

pertaining to containment design pressure and post-accident offsite doses.

The plant has two trains of fan coolers on separate power sources; one train has two fan coolers and the other train has three tan coolers.

Since, for the present situation, both containment spray trains would be out of service, the staff assumed a single active failure would reduce the active containment heat 1

removal capability to two fan coolers during a pipe break accident.

Under l

these conditions, the reduced heat removal capability would be expected to l

result in a higher peak containment pressure.

In addition, less filtration of radiaactive iodine would be expected to result in higher offsite doses.

The peak NRC calculated containment pressure for the design basis LOCA (double-j ended pump suction guillotine break) is 41.9 psig, which is slightly above the licensee's previously calculated peak pressure of 40 psig (with containment sprays) but substantially below the containment design pressure of 47 psig.

With regard to offsite dose calculaticas, the methods and assumptions used by the NRC staff were consistant with those used in the current licensee applica-tion reviews (i.e., Standard Review Plan 15.6.5).

The calculations predict that the resultant doses would be approximately four times the 10 CFR Part 100 thyroid exposure guidelines at the Exclusion Area Boundary.

An additional l

analysis was performed assuming that operator action was taken to initiate con-tainment spray after 30 minutes.

This calculation indicates that the resultant dose sould be approximately 1.8 times the exposure guidelines at the Exclu:ica Area Boundary.

Both the licensee's/ vendor's calculations based on actual operating conditions, 7

and the NRC staff's calculations based on much more conservative conditions, i

emphasize the importance of the containment sprays-in reducing potential off-site iodine doses in the unlikely event of a LOCA.

As corrective actions, the licensee opened the affected valves,. reverified the.

safety injection and locked valves list, and verified the inclusion of the two valves on the locked valves list.

i Among long term corrective action steps are a number of improvements in the-licensee's quality assurance.and training programs.

In addition-i (1) A review of valve position indicat!on.-for all safety-related valves will be made to determine if modifications are necessary to provide for posi-tive indication of deenergized valvds.

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1 (2) The operability of all currently installed safety-related motor-operated valve position indicators will be verified and corrected if necessary.

I Thn NRC has proposed a $40,000 civil penalty for the regulatory violations associated with this event.

McGuire Unit 1 While operating at full power on September 28, 1983, train B of the containment spray system (CSS) was declared inoperable.

This declaration was made following a loss of power indication for the dc power supply to the train B containment prassure control system (CPCS) pressure transmitter.

Both trains (i.e., A and B) of the CSS are required to be operable by technical specifications.

Hoover, en action statement permits operation for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with one train inoperable.

On September 29, an operator was sent to inspect nuclear service water (NSW) pump 1A.

The operator noted water in the oil reservoie for the outboard pump bzaring.

The pump was declared inoperable by the Shift Supervisor and the Assistant Operating Engineer, which meant that train A of the NSW system also was inoperable.

The NSW system provides cooling to the CSS heat exchanger and the air handling unit motor cooler for the CSS pump.

Therefore, the inoperability of train A of NSW caused train A of CSS to be inoperable.

CSS train A inoperable coincident with the inoperability of train B of CSS resulted in the inoperability of both CSS trains, and placed the unit outside the Action Statement of Technical Soeci-fication 3.6.2.

This inoperability was confined to the recirculation mode of op2 ration of the CSS.

l Tha impact of the inoperable NSW train upon the single remaining operable CSS train was not realized when NSW pump 1A was tagged out. Thc discovery that i

both CSS trains had in fact been inoperable was made when CSS train B was being cleared from the Technical Specification Action Item Log (TSAIL).

The tech-nical inoperability of both trains existed for approximately five hours on September 29.

Tha Tec iical Specification Reference Manual provides a list of related tech-nical specifications with appl 1 cable modes to be considered when a system is dIclared inoperable.

As a result of this incident, the list of related tech-nical specifications was reviewed and it was discovered that the NSW system's ir. pact upon CSS and on DG-1A was not addressed by the' reference manual.

Other systems which depend upon NSW for operability and are required during p:wer operation are the chemical and volume control system, auxiliary feedwater system, component cooling water system, control area ventilation system, and thm diesel generator (DG).

All of these systems had the redundant train oper-(ble when the NSW train became inoperable.

However, a requirement exists to-d;clare dependent systems inoperable when a support system is taken out of strvice.

The common but'not totally uniform approach used when declaring a i-support system inoperable is to list dependent. systems in the TSAIL.

This cpproach was not. applied when NSW pump 1A was declared inoperable.

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Thus, with DG-1A inoperable due to loss of NSW pump 1A, certain action state-ments of the associated specification were appifcable.

Compliance with Tech-nical Specification Action Statement 3.8.1.1, was not achieved during this incident.

This required (1) that an active test of DG-18's operability be performed by starting the DG and verifying generator parameters, and (2) that required equipment relying on DG-1B as an emergency power source, and the tur-bine-driven auxiliary feedwater pump, be verified to be operable.

Since the dependency of systems upon NSW train A was not evaluated and DG-1A was not declared inoperable, these actions were not met, i

The causes of this event were the failure of the power supply for the contain-ment pressure control system and the clogging of the drain line for the NSW pump 1A seal catch basin, which allowed water to back up and enter the outboard bearing.

The failure to identify the impact of NSW train A on CSS train A's operability is attributed to personnel error.

Appropriate personnel were counseled and a technical specification manual was revised.

As corrective actions, the power. supply was replaced, the NSW pump outboard l

seal catch basin drain line was cleared, and the bearing was inspected for damage and flushed with oil.

The oil reservoir was then refilled with clean oil.

Also, a memorandum was issued September 30, 1983.

This memorandum was addressed to all Senior Reactor Operators and stated the policy of declaring all dependent systems inoperable (and making the appropriate TSAIL entries) f-whenever a support system is-declared inoperable.

Technical Specification Reference Manual-Section IV was updated to include the impact of NSW systems on CSS operability.

(Refs. I through 3.)

1. 2 Total loss of AC Power At Fort St. Vrain* (a high-temperature gas-cooled reactor) in May 1983, an event occurred in which all ac power to the station was temporarily lost.

Sub-I sequent investigations showed that the event was attributed to the interconnec-tion of the emergency diesel generator with an offsite grid that had developed i

problems during a storm.

The. event illustrates how operating the emergency diesel generators in parallel with the offsite grid can compromise their ability-to function as designed in an emergency.

On May 17, 1983, with the reactor shut down and the 1A emergency diesel genera-tor (EDG) set shut down for planned maintenance, the offsite power system developed problems due to severe weather conditions. The 18 EDG ws started and tied to the IC essential bus (EB) and operated in parallel with the plant-electric distribution system, which was being supplied by the offsite power i

system.

Thirty minutes later, all offsite power was lost to the station due to high winds and snow.

I Normally, on a loss of offsite power and turbine trip the EDGs start and'. load shedding relays actuate to strip the 480 V EBs of-all electrical loads.

The load shedding relays are then automatically reset when voltage on either the IA-or.1C 480 V E8 is reestablished via the respective EDG set.

Essential 1oads are then picked up by the load sequencer associated with the EDG set.

Fort St. Vrain is a 330 MWe (net) HTGR-located 35 miles north of Denver, l

Colorado, and is operated by Public Service of Colorado.

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At Fort St. Vrain, the load shedding circuit for each EDG includes four time dalay relays (227-1A and -1C that monitor voltage losses on the 1A 480 V EB and 227-3A and -3C that monitor voltage losses on the IC EB).

During the event, two of these relays (227-3A and -3C) remained deenergized even after the 1B EDG htd reenergized the IC 480 V EB due to burned out coils.

The other two relays (227-1A and -1C) also remained deenergized since the 1A EB had no power (loss of offsite power and 1A EDG out of service).

With all four relays deenergized, ths load shedding circuit remained in the tripped state (energized) and pre-vsnted the loads on the 1C and IB EBs from sequencing as designed.

l Tha relays that failed were voltage monitoring relays on the 1C EB.

At the time of the loss of offsite power, the IB EDG was operating in the parallel configuration described earlier.

It is possible that the relays failed due to this method of operation.

Voltage surges propagated from the unstable offsite I

grid system combined with voltage transients at the EDG could have caused or contributed to the relay failures.

In addition, a review of existing test 1'

procedures for the diesel generators found that, due to procedural inadequacy, these time delay relays are not tested as individual components on a regular i

basis.

Thus, the failures of these relays would remain undetected during 1

n2rmal surveillance testing.

Only due to the uniqueness of the event were the coil failures discovered.

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The operation of the onsite emergency power source (the EDG) in parallel with an unstable grid system can compromise its ability to function as the onsite emergency power source. The potential adverse effects are-(1) the EDGs would b2 exposed to voltage surges propagating from the troubled offsite power system which could cause immediate or cumulative damage to the EDGs and associated d

centrol circuitry, (2) the EDGs would be overloaded if offsite power was lost

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and would require the proper functioning of the EDGs' protective circuits to ssparate the EDGs from the plant's electrical distribution system, and (3) the subsequent restart of the emergency onsite power system would require the j

proper functioning of the automatic load shedding and load sequencing circuits

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whose components may have been exposed to the voltage surges in item (1) above.

A review of operating experience and practice shows that there is variation in the methods.of operating onsite emergency power sources at nuclear plaats during situations when the offsite power system is experiencing problems.

The method of parallel operation used at Fort St. Vrain may be used in other nuclear power plants as well, however, there appears to be no advantage to this type of opera-tion.

As seen at Fort St. Vrain,-when offsite power is lost, the EDG tends to overload and will either trip or disconnect from.the emergency bus.

Also, problems in the offsite power source could propagate to the onsite emer-g;ncy system and affect-its. operation.

Thus, the intent of this operating j

ccnfiguration, that of maintaining the plant's emergency. loads when offsite power is lost, is not attained.

It should be noted that Fort St. Vrain was maintained without much difficulty in a safe shutdown. condition, mainly;because the large heat capacity of a gas-cooled reactor. core provides adequate time to censider and resolve such problems as~ occurred during this event.

However, a similar total loss of ac power conditions at a light water reactor would pro-vide an operator with much'less time to act.

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An alternate method of operation would be to start the EDGs when offsite power problems are encountered and keep them running unloaded, ready to energize the EBs when offsite power is lost.

Another method would be to start the EDGs and energize the associated emergency buses and loads and then isolate the emergency i

power system from the offsite power system that is experiencing problems.

i The licensee tested all four ti.ne delay relays and replaced the faulty ones.

A new procedure for testing these relays was developed by the licensee and was implemented in July 1983.

However, the use of these time delay relays in the above described configuration appears to be unique to Fort St. Vrain and, hence, has no implication on other nuclear power plants.

NRC is reviewing the practice i

of parallel operation of the onsite emergency power sources with the grid system.

(Refs. 4 and 5.)

1.3 Isolation of Flow from Charging Pumps to the RCS

]

In September 1983, an event occurred at San Onofre Unit 3* in which the closing of two manual isolation valves isolated flow from the charging pumps to the reactor coolant system (RCS) and violated technical specifications.

As a result of excessive unidentified leakage from the RCS, Unit 3 was placed in hot standby on September 29, 1983, and action was initiated to localize the

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source of the leakage.

This action was in accordance with limiting conditions for operation (LCOs).

In preparation for cooldown, the RCS was borated to the shutdown margin required for hot shutdown conditions, which exceeds the shutdown j

margin for cold shutdown conditions.

Cooldown was then commenced in parallel with continuing efforts to locate the leakage source. During swing shift on September 29, charging flow was isolated by closing manual isolation valves for the makeup system in accordance with an abnormal valve lineup provided to the Operating Foreman by the Plant Superin-tendent.

This abnormal lineup was developed as an effort to locate the leakage source.

RCS was being held constant at about 480*F in order to measure the leak rate accurately.

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On September 30, as the leak rate check with these valves secured was being

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completed, the graveyard Shift Supervisor recognized that the' shutting of the two valves violated the technical specifications.

Shutting of these valves represented isolating flow from the charging pumps to the RCS, and is incon-4 sistent with LCOs for boration flow paths via the charging pumps and emergency core cooling system subsystems during hot standby operation.

He immediately ordered the valves to be opened.

The valves had been closed for about 3-1/2 i

hours.

The cause of this event was personnel error in that the abnormal lineup was not reviewed relative to technical specification requirements.

The lineup was docu-mented and reviewed in accordance with the abnormal valve lineup section of the work authorization procedure.

Although a revision to the abnormal valve lineup

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procedure was issued on September 13 to more specifically call out the need to i

• San Onofre Unit 3 is a 1070 MWe (net) PWR located 5 miles south of San l

Clemente, California, and is operated by Southern California Edison.

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raview abnormal lineups relative to technical specification requirements, training in the revision had not yet been provided to the operating shifts, and tha abnormal valve lineup section of the work authorization procedure had not basn revised to refer to the revision.

As corrective action, special training in the revised abnormal valve lineup procedure was provided in shift briefings, and additional training will be c

j included in the requalification program.

Applicable sections of the work

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tuthorization procedure have.been revised to refer users of the procedures to the control of system alignments procedure when performing abnormal system alignments.

Personnel involved have been counseled.

In addition, acceptable means for isolating systems for the purpose of determining RCS leakage will be procedurally specified.

(Refs. 6 and 7.)

1. 4 Large Diameter Pipe Cracking in Boiling Water Reactors On March 23, 1982, Nine Mile Point Unit 1* reported an event involving leakage from welds on two nozzles connecting recirculation system piping to the reactor i

vessel.

The leakage was discovered during performance'of a routine hydrostatic pressure test prior to return to operation from a scheduled maintenance outage.

Subsequent inspections and evaluations showed extensive intergranular stress corrosion cracking (IGSCC) in heat affected zones near weld areas of large diameter (28-inch) piping in the reactor coolant recirculation system.

After extensive analysis and review the licensee decided to replace the recirculation piping in all five recirculation loops, all ten safe ends, and branch piping as i

warranted by inspection and evaluation.

The replacement material is of a type i

less susceptible to IGSCC.

Cracking in austenitic stainless steel piping in BWRs has been observed for j

many years. Although cracking in large diameter piping had been reported on some foreign reactors, the findings at Nine Mile Point Unit 1 were the first j

examples of major cracking in large diameter piping in the United States. - The j

causes of IGSCC are not fully understood, and are being investigated extensively, i

The NRC issued Inspection and Enforcement (IE)Bulletin 82-03, Revision 1 (Ref. 8) in October 1982 for action by nine BWR plants scheduled for refueling outages in late 1982 and early 1983. -Inspections pursuant to this bulletin showed cracking in five of the first seven plants examined, prompting issuance of IE Bulletin 82-03 in March 1983. -(Ref. 9.) This bulletin required augmented inspection of welds in the recirculation system piping,.using ultrasonic testing i-(UT) inspection procedures of demonstrated effectiveness, for all plants beyond those identified in Bulletin 82-03, Revision 1, at their next refueling or

~ extended. outage but no later than January 1984.

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• Nine Mile Point Unit 1 is a 610 MWe_(net) BWR located 8 miles northeast of l

Oswego,-New York, and is operated by Niagra Mohawk Power.

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As of early July 1983, five plants (Browns Ferry Unit 3, Brunswick Unit 2, Dresden Unit 3, Pilgrim Unit 1, and Quad Cities Unit 2)* had not yet begun inspections.

These plants were scheduled for inspections at various times

' rom August 1983 through January 1984.

However, the NRC concluded that these uninspected facilities may have IG5CC, which may be unacceptable for continued safe operation without inspections and repair or replacement of the affected pipes and additional surveillance requirements.

Therefore, on July 21, 1983, the NRC sent letters to the licensees of the five uninspected plants requesting that by August 4,1983, they submit information regarding justification for continued operation, costs and impact of conducting the inspections on an accelerated schedule, availability of qualified personnel, and other bases to j

support their previously established schedules for IGSCC inspections.

On August 8 and 9, the NRC staff met with licensee representatives from the five BWR plants yet to be inspected to discuss their responses to the NRC let-ters.

As a result of the meeting, accelerated schedules for inspections and interim additional compensatory measures (improved leak detection capability, i

emergency core cooling system availability, and operator training) wore com-mitted to by the licensees.

The staff evaluated the information and commit-ments received from the licensees.

On August 26, the NRC issued orders for each of the five plants that would confirm these accelerated inspection schedules and impose new interim compensatory measures, or confirm compensatory measures proposed by the licensees.

Inspections conducted in response to the IE bulletins as well as the other inspection requirements revealed extensive cracking in both large diameter recirculation and residual heat removal system piping welds at several facilities.

Table 1 is a summary of the cracking observations from BWRs where piping has been examined and defects found, and indicates the extent of cracking in large diameter recirculation and RHR system piping as of March 1984.

Throughout the month of October 1983, the NRC staff drafted requirements for reinspection of plants inspected under the provisions of the IE Bulletins, and criteria for repair and/or replacement of piping.

At a meeting with BWR licensees on October 21, the NRC staff described the development of these plans and brought the industry up to date on tha pipe crack issues.

At the same meeting, the licensees described their past and planned future actions regard-ing inspection, repair, and replacement.

These meetings with licensees as a group, and individual meetings with licensees to discuss specific proposals, continued in late October and into November 1983.

• Browns Ferry Unit 3 is a 1065 MWe (net) BWR located 10 miles northwest of Decatur, Alabama, and is operated by Tennessee Valley Authority.

Brunswick Unit 2 is a 790 MWe (net) BWR located 3 miles north of South Port, North Carolina, and is operated by Carolina Power and Light.

Dresden Unit 3 is a 773 MWe (net) BWR located 9 miles east of Morris, Illinois, and is operated bv Commonwealth Edison.

Pilgrim Unit 1 is a 670 MWe (net) BWR located 4 miles southeast of Plymouth, Massachusetts, and is operated by Boston Edison.

Quad Cities Unit 2 is a 769 MWe (net) BWR located 20 miles northeast of Moline, Illinois, and is operated by Commonwealth Edison.

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12" - 28" Pipe Welds No.

No.

Plant Name Licensee P1 ant Location Examined Defective *

-Big Rock' Point Unit 1 Consumers Power Co.

Charlevoix County, Michigan 11-0 Browns Ferry Unit 1**

Tennessee' Valley Authority Limestone County, Alabama 123 47 Browns Ferry. Unit.2 Tennessee Valley hthority Limestone County, Alabama 34 2

Browns Ferry Unit 3-Tennessee Valley Authority Limestone County, Alabama 191 0

Brunswick Unit 1 Carolina Power & Light Co.

Brunswick County, No. Carolina 32 3

Brunswick Unit' 2 -

Carolina Power & Light Co.

Brunswick County, No. Carolina 131 16-Cooper ***

Nebraska Public Power Dist.

Nemaha County, Nebraska 135 20

-Dresden Uni.t 2 Connonwealth Edison 'Co.

Grundy County, Illinois 51 10 Dresden Unit 3 Comonwealth Edison Co.

Grundy County, Illinois 240 64 Duane Arnold Iowa Electric Power & Light Linn County, Iowa 51 0

m FitzPatrick Power Authority of the Oswego County, New York 55 1

State of New York Hatch Unit 1 Georgia Power'Co.

Appling County, Georgia 58 7

Hatch Unit 2**

. Georgia Power Co.

Appling County, Georgia 108 39 Millstone Unit l'-

' Northeast Nuclear Energy Co.

New London County, Connecticut-11 0

Monticello**

Northern States Power Co..

Wright County, Minnesota 135 6

Nine Mile Pt. Unit 1 Niagara Mohawk Power Co.

Oswego County, New York

'0yster Creek Jersey Central Power & Light Ocean County, New Jersey 31 0

' Peach Bottom Unit 2**

Philadelphia Electric Co.

York County, Pennsylvania 123 26 Peach Bottor. Unit 3 Philadelphia Electric Co.

York County, Pennsylvania 111 15 Pilgrim Unit 1**

Boston Edison Co.

Plymouth County, Massachusetts

. Quad Cities Unit 1 Commonwealth Edison Co.

Rock Island County, Illinois 18 0

(Quad'CitiesUnit2 Commonwealth Edison Co.

Rock Island County, Illinois 225 22

' Vermont Yankee Vermont Yankee Nuclear Power Windham County, Vermont 60 34

• None exceeded crack propagation criteria.

• • Replacing pipe.

• • • Plannina pipe replacement.

During the inspection process, questions wera raised regarding the reliability of the UT inspection techniques.

In conjunction with the NRC bulletin activi-ties, joint efforts by the NRC and industry were begun to train and qualify inspection personnel, using improved UT procedures on well characterized pipe cracks in pipe segments removed from Nine Mile Point Unit 1, to assure higher reliability in the inspection process.

In general, the probable consequences of small cracks are crack propagation and minor leakage of primary coolant.

When small but measurable leaks occur, leak-age monitoring systems detect the change of leak rate, and a plant shutdown is required if allowable leak rate limits are exceeded.

Licensees are also required to perform periodic inspections of piping to detect evidence of pipe cracks and repair or replace piping, if necessary.

Redundant core cooling systems also are available to provide cooling of the core even in the remote case of a pipe failure.

However, the Nine Mile Point Unit 1 results and subsequent inspections performed on other BWRs resulted in increased safety concern regarding the extensive range of pipe sizes involved, the large number of plants affected, the size and number of cracks, the adequacy of detection and characterization of such cracks, the repair techniques, and the adequacy of licensees' compensatory measures (leak detection capability, emergency core cooling system availability, and operator training).

Although IGSCC in the sensitized material of the heat-affected zone in BWR piping is influenced by the environmental conditions existing in the BWR reactor coolant system and stresses in the piping, including residual stresses induced by welding, there is no clear correlation between the extent of cracking and operating time.

Some plants with a relatively brief operating history, e.g., Hatch Unit 2,* show extensive cracking.

The licensee for Hatch Unit 2 will replace the affected piping in 1984.

As corrective actions to prevent recurrence, inspections of piping either have been or are being made in accordance with IE Bulletins 82-03, Revision 1, and 83-02. Where cracking is observed, resolution is in accordance with NRC require-ments, as discussed below.

Efforts continue to train and qualify inspection personnel, using improved UT procedures, to assure higher reliability in crack detection and sizing.

The Electric Power Research Institute (EPRI) is involved in programs for the detection and characterization of cracks, and is working with the licensees in formulating qualifications programs for weld inspectors.

Included in EPRI's efforts is a "round robin" program to compare crack depth measurements made by UT.versus results of actual destructive examinations.

EPRI is also conducting a large number of UT operator training courses to upgrade the capabilities of inspection teams in detecting and sizing IGSC cracks, based on the results from the round robin.

The NRC is participating in portions of this program.

A cooperative effort between EPRI and the BWR Owners Group has also concentrated on developing remedial measures for both operating plants and plants under construction to extend the service lifetime of piping systems.

General Electric, the nuclear steam supply system vendor for the BWRs, has also been involved in studying field and laboratory data on cracks caused by inter-granular stress corrosion, rate of crack propagation, as well as suitable

• Hatch Unit 2 is a 748 MWe (net) BWR located 11 miles north of.Baxley, Georgia, and is operated by Georgia Power.

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remedial measures.

A number of remedial measures have been developed, quali-fied, and implemented.

These include solution heat treatment, alternate nuclear grade materials, heat sink welding, induction heating stress improven,ent, and wald. overlay.

Startup de-aeration techniques and the use of hydrogen water chemistry are currently being investigated as a means of retarding the rate of IGSCC.

The NRC is closely involved in the licensees' and the vendors' efforts to assure proper detection, characterization, and resolution of the cracking problem.

The NRC staff has been reviewing the inspection results of each plant on a case-by-case basis.

For the licensees which had r.ot yet made inspections required by the IE Bulletins, interim compensatory measures (e.g., improved leak detection capability, emergency core cooling system availability, operator training) were established where necessary.

In general, for those plants where cracking has been observed, repairs, analysis and/or additional surveillance conditions were required. Where repair was proposed, consideration was given to the strength (relative to ASME Code margin) of the repair, its effect on the piping system, and further inspectability. Where repair was not proposed, con-sideration was given to uncertainties in the measurements of cracking depth and to projected growth of cracks during subsequent operation.

NRC staff evaluation criteria require maintaining the inherent factor of safety prescribed by Sec-tion III of the ASME Boiler and Pressure Vessel Code for normal and faulted conditions with consideration of the uncertainties in crack size and growth rate.

(Ref. 10.)

1.5 Nitrogen Bubble Formation in Reactor Vessel Head During Extended Outage Between November 18 and 27, 1983, while in an extended cold shutdown outage (since February 1982), San Onofre Unit 1* experienced the unexpected formation of a nitrogen gas bubble in the reactor vessel head.

The bubble was discovered as a result of investigations of unexplainable increases in pressurizer water 1svel.

The event described below illustrates the continuing need to independ-antly and concurrently assess the various factors (i.e., liquid, gas, pressure, ttmperature, etc.) that can cause pressurizer level changes to occur.

On November 18, 1983, with one power operated relief valve (PORV) out of service, the reactor coolant system (RCS) was lowered to an indicated pressurizer level of less than 50% in order to meet the intent of a pending technical specifica-tion change which requires two operable PORVs whenever pressurizer water level is greater than 50%.

Also, in accordance with an operating instruction, the volume control tank (VCT) was pressurized to 45 psig to allow RCS charging and letdown using pressure rather than a charging pump as the motive force for flow.

Experience had shown that a high differential pressure develops across a control valve during charging pump operations with the RCS depressurized, which is detrimental to the valve and its seating surfaces.

During the next three days, the pressurizer level increased 2% to 3% each day.

Operators looked for possible sources of inleakage from adjoining systems.

Once on November 21, and twice during the subsequent five days, pressurizer level was lowered to stay below the 50% level, while the search for suspected inleakage continued.

• San Onofre 1 is a 436 MWe (net) PWR located 5 miles south of San Clemente, California, and is operated by Southern California Edison.

11

t l

l i

On November 27,'the plant staff concluded that no liquid inleakage path existed I

which could account for the continued increase in the pressurizer level, and that the increase in pressurizer level could be caused by gas ingress into the RCS.

To check for.a gas bubble, the reactor vessel head was vented.

As a result of this venting, identified pressurizer level decreased from 45% to 16%

in 2-1/2 hours.

The pressurizer level was restored by charging 3684 gallons into the RCS.

The licensee attributed the cause of_the event to the increased nitrogen gas pressure used in the VCT to force charging flow to the RCS.

Since the solu-

]

bility of nitrogen gas is less in the reactor vessel head location than it is l

in the VCT, nitrogen gas came out of solution in the RCS and collected in the j

reactor vessel head.

i As corrective action, the licensee reduced the VCT nitrogen pressure to 35 psig, and the reactor vessel head will continue to be periodically vented when nitro-gen pressure is used in the VCT as the motive force for charging flow.

The licensee informed all operating shifts of this occurrence and the manner in which it developed.

In addition, the operating instruction has been rewritten to include directives for venting a nitrogen accumulation in the reactor vessel head.

The licensee also committed to evaluate alternate methods of providing charging flow to the RCS with the unit in cold shutdown.

l Had the nitrogen generation continued, reactor vessel level would not have been depressed below the top of the hot leg piping.

The geometry of the vessel is such that.it would inhibit the core uncovering under the existing plant condi-tions.

(Ref. 11.)

1

1. 6 Failed Fuel Assemblies and Damaged Thermal Shield j

l During Cycle 5 operation of Millstone Unit 2,* a Combustion Enginering (CE) e designed plant, the licensee noted elevated levels of radioactive iodine and other fission products in the reactor coolant.

By the end of the cycle, the primary system activity was about 2% of the plant's technical specification limit; this was indicative of 10 to 30 fuel pin failures.

l The plant was shut down on May 28, 1983,-for refueling and maintenance.

The licensee established a fuel pin failure investigation program.

Fuel sipping (analysis of the fuel assembly for leakage of fission products) was conducted on the entire core, and 26 fuel assemblies were identified which had one or j

more failed fuel pins.

Five of the assemblies were supplied by one vendor and were scheduled for discharge at the end of Cycle 5; these assemblies had been irradiated for three cycles.

Twenty-one of the assemblies were supplied by l

anotFar vendor and had been scheduled for reinsertion for Cycle 6; these assen-j

'bljes had seen no more than one or two cycles of operation.

Ultrasonic. inspections showed that there were 32 failed fuel pins in the 26 fuel assemblies.

The licensee evaluated a number of possible; failure mechanisms'and concluded-that the failures apparently resulted from multiple sources, none of e

i l

l

• Millstone Unit'2 is an 860 MWe-(net) PWR located 5 miles southwest of New-London, Connecticut and is operated by Northeast Nuclear Energy.

I 12 l'

which were indicative of a situation that may lead to continued serious degrada-tion of the fuel cladding.

For example, there was evidence of debris induced w:ar of the cladding and one case of confirmed grid spring / fuel rod fretting.

The probable cause of the latter was a damaged cell, most likely related to either fuel manufacturing or handling.

To reduce the possibility of debris induced wear, the licensee performed an extensive cleanup of the primary system.

Visual inspections revealed that 15 fuel assemblies had broken holddown springs.

-The probable cause was attributed to flow induced vibration, near the core periphery, leading to fatigue failure of the springs.

The licensee's analysis concluded that, although broken, the springs remained functional and the assem-blies could continue in operation.

Redesigned springs were placed on all new fuel assemblies.

Further inspections revealed two fuel assemblies with structural damage; one of the two also had a broken holddown spring.

However, the requirements for struc-tural integrity, such as strength and loading capability, were still met for normal as well as for accident conditions by these fuel assemblies.

The cause was attributed to insufficent gap clearances between the assembly structurals and the fuel alignment plate.

Additional clearances will be incorporated into new fuel assemblies.

The problems described above necessitated a revision to the licensee's origi-ns11y planned reload core for Cycle 6.

A combination of new and previously discharged fuel assemblies were used to replace the leaking and two damaged fuel assemblies.

Nine fuel assemblies, each with a single broken holddown spring, were also used for Cycle 6 (the licensee decided that repair of these springs on the irradiated fuel assemblies would involve a high risk of damage to fuel pins).

As part of the scheduled shutdown activities, the reactor vessel internals were inspected.

Damage was noted to both the thermal shield and the core barrel.

The damage appeared similar to that experienced at St. Lucie Unit 1,* another CE designed facility.

The damage incurred at St. Lucie 1 is described in Appendix C of Ref. 12.

(See also Power Reactor Events, Vol 5, No. 3, pp. 14-15.)

As described in that report, it is believed that the damage to the thermal shield was not a single event, but rather occurred over a period of time and wts related to mechanical stress caused by flow induced vibrations.

Also as discribed in the report, the use of a thermal shield is an optional design in CE plants.

The licensee for Millstone Unit 2 decided to operate the plant in the future without the thermal shield.

The thermal shield was therefore removed and the minor damage to the core support barrel was repaired.

The Cycle 6 core reload changes, together with operation without the thermal shield, were submitted to the NRC for approval.

NRC approval was granted on December 30, 1983 and the plant achieved criticality on January 5, 1984.

The number of fuel pins which failed constituted less than 0.1% of the total number of fuel pins in the core. -The resultant primary activity was only a small fraction of the technical specifications limitations.

(Refs. 13 and 14.)

• St. Lucie Unit 1 is an 822 MWe (net) PWR located 12 miles southeast of Ft.

Pierce, Florida, and is operated by Florida Power and Light.

13

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1.7 ' Damage to Optical Isolator Output Cards and Solid State Devices i

At Grand Gulf Unit 1* in August of 1983, an event occurred in which residual heat removal (RHR) pump A failed to start, Division 1 buses were incorrectly shown tripped, and numerous annunciators on the Division 1 control room panel incorrectly alarmed.

The event was attributed to imposing an ac voltage onto a dc voltage circuit, and shows how this method of operation damages voltage sensitive components.

1 The cause of the event was personnel error, in that a computer cable was incor-rectly terminated in a motor control center across ac relay contacts.

As cor-rective action, the computer cable was disconnected and the licensee has initiated a program to eliminate future constructico error through closer super-i vision at work activities, trainirig, improved inspections, and clearer work instructions.

All solid state breaker trip devices in Division 1 have been inspected and tested and no damage was found.

The effects on safety were 4

limited to Division 1 with the plant in cold shutdown.

A detailed description of the event follows.

On May 27, 1983, a computer cable which provides a signal to the computer when an automatic start of the drywell recirculation fan unit A occurs was incor-rectly terminated during a drywell ventilation modification which added the recirculation fan to the system.

The cable should have been terminated across a set of isolated relay contacts but was instead incorrectly terminated across the overload (OL) device in the 120 V ac control circuit for recirculation fan unit A in its motor ccrtrol center (MCC).

The power for the computer cable is supplied from a 125 V dc bus through an isolation panel.

The breaker to the recirculation fan was not closed until August 3, 1983, to perform preoperational testing.

Therefore, no electrical interconnection between ac and dc existed prior to this date.

When the breaker was closed, no adverse effects occurred because the OL device was closed; therefore, no ac-current flowed into the de circuits.

As part of preoperational testing, the OL device and the penetration cabinet failure relay contact were opened and closed on the evening of-August 3, 1983, i

and the morning of August 4.

The opening and closing of these contacts inserted and then removed the 120 V ac on the 125 V dc bus.

This resulted in the fol-lowing effects:

(1) An optical isolator output card in the RHR A pump trip circuit failed, which caused a continuous pump trip; (2) A continuous trip occurred on a standby service water system load center i

breaker; and (3) ' Numerous annunciators on the Division 1 control room panel incorrectly al armed.

• Grand Gulf Unit 1 is a 1250 MWe (net) BWR and was granted-a low power license in June 1982.

It is located 25 miles south of Vicksburg, Mississippi, and is operated by Mississippi Power and Light.

14

Previous incidents of ac voltage being imposed on a dc voltage circuit occurred during the preoperational phase of startup.

These resulted from imilar wiring l_

. errors in construction and design.

Applying 120 V ac on the 125 V de logic and J

L centrol circuits will not generally damage wiring, relay coils, contacts, and most instruments if the voltage is not excessive.

However, it can be expected to. damage optical isolator output cards and other solid state devices.

Whether components are damaged depends on their logic arrangement in the. associated

-circuits during the time the ac is present.

It can also affect the operation

-of non-solid state devices; e.g., a relay may not deenergize with ac present.

~

The. optical isolator. output card in the RHR pump trip logic circuit was damaged as a result of the ac voltage during this event.

Only two isolators are con-n:cted ^directly to the Division 1125 V dc bus. One was not damaged because

-the output card was in parallel with other relay contacts that were closed.

The r_elay contacts parallel with the other were open, thus the ac current flowed through the output side and destroyed the output transistors.

This type of optical isolator would be expected to fail if ac' voltage is present.

The isolator output card was manufactured by General Electric.

The model number is 20486188AAG2 and the serial number is TWRE5-17.

The emergency safety _' features 480 V standby service' water load center breaker gave dual indication during the time the ac voltage was present on the de bus,

.and then tripped. The breaker is equipped with a solid state trip device, and its control circuits receive power from the Division 1 125 V dc bus.

The ac voltage apparently caused a trip' signal from the solid state trip device, but no damage to the device.

The licensee decided not to perform extensive inspection and testing of other components within the 125 V dc Division-1 system because:

(1) Past experien'ce showed that low ac voltage (less than or equal to 120 V ac) did not damage.non-solid state devices; (2) The 18-month' surveillance on the affected circuits and components were to be performed within the next 30 days, including the 18-month diesel gen-erator loss of coolant accident / loss' of-offsite power tests; (3) The solid state trip devices in all of the safety-related breakers'were scheduled to be inspected : tested and possibly replaced.duelto an unre-lated potential failure.previously reported; and (4) ' Daily channel checks an'd monthly functionals are adequate to; uncover any other. damage. -(Ref. 15.)-

1.8 Temporary Connection Between Air Storace Tank and Division 1 Diesel Generator.

At Grand Gulf. Unit 1* on September 13, 1983, the Operations Shift Superintendent was notified of a temporary connection made without proper reviews, authoriza-tions, and documentation from the Division 2 diesel generator (DG) starting

• Grand Gulf Unit 1 is a 1250 MWe-(net) BWR,'and was granted a low power

_. license in' June 1982.

It is located 25 miles south of Vicksburg,.

Mississippi, and.is~ operated by Mississippi Power and Light.

)

15.

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air system to the Division 1 DG barring device.

The Shift Superintendent noti-fied maintenance to remove the connection, and issued a Plant Quality Deficiency Report (PDQR).

At the time of the event, the plant was in cold shutdown, and the Division 1 DG was inoperable.

The temporary line was connected to a non-Q pipe downstream of the Division 2 starting air storage tank isolation valve, just before the Division 2 engine barring device.

The line was routed through a normally locked security door and attached to the Division 1 diesel engine barring device.

The connection was made to roll the Division 1 engine to inspect and dry the generator.

Also, the isolation valve was opened by non-operations personnel.

The pressure in the C and D tanks remained above 160 psig during the event, which indicated that the Division 2 DG had adequate air pressure to assure emergency starts if needed.

The cause of the event was due to personnel error.

The Mechanical Superinten-dent instructed craf t personnel to prepare the connection while simultaneously requesting the Nuclear Support Manager to verify if such a connection would be approved by the Operations Shift Superindentent.

On September 12, the Shift Superintendent denied the request.

Technical specifications required the Divi-sion 2 diesel generator to be operable.

It was discovered on September 13, that the connection had been made.

The error was due to miscommunication and noncompliance with administrative procedures.

The personnel involved were counseled and made aware of the proper procedure.

(Ref. 16.)

1.9 Main Steam Line Radiation Monitor Found with Trip Setpnint Greater than Three Times Normal Background At Vermont Yankee Unit 1* on September 28, 1983, during normal operation, main steam line radiation monitor RM-17-251A was found be have a trip setpoint exceeding the less than three times (3X) normal background at rated power required by technical specifications.

As a result, the licensee tripped the A main steam line instrument system and adjusted the setpoint.

The cause of the event was attributed to procedural inadequacy, in that the procedures did not address the requirement to periodically determine normal fuel power back-ground in order to calculate correct setpoints.

The functions'of the main steam line. radiation monitors are to provide immediate indication of excessive radiation in the lines and to initiate automatic action to contain the radiation.

Each monitor has an upscale trip.

This trip is con-nected to'the reactor protection system (RPS).

Circuits are arranged such that an upscale trip from a monitor activates one of two RPS safety channels.

This monitor also annunciates a control room high-radiation' alarm through a switch in a recorder.

This switch is set at less than 3X the normal background radia-tion.

The. trip is set at 3X normal radiation, per technical specifications.

Activating both channels (A and B) results in a control' room main steam line high-high radiation alarm and initiates-the following protective actions:

(1) All Group 1 primary containment isolation valves are closed (main steam isolation valves, steam.line drains, and reactor water sample lines).

" Vermont Yankee Unit 1 is a 504 MWe (net)-BWR located 5 miles south of Brattleboro, Vermont, and is operated by Vermont Yankee Nuclear Power.

16 t

7 (2)

The off gas to the stack pilot valves, the holdup valve, and the drain valve are closed.

(3)

The mechanical vacuum pump is tripped.

(4)

The reactor is scr6mmed.

During a review of control room instrumentation and switch positions on September 27, 1983, an NRC inspector observed that the A channel main steam line high radiation monitor (RM-17-251A) indicated a normal background rad;a-tion level of 155 mr/hr with the reactor at a power of 1589 MWth (99.8% power)

The inspector noted that a sticker on the front of the ;ndicator panel indi-cated that the high-high trip setpoint was 500 mr/hr.

Technical specifications require the trip setting to be less than 3X normal background at rated power At these conditions, the trip setting was equal to 3.22X the normal background at rated power.

The inspector immediately reviewec Instrument and Control (I&C) calibration records to determine the current trip settings.

These records indicated that the A channel trip setting was routinely verified to be at 500 mr/hr.

The last change to the setpoints was performed on November 13, 1979.

Records of normal full power background reading on the A channel between September 10 and 24, 1983 indicated a background of hetween 145 to 160 mr/hr.

The inspector was z

informed by the licensee management that the normal full power background was considered to be 200 mr/hr based on initial startup readings and, therefore, the trip settings could be as high as 600 mr/hr.

The setting at 500 mr/hr was thus conservative.

}{

The inspector also questioned the plant chemist with regard to whether the check of the trip settings had been performed as required since the last startup from I

7 the refueling outage.

The licensee representative irdicated that this check had not been performed.

The licensee's management reviewed these findings and agreed that the A main steam line high radiation trip setting was not in accordance with the technical specification requirements.

On September 28, 1983, the licensee tripped the A main steam line instrument system, and actions were initiated to adjust the "k

trip setting on the A channel down from 500 mr/hr to 425 mr/hr The licensee also adjusted the D channel from 500 mr/hr to 450 mr/hr for conservatism.

(The B and C channels were within tecnnical specification requirements during the event.) Background was established for all monitors and the trips were reset, as required, to be less than 3X background.

The inadequate procedurc is being revised to address the specific method for background determination (Refs. 17 and 18 )

1.10 Load Reduction Transient at Salem Unit 2 h

At Salem Unit 2* in January 1982 a load reduction transient occurred involving five separate and unrelated failures, including a failure of the rod control

_[

system.

The event initiated from a feedwater transient involving a loss of 4

suction to the feedwater pumps.

During the event reactor power exceeded R Salem Unit 2 is a 1106 MWe (net) PWR located 20 miles south of Wilmington,

[

Delaware, and is operated by Public Service Electric and Gas.

~

17

.FW

turbine 1,ad by up tu /0% and the reactor coolant system (RCS) average tempera-ture (T-ave) exceeded technical specification limits.

The plant, however, was stabilized without a trip, avoiding an overcooling transient.

Although the scram function was asailable when the rod control system failed and T-ave exceeoed technical specit1 cations, there was no requirement for a reactor trip.

The initiating event prior to load reduction was a high level in a heater drain tank follnwed by steam generator feed pump (5GFP) low suction pressure alarm.

Due to several previous trips attributed to instability in the heater drain system, the licensee had established guidelines for dealing with low feedwater pump suction pressure.

These guidelines called for bypassing the condensate polishing system and reducing load in 10% increments.

After the manual load reduction, and in order to reduce the RCS I-ave, the operator tried to insert the control rods in bank D, but was inhibited because of a failure of the firing circuit control card in the power cabinet.

An urgent failure alarm in the rod control system annunciated.

Due to the rod control urgent failure alarm, the rod control system placed a " hold signal" on all rods controlled by that power cabinet.

Because control bank D was first in the programmed sequence for rod insertion, the operator could not insert any control banks.

According to pro-cedure, the operator manually initiated RCS boration at 10 gpm in order to reduce RC5 T-ave.

The condenser steam dump system had been armed in the load rejection mode of operation as a result of the turbine load reduction.

When RCS T-ave exceeded the programmed I-ref by 5 F, the steam dumps began modulating to control T-ave at 5 f above T-ref.

High steam flow alarms for all steam generatars annunci-ated due to the opening of the condenser steam dump valves.

The SGFP low suction pressure alarm again annunciated.

At this time there was a mismatch of approximately /0% between turbine ioad and the reactor power.

The mismatch was being rejected to the condenser by the steam dump system.

The turbine load was increased in order to reduce the power mismatch.

The dump valves started to modulate closed, and T-ave was held stable at 580 F.

The operator believed that the transient was under control and reset the steam dump system load rejection signal, not realizing that resetting of the load rejec-tion arming signal would cause the steam dump valves to close, and thereby increase T-ave at a rapid rate.

At that time, there was a mismatch of approx-imately 46% between turbine load and reactor power.

T-ave peaked at 592 F, Causing a rapid increase i r, pressuri zer level from 54% to 78% and in pressurizer pressure from 2200 psig to a peak pressure of 2340 psig.

Both pressurizer spray valves operated to offset the pressurizer pressure increase.

The elevated T-ave was reflected back into the secondary side, causing steam line pressure to increase rapidly.

This resulted in two main steam line isolation /stap valves (MSIVs) coming off their open seats and closing parti-ally.

The operator re-openeu the two valves.

When steam pressure increased to 1080 psig, the No. 23 steam generator safety valve lifted.

An operator was sent to determine which valve was discharg ng.

The combined effects of kCS i

boration and increasing turbine load started to reduce the RCS T-ave.

Pressure decreased under the influence of pressurizor sprays with both spray valves fully open.

Manual boration was stopped.

Even though the spray demand signal was at zero, only one valve indicated closed while the other valve failed to close automatically.

The operator went to manual on the spray valve controller and the valve closed.

18

Pressurizer level dropped to 22% and pressurizer pressure dropped to 2050 psig.

l All the pressurizer heaters energized and pressure was increased to 2260 psig.

l Pressurizer pressure controls were returned to automatic.

I Approximately one hour after the transient, the unit was at stable conditions:

pressurizer pressure at 2230 psig, pressurizer level at 32%, T-ave at 558 F, and reactor power at 46%.

The steam generator safety valve had failed to fully reseat and was still relieving steam.

An attempt was made to fully reseat the safety valve by lowering RCS T-ave 4-6 F below T-ref, and then by manually cycling the steam generator atmospheric relief valve.

Steam generator pressure d: creased to 800 psig, but.the safety valve still failed to fully reseat.

It was discovered that the lifting disc associated with the manual lifting arm had rotated approximately two full turns down the valve stem and was preventing valve closure.

The manual lifting arm was removed 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the safety valve had lifted and the valve then was fully closed.

The loss of SGFP suction pressure occurred when turbine load rapidly decreased, followed by actuation of the condenser steam dump.

First, steam generator level shrank and to compensate for this level decrease feed flow momentarily increased.

This resulted in increased flow from the condensate pumps and h2ater drain pumps.

Secondly, turbine extraction steam pressure decreased.

This caused a decrease in pressure in the shell side of the fifth and sixth point heaters, which consequently reduced the pressure in the heater drain tanks.

This resulted in flashing of the water in the tanks which reduced the heater drain tank levels, and when combined with the increased feedwater flow, caused the level in the tanks to decrease to the point where the heater drain pump discharge valves began throttling closed to maintain level.

The reduction in heater drain pump flow caused a further reduction in feed pump suction pres-sure, since the condensate pumps were not capable of providing the required pressure.

Therefore, a further reduction in load was required and the cycle continued to repeat itself until the feed pumps tripped.

As a result of this event, station procedures were revised and additional training was implemented.

The licensee will replace the condensate pumps with higher heat pumps, and will trip the plant manually when the rod control system has failed and RCS T-ave has exceeded technical specification limits.

(Ref. 19.)

19

1.11 Errata / References Errata Power Reactor Events, Vol. 5, No. 5 (issued February 1984) contained a summary of events regarding " Improperly Installed Fire Dampers," pp. 9-10.

Several plants were listed as having dampers installed in noncompliance with National Fire Protection Association Standard 90A or with design criteria of the damper manufacturer.

The operating power plants involved should have included Crystal River, Farley, Grand Gulf, and McGuire.

Also listed in the writeup were Fort St. Vrain, Vermont Yankee, and Davis Besse.

Although problems were found at these plants in late 1983 regarding reanalysis of plant vulnerabilities and fire protection, the three plants were incorrectly included in the " Improperly Installed Fire Dampers" writeup.

References (1.1) 1.

Consolidated Edison Company, Docket 50-247, Licensee Event Report 83-43, December 13, 1983.

c.

2.

Duke Power Company, Docket 50-369, Licensee Event Report 83-84, October 14, 1983.

3.

NRC, Memorandum for R. W. Houston and D. R. Muller, NRR, from F. J. Miraglia, NRR, re:

Inoperable Containment Spray Systems at Indian Point Unit 2, January 1984.

(1.2) 4.

Public 3ervice Company, Docket 50-267, Licensee Event Report i

83-18, June 16, 1983.

5.

NRC, AE0D Engineering Evaluation AE0D/E401, January 4, 1984.

(1.3) 6.

NRC, Preliminary Notification PNO-V-83-43, October 3, 1983.

7.

Lotters from H. B. Ray, Southern California Edison, to J. B.

Martin, NRC/ Region V, September 30, 1983 and October 17, 1983.

8.

NRC, IE Bulletin 82-03, Revision 1, October 28, 1982.

(1.4) 9.

NRC, IE Bulletin 83-02, March 4, 1983.

10.

Letter from D. G. Eisenhut, NRC, to D. L. Farrar, Commonwealth Edison Company, July 21, 1983.

(1.5) 11.

Letter from J. G. Haynes, Southern California Edison Company, to J. B. Martin, NRC/ Region V, re: Licensee Event Report 50-206/

83-006, December 12, 1983.

(1.6) 12.

NRC, Report to Congress on Abnormal Occurrences, NUREG-0090, Vol. 6, No. 2, November 1983.

13.

Letter from W. G. Counsil, Northeast Utilities, to J. R. Miller, NRC, November 4, 1983.

20 r

=

14.

NRC Memorandura for Assistant Director for Operating Reactors, NRR/DL, from L. S. Rubenstein, NRR/05I, December 19, 1983.

(1.7) 15.

Mississippi Power and Light Company, Docket 50-416, Licensee Event Report 83-115, November 3, 1983.

(1.8) 16.

Mississippi Power and Light Company, Docket 50-416, Licensee Event Report 83-135, October 20, 1983.

~(1.9) 17.

Vermont Yankee Nuclear Power Corporation, Docket 50-271 Licensee Event Report 83-25, October 12, 1983.

i 18.

NRC, Inspection Report 50-271/83-27, October-26, 1983.

l I

(1.10) 19.

NRC, AE0D Engineering Evaluation AE0D/E323, September 1983.

l These referenced documents are available in the NRC Public Document Room at 1717 H Street, NW, Washington, D.C. 20555 for inspection and/or copying for a fee.

i 1

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21 L.. -

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2. 0 ABSTRACTS OF OTHER NRC OPERATING EXPERIENCE DOCUMENTS 2.1 Abnormal Occurrence Reports d.

G-0090) (Issued in November-December 1983 An abnormal occurrence is defined in Section 208 of the Energy Reorganization Act of 1974 as an unscheduled incident or event which the NRC determines is significant from the standpoint of public health or safety.

Under the pro-visions of Section 208, the Office for Analysis and Evaluation of Operational Data reports abnormal occurrences to the public by publishing notices in the Federal Register, and issues quarterly reports of these occurrences to Congress in the NUREG-0090 series of documents.

Also included in the quarterly reports are updates of some previously reported abnormal occurrences, and summaries of certain events that may be perceived by the public as significant but do not meet the Section 208 abnormal occurrence criteria.

Date Issued Report 11/83 REPORT TO CONGRESS ON ABNORMAL OCCURRENCES.

APRIL-JUNE 1983, NUREG-0090, VOL. 6, NO. 1 There were four abnormal occurrences uring the report period.

One occurred at a licensed nuclear plant, and three were reported by Agreement State licensees.

The occurrence at the plant involved unavailability of the auxiliary feedwater system at Turkey Point Units 3 and 4 on April 19, 1983.

The Agreement State occurrences involved overexposure of two radiographers at Bayou Testers, Morgan City, Louisiana, on June 21, 1982; a missing radioactive source from Gearhart Industries, Corpus Christi, Texas on September 14, 1982; and employee exposures to americiom-241 at Gulf Nuclear, Inc., Webster, Texas, reported February 25, 1983.

Also, the report provided update information on the following occurrences previously reported in NUREG-0090:

cracks in pipes at boiling water reactors (75-5), first reported in NUREG-75/0090, January-June 1975; nuclear accident at Three Mile Island (79-3),

first reported in Vol. 2, No.1, January-March 1979; failure of high pressure safety injection system (81-4), first reported in Vol. 4, No. 3, July-September 1981; and deficiencies in manage-ment and procedural controls (83-2), first reported in Vol. 6, No. 1, January-March.1983.-

In addition, reactor vessel internals bolting-failures at Babcock & Wilcox pressurized water reactors, and damage to the thermal shield at St. Lucie Unit 1 were discussed as items of interest that did not meet-abnormal occurrence criteria.

22

2.2 Bulletins and Information Notices Issued in November-December 1983 The Office of Inspection and Enforcement periodically issues bulletins and information notices to licensees and holders of construction permits.

During the period, one bulletin and one bulletin supplement, and 11 information notices were issued.

Bulletins are used primarily to communicate with industry on matters of generic importance or serious safety significance; i.e., if an event at one reactor raises the possibility of a serious generic problem, an NRC bulletin may be issued requesting licensees to take specific actions, and requiring them to submit a written report describing actions taken and other information NRC should have to assess the need for further actions.

A prompt response by affected licensees is required and failure to respond appropriately may result in an enforcement action, such as an order for suspension or revocation of a license.

When appropriate, prior to issuing a bulletin, the NRC may seek comments on the matter from the industry (Atomic Industrial Forum, Institute of Nuclear Power Operations, nuclear steam suppliers, vendors, etc.), a technique which has proven effective in bringing faster and better responses from licensees.

Bulletins generally require one-time' action and reporting.

They are not intended as substitutes for revised license conditions or new requirements.

Information Notices are rapid transmittals of information which may not have been completely analyzed by NRC, but which licensees should know.

They require no acknowledgement or response, but recipients are advised to consider the applicability of the information to their facility.

Date Bulletin Issued Subject 83-07 12/9/83 APPARENTLY FRAUDULENT PRODUCTS SOLD BY RAY MILLER, Supplement 2 INC.

On 7/22/83, IE Bulletin 83-07 was issued to all nuclear power facilities and fuel facilities holding an operating license or construction permit, request-ing them to submit in writing, within eight months, their determination if certain apparently fraudulent products sold by Ray Miller, Inc., were installed in safety-related systems.

(See also Power Reactor -

Events, Vol. 5, No. 4, January 1984,~ p. 25; Vol. 5, No. 5, February 1984, p. 14.)

In addition, non-licensee companies that received the products were asked to identify (1) the nuclear facilities that may have been supplied the products, or (2) the customer to whom they sold the products if they themselves were not the end-user.

Supplement 2 to Bulletin 83-07 was sent for action to all nuclear power reactor facilities.and fuel facilities holding an operating license or construction permit,.and for information to other i

23

Date Bulletin Issued Subject 83-07 fuel cycle facilities and Category B, Priority I Supplement 2 material licensees.

Attachments 1 through 3 listed (continued) additional respondents identified as end-users, secondary recipients, and NRC licensees identified as secondary recipients.

No additional actions beyond those specified in Bulletin 83-07 were requested by this supplement.

83-08 12/28/83 This bulletin was sent to all nuclear power reactor facilities holding an operating license '(0L) or construction permit (CP), for action.

The purpose of this bulletin was to assure proper operation of circuit breakers with undervoltage trip attachments being used in safety-related applications other than as reactor trip breakers.

Toward this end, the bulletin described recent findings involving such circuit breakers and asked holders of cps and OLs to take certain actions.

The subject breakers are similar to those identified in IE Bulletins 83-01,

" Failure of Reactor Trip Breakers Westinghouse DB-50) to Open on Automatic Trip Signal," and 83-04, " Fail-ure of the Undervoltage Trip Function of Reactor Trip Breakers." For abstracts, see Power Reactor Events, Vol. 5, No.1, pp. 28-29 for 83-01., Vol. 5, No. 2, p. 21 for 83-04.) Holders of cps and OLs were asked to:

(1) identify the safety-related applications of the breakers and the systems in which they are used; (2) review the adequacy of the design, testing, and maintenance of the breakers in light of their operating experience and information conveyed in the bulletin; and (3) evaluate the need to take corrective measures to ensure proper opera-tion of the breakers.

Information Date Notice Issued Subject 83-74 11/3/83 RUPTURE OF CESIUM-137 SCURCE USED IN WELL-LOGGING OPERATIONS l

All NRC licensees authorized to possess and use sealed sources containing byproduct or special nuclear material in well-logging operations were alerted to a potentially serious problem identified during removal _of a sealed source from.its holder at Shelwell Services, Inc., on September 14, 1983.

The source removal effort resulted in the rupture of a i

cesium-137 sealed source and subsequent personnel and area contamination. After several unsuccessful l

24

Information Date Notice Issued Subject 83-74 attempts to remove a cesium source capsule from its (continued) holder by inserting a lubricant into the source holder and tapping it, employees placed the sou ce holder on a turning lathe and attempted to push the source out of its holder using a drill bit.

With the source holder concentrically spinning around the bit's axis, the source capsule was ruptured.

When the holder was removed from the lathe the source fell into a rag.

Because of inadequate surveys, the licensee failed to evaluate the situation and take immediate cor-rective actions to limit personnel exposure and the spread of contamination.

The licensee disregarded off-scale readings of two different radiation survey instruments, assuming that both were malfunctioning.

This notice suggested that recipients review their procedures for well-logging source changes to ensure that capsules cannot be ruptured or source contain-ment breached.

Written procedures should be estab-lished for installation and removal.

It was also suggested that recipients review their procedures and training programs to ensure that appropriate and operable radiation monitoring equipment is available and used, and review insurance coverage to determine if it is adequate to pay for decontamination in the event of an incident.

83-75 11/3/83 IMPROPER CONTROL R00 MANIPULATION All nuclear power plants holding an opeisting license or construction permit were informed of an event that occurred at Quad Cities Unit 1 in March 1983 and Hatch Unit 2 in July 1983, involving improper control rod manipulations because of inadequate communications from and controls by plant management.

(See also Power Reactor Events, Vol. 5, No. 4, January 1984, pp. 1-5.)

These events did not result in fuel damage, but affected the plants' ability to sustain a rod drop accident.

It was expected that recipients of the notice review the information for applicability to their facilities.

83-76 11/2/83

-REACTOR TRIP BREAKER MALFUNCTIONS (UNDERV0LTAGE TRIP DEVICES ON GE TYPE AK-2-25 BREAKERS)

All nuclear power reactor facilities holding an operating license or construction permit were advised of malfunctions of the undervoltage (UV) 25 t

-~

Information Date Notice Issred Subject 83-76 trip attachments in General Electric AK-2-25 (continued) breakers, wnich are safety related systems.

Mal-functions of the UV trip attachments at San Onofre were described.

These involved the UV armature being in midposition rather than in contact with the air gap adjusting screws.

It was suggested that recipients of the notice visually inspect each UV armature to assure its proper position after each operation.

If the UV armature were to be found in an improper position, the NRC would consider the reactor trip breaker to be inoperable.

83-77 11/14/83 AIR / GAS ENTRAINMENT EVENTS RESULTING IN SYSTEM FAILURES All holders of a nuclear power reactor operating license or construction permit were informed of events at Calvert Cliffs Unit 1, McGuire Unit 1, San Onofre Unit 2, and St. Lucie Unit 1 that rendered redundant safety systems inoperable because air or gas entrainment caused pump cavitation.

Licensees were cautioned that the types of system inoperability resulting from such entrainment vary, and that redundant safety-related trains or components can be affected as shown by the events discussed.

The serious consequences that may result from such system or component impairment cannot be overemphasized.

It was expected that recipients of this notice review the information for applicability to their facilities.

83-78 11/17/83 APPARENT IMPROPER MODIFICATION OF A COMPONENT AFFECTING PLANT SAFETY All nuclear power reactor facilities holding an operating license or construction permit were informed of an event involving apparent improper modification of a compcnent affecting plant safety.

The modification was to a power operated relief valve (PORV) at Rancho Seco, and consisted of adding an indicator, visible to control room personnel, to the valve's operating lever.

The additional weight of the indicator apparently inhibited its ability to reseat properly.

This event pointed out two facets of component modifications which are dictated by good practice, yet can easily be overlooked in the rush to bring a plant back on line:

(1) consul-tation with the component manufacturer before making the modification, and (2) testing of the component after the modification has been made.

It was noted that the area of concern in this notice was not 26 A

l Information Date l

Notice Issued Subject l

83-78 limited to PORVs, but was related to the modifica-(continued)'

tion of any component that affects plant safety.

83-79 11/23/83 APPARENTLY IMPROPER USE OF COMMERCIAL GRADE COMPONENTS IN SAFETY-RELATED SYSTEMS All nuclear power reactor facilities holding an operating license or construction permit were informed of the apparently improper use of com-mercial grade components in safety-related systems.

The event discussed involved a leaking heat exchanger outlet valve at Cook Unit 2.

The valve manufacturer determined that the elastomer seat had not been properly bonded to the valve body at the time of manufacture; i.e., it was manufactured as a commercial grade valve since neither the purchase order nor the specification for the valve required fabrication under an approved nuclear quality assurance progran..

It was noted that com-mercial grade components should not be used in safety-related systems unless they are evaluated by engineering and quality assurance personnel.

83-80 11/23/83 USE OF SPECIALIZED " STIFF" PIPE CLAMPS All nuclear power reactor facilities holding an operating license or construction permit, nuclear steam system suppliers, and architect engineers were notified of a potentially significant problem in the use of specialized " stiff" pipe clamps, which may result in significant localized stresses in Class 1 piping.

The notice describes certain design con-cepts that have been incorporated by clamp vendors in responce to recent. specification requirements that clamps be designed to provide total system stiffness-compatible with the shock suppressor stiffness.

However, these innovations can result in localized piping stresses significantly higher than the stresses from conventional pipe clamps.- 'The NRC staff does not believe-the new clamp design to be deficient, butidoes believe that potential safety.

concerns could exist if the piping designers are not aware of the conditions under which high stress can be induced by the clamp.

The applicant / licensee should be aware that post-installation control of the~ clamp preload may be necessary when the clamp stiffness is required to assure total piping system i

restraint.

27 L

'a

Information Date Notice Issued Subject 83-81 12/7/83 ENTRY INTO HIGH RADIATION AREAS FR0?1 AREAS WHICH ARE NOT UNDER DIRECT SURVEILLANCE All licensees authorized to use portable radiography device: in radiography programs were notified of a potentially significant problem pertaining to entry into high radiation areas from outside the area under direct surveillance.

The notice discussed an event that occurred during radiographic examination of welds on a pipeline in Alaska.

Unknown and undetected by the radiography crew was a welder who had entered the pipe on a crawler, about 300 ft from the radiographic operation, to perform repairs from within the pipeline.

It was suggested that radio-graphy crews be aware that high radiation areas are not always within vision.

While access to these areas may normally be considered unlikely, it remains the licensee's responsibility to control access when radiographic operations are in progress.

83-82 12/20/83 FAILURE OF SAFETY / RELIEF VALVES TO OPEN AT BWR -

FINAL REPORT All nuclear power mactor facilities holding an operating license or construction permit were pro-vided this final supplement and update to Informa-tion Notices 82-41 (Power Reactor Events, Vol. 4, No. 5, April 1983, p. 41) and 83-39 (Vol. 5, No. 3, December 1983, pp. 23-24).

An update is provided on meetings, testing results, conclusions and courses for future action involving the Target Rock two-stage safety / relief valves.

83-83 12/19/83 USE OF PORTABLE RADIO TRANSMITTERS INSIDE NUCLEAR POWER PLANTS All nuclear power reactor facilities holding an operating license or construction permit were apprised of instances at various places in which portable radio transmitters caused system malfunc-tions and spurious actuations. This radio frequency interference (RFI) is caused by solid state devices.

As newer plants are built that use more solid state equipment, and as older plants retrofit solid state equipmer*., more cases of RFI by portable radio trans-mitters are likely to result.

If plant operations make the use of portable transmitters near RFI-sensitive equipment either necessary or likely in an emergency, then administrative prohibitions are not adequate and the licensee should consider hard-ware fixes.

Typical fixes include filters, shielded cables, and modification of affected equipment.

28

^

1 Information Date Notice Issued Subject 83-84 12/30/83 CRACKED AND BROKEN PISTON RODS IN BROWN B0 VERI ELECTRIC TYPE SHK BREAKERS All holders of a nuclear power reactor operating license or construction permit were notified of a potentially significant problem pertaining to Brown Boveri. Electric (BBE) type 5HK 250/350, 1200/2000 ampere circuit breakers.

The problec involves defects or failure of the puffer piston connecting rods, which are needed for low current interruptions to assist magnetic forces to move the arc into the interrupting chamber of the breaker, and to provide a pneumatic cushion which reduces the shock forces imposed on the mechanism and current-carrying parts upon opening.

The manufacturer indicated that, although no breaker failed because of a broken puffer piston rod, the breaker's capability to interrupt at low current may be impaired.

BBE recommends inspecting for cracked or broken rods at normal maintenance intervals and replacing the piston assembly if this condition is found.

An attachment to the notice contained a list provided by BBE of SHK circuit breakers that they have sup-plied for use in Class IE applications at nuclear power plants, and which may be affected.

29

2.3 Case Studies and Engineering Evaluations Issued in November - December 1983 The Office for Analysis and Evaluation of Operational Data (AEDD) has as a pri-mary responsibility the task of reviewing the operational experience reported by NRC nuclear power plant licensees.

As part of fulfilling this task, it selects events of apparent interest to safety for further review as either an engineer-ing evaluation or a case study.

An engineering evaluation is usually an imme-diate, general consideration to assess whether or not a more detailed protracted case study is needed.

The results are generally short reports, and the effort involved usually is a few staffweeks of investigative time.

Case studies are in-depth investigations of apparently significant events or situations.

They involve several staffmonths of engineering effort, and result in a formal report identifying the specific safety problems (actual or potential) illustrated by the event and recommending actions to improve safety and prevent recurrence of the event.

Before issuance, this report is sent for peer review and comment to at least the applicable utility and appropriate NRC offices.

d Thate AE00 reports are made available for information purposes and do not impose any requirements on licensees.

The findings and recommendations contained in these reports are provided in support of other ongoing NRC activities concerning the operational event (s) discussed, and do not represent the position or requirements of the respon-sible NRC program office.

Special Date Study

• Issued Subject P301 7/83 REPORT ON THE IMPLICATIONS OF THE ATWS EVENTS AT THE SALEM NUCLEAR POWER PLANT ON THE NRC PROGRAM FOR COL-LECTION AND ANALYSIS OF OPERATIONAL EXFERIENCE On February 25, 198?, Salem Unit 1, a Westinghouse de-signed nuclear power plant, experienced a total failure of the reactor trip system (RTS) to automatically shut down the reactor upon receipt of a valid signal from the reactor protection system (RPS).

A similar event had occurred at Salem Unit 1 on February 22, 1983.

The fail-ures were caused by two electro mechanical circuit breakers (reactor trip breakers (RTBs)), which failed to open in response to the automatic trip signal from the RPS because the associated undervoltage (UV) trip attachment did not actuate the trip mechanisms.

The breakers subsequently opened when the operators actuated

• No case studies were issued during the period.

However, special study P301 issued by AE00 in July 1983, and inadvertently omitted as an abstract in the issue of Power Reactor Events that covered the July-August 1983 period, is being included 'in this issue.

30

Special Date Study

• Issued Subject P301 (Continued) them via the manual scram switch.

The proper function-ing of the automatic feature of the RTS including the RTBs is of prime importance to the protection of public health and safety; its failure results in total reliance on operator actions to control plant transients.

On March 1983, AE00 initiated a special study to review and evaluate the implications of these anticipated tran-sient without scram (ATWS) events at Salem on the NRC's program for collecting and analyzing operational exper-ience.

The study focused on the adequacy of NRC's report-ing requirements as they relate to RTB' failures, includ-ing the licensees' understanding of the requirements and the impact of proposed revisions to the requirements; and whether trends and patterns analyses of the reported RTB failures could have identified a significant potential for the problem at Salem Unit 1 be,* ore it occurred.

Addi-tional topics _ reviewed were the requirements for licensees to analyze operating experience with a specific focus on the ability to reconstruct the sequence of events.

Some of the conclusions drawn from the study are de-scribed below.

The Salem ATWS events emphasize that' operational data assessment requires clear and in-depth licensee reports on failure history.

Operational event analysis and feedback by each licensee, the industry, and the NRC is essential for the safe operation of' nuclear power plants.

~

Such aspects as what information is to be recorded following the course of a serious event; scanning and recording rates; quantity of data recorded and retention period, and the requirements for equip-ment availability, reliability, and qualification; need'to be specifically addressed.

Planned trends _and patterns' analyses, coupled with close scrutiny of failure-data and detailed engi-neering assessment particularly of those_ features related to reliability, should~ aid in the identi-fication of specific plant'and/or generic safety problems and the need for corrective actions.

Even though the' events at Salem involved no-plant damage, no releases, and no immediate threat to public health and safety,.the fact-that the NRC o

31 m

Special Date Study

• Issued Subject P301 (Continued) and the industry have devoted extensive resources to studying its cause and implications is a strong indication of the heightened sensitivity to opera-tional events and the progress made in understand-ing the lessons of operational experience.

j Engineering Date j

Evaluation Issued Subject E325 11/21/83 VAPOR BINDING OF AUXILIARY FEEDWATER PUMPS H. B. Robinson, Unit 2 has experienced four failures of auxiliary feedwater (AFW) pumps due to low discharge pressure trips caused by steam formation in the AFW piping and pump casings (vapor binding).

The steam was formed when hot water from the feedwater system leaked through two check valves and a motor operated valve in the piping to either motor-or steam-driven AFW pumps.

The safety implication of the events at Robinson is that the leakage of main feedwater to the AFW system consti-tutes a common cause failure that can render both trains of the AFW system inoperable, although only single trains have been adversely affected to date.

Similar events have also occurred at D. C. Cook, Unit 2.

The potential for the loss of AFW system due to back-leakage appears generic because the designs of the systems at Robinson and Cook are typical of other PWRs; i.e., isolation between the steam conversion system and the AFW system is accomplished by check valves and motor-operated valves.

AE00 has initiated a case study to better define the generic implications and establish the bases for revising the technical specifications to ensure that the AFW temperature is monitored and/or that the inservice inspection programs test the isolation capability of the check valves.

E326 11/28/83 STEAM VOIDING IN OCONEE UNIT 3 ON JUNE 13, 1975 - A PRECURSOR EVENT TO THE TMI-2 ACCIDENT On June 13, 1975 Oconee, Unit 3 experienced a reactor trip and an overcooling transient.

Post-trip analyses focused on the effect that the excessive cooldown rate had upon the fuel, the violation of the plant's techni-cal-specifications and the violation of the reactor cool-ant pump net positive suction head requirements.

Although the licensee noted anomalous plar.t behavior during the transient (rising pressurizer level which led operators to secure high pressure injection and to reopen the block valve 15 seconds after closing it, the~ reason for the 32

Engineering Date l

Evaluation Issued Subject

[

l

-E326 (contin ~ued) rising pressurizer level did not appear to have been investigated by either the licensee, the nuclear steam system supplier (Babcock & Wilcox-B&W), or the NRC.

It appears that primary system voiding contributed to the increase in pressurizer level, but none of the post-trip analyses recognized it at the time.

Had an extensive review of this event been madeiand the operators at other B&W plants been made aware of the de-tails of this event, including primary system voiding and pressurizer level increases accompanying a stuck open power-operated relief valve, it is possible that subse-quent depressurization events at B&W plants (TMI-2 acci-dent in particular) might have taken different courses.

This engineering evaluation stressed the need for rigor-ous post mortem analysis of anomalous events and for effective dissemination of operating data throughout the nuclear community.

E327 11/28/83 GASEOUS RELEASES FROM WASTE GAS DISPOSAL SYSTEM 3..

This engineering evaluation was performed to evaluate the potential for releases of gases from the waste gas disposal system of PWRs.

A search of licensee event reports was performed.to evaluate the causes for such events and to determine if the events had any generic or safety implications.

As a result of a review of this operating experience; it was found that the greatest potential'for significant releases results from the 4

possibility of hydrogen explosion in the waste gas de-cay tank.

In at least'one instance, an internal-igni-tion of a hydrogen-air mixture in tre tank occurred.

The waste gas disposal system at most plants is not designed to sustain a hydrogen explosion.

The evalua-tion suggested that proposed technical specification requirements should be placed on operating plants to limit the concentration of hydrogen or' oxygen'in the waste gas holdup system.to less than or equal to 4% by-volume.

33

2.4 Generic Letters Issued in November-December 1983

' Generic-letters are issued by the Office of Nuclear Reactor Regulation, Division

{.

of Licensing.

They are similar to IE Bulletins (see Section 2.2) in that they transmit information to, and obtain information from, reactor licensees, appli-

. cants, and/or equipment suppliers regarding matters of safety, safeguards, or environmental significance.

During September and October 1983, three letters were issued.*

l

' Generic letters usually either (1)' provide information thought to be important in assuring continued safe operation of facilities, or (2) request informa-i tion on a specific schedule that would enable regulatory decisions to be made regarding tne continued safe operation of facilities.

They have been a signifi-cant means of communicating with licensees on a number of important issues, the resolutions of which have contributed to improved quality of design and operation.

f.

' Generic' Date Letter Issued Subject 83-32 12/2/83 NRC STAFF RECOMMENDATTONS REGARDING OPERATOR As' IONS FOR REACTOR TRIP AND ATWS All power reactor licensees and applicants for operating L

licenses were provided an enclosed " Staff Position on j

Operator Actions for Reactor Trio and ATWS." Operator action to immediately back up all automatic trips with a manual trip based solely on receipt of " positive indicatiG of.an " automatic trip demand" without evaluating the j-automatic trip system's success is believed by the NRC.

staff to be conservative and, therefore, the preferred' method.

(This operator action is not currently required by the NRC.) Facility procedures should identify the instruments that provide the " positive indication" of an

{

" automatic trip demand."

l 83-35 11/2/83-CLARIFICATION OF TMI ACTION PLAN ITEM II.K.3.31 All licensees of operating reactors, applicants for

- operating licenses, and holders of construction permits were provided clarification of NUREG-0737, Item II.K.3.31f which requires all licensees to. submit plant-specific small-break loss-of-coolant accident (SBLOCA) analyses using evaluation models revised per II.K.3.30, which requires that each licensee revise its current emergency core cooling system (ECCS) S8LOCA models.

Unless a revisc i

L

• Generic' Letter 83-34 has'not ye't been issued; Generic Letters 83-33 and 83-38 were abstracted in Power Reactor Events Vol. 5, No. 5, covering documents issued during September-October 1983.

L

34 4

e

-,-.-e..,.

Generic Date Letter Issued Subject 83-35 model shows a previously approved model to be noncon-(continued) servative, however, the previously approved models would l

remain in compliance with Appendix K to 10 CFR 50, as would the ECCS analyses performed with the previous model.

The requirements of II.K.3.31 can be satisfied by each licensee submitting a plant-specific analysis that demonstrates that current SBLOCA analyses using pre-viously approved evaluation models are more limiting i

than analyses using the previously revised (II.K.3.30) models.

83-36 11/1/83 NUREG-0737 TECHNICAL SPECIFICATIONS All boiling water reactor licensees were provided guid-ance in meeting the requirements of NUREG-0737, "Clari-fication of TNI' Action Plan Requirements," which identi-fies items for which technical specifications are required.

The guidance provided in Generic Letter 83-02 covered NUREG-0737 items scheduled for implementation by 12/31/81.

(See also Power Reactor Events, Vol. 5, No. 1,

p. 34.) A number of NUREG-0737 items which require i

technical specification, were scheduled for implementa-tion afte'r 12/31/81.

Each of those items was presented in either Enclosure 1 or Enclosure 2 of this letter.

• contained samples in standard technical specification formats with blanks or parentheses appearing where the information is plant specific.

Licensees were requested to review their facility's technical specifications-to determine consistency with the guidance provided in Enclosure 1.

It was recom-mended that licensees respond within 90 days of receipt of this latter.

83-37

.11/1/83 NUREG-0737 TECHNICAL SPECIFICATIONS All pressurized water reactor licensees were provided guidance on the same subject discussed in Generic Letter 83-36 above, and were referred to Generic Letter 82-16 for guidance on NUREG-0737 items scheduled for imple-mentation by 12/31/81.

Licensees were requested to review their facility's technical specifications to determine consistency with the guidance ~provided in Enclosure 1.

It was recom-mended that licensees submit technical specifications

.for reactor coolant systems within 30 days of receipt

.of this' letter, and within 90 days for the remaining items discussed in Enclosure 1.

35

Generic Date Letter Issued Subject 83-39 12/8/83 VOLUNTARY SURVEY OF LICENSED GPERATORS Representatives of various utilities on an attached list were informed that the NRC has contracted with Battelle Pacific Northwest Laboratories to undertake a mailed survey of selected licensed operations personnel at commercial operating nuclear power plants.

The purpose of this voluntary survey is to provide information that will be useful in understanding current work and staff-ing practices in nuclear power plant operations.

Survey results will be presented in aggregate form to prevent the identification of individual respondents and specific utilities or plants.

83-40 12/21/83 OPERATOR LICENSING EXAMINATION All power reactor licensees and applicants for an operating license were referred to Generic Letter 83-01 (Power Reactor Events), Vol. 5, No. 1, p. 34), which requested information to form the basis for scheduling manpower and resources to licensed operators and senior operators through 1985.

Recipients were requested in Generic Letter 83-40 to provide updated information and information through 1987; i.e., a best estimate of the need for operator licensing examinations for the remain-der of FY 1984 as well as for FYs 1985 through 1987.

Responses were requested by 1/16/84 to Mr. Don Beckham, AR-5221, Washington, DC 20555, or at (301) 492-4868.

f 83-41 12/16/83 FAST COLD STARTS OF DIESEL GENERATORS Widespread concern has been expressed by the nuclear industry that fast cold start surveillance testing of diesel generators may result in premature diesel engine degradation In order to determine whether the number of fast cold starts should be reduced, the NRC requested that all licensees of operating reactors voluntarily participat-in providing'information about the extent and effects of this practice. Responses to questions contained in this letter were requested by 1/6/84. The results of this and other efforts will be factored into the NRC's diesel generator reliability program.

83-42 12/19/83 CLARIFICATION TO GENERIC LETTER 81-07 REGARDING RESPONSE TO NUREG-0612, " CONTROL OF HEAVY LOADS AT NUCLEAR POWER PLANTS" On 12/22/80, the NRC issued Generic Letter 81-07, which.

requested that licensees implement certain interim actions and provide information to the NRC related to heavy loads at their facilities, in regard to NUREG-0612.

36

L Generic Date i

Letter Issued Subject 83-42 As indicated in NUREG-0612, one means for complying with (continued) the criteria of Section 5.1 is to demonstrate that no single failure in the heavy loads handling equipment will result in dropping of a load, as discussed in Section 5.1.6.

One acceptable means of complying with the guidance of Section 5.1 vas to meet the guidelines of NUREG-0554, " Single Fa. lure Proof Cranes." However, in the course of reviewing rane designs against NUREG-0554, the NRC has identified concerns of a generic nature which indicate that NUREG-0554, until revised, may be deficient in assuring single failure proof cranes.

The concerns relate specifically to assuring that a single failure in the electric power / control system will not cause a load drop.

The purpose of this letter was to provide information concerning this potential problem related to single failure proof cranes to all holders of operating licenses, applicants for operating licenses, and holders of construction permits for power reactors.

83-43 12/19/83 REPORTING REQUIREMENTS OF 10 CFR PART 50, SECTIONS 50.72 AND 50.73, AND STANDARD TECHNICAL SPECIFICATIONS All licensees and applicants for operating power reactors, and holders of construction permits for power reactors were informed that Section 50.72 of Title 10 of the Code of Federal Regulations has been revised and became effective 1/1/84.

A new Section 50.73 has been added and also became effective 1/1/84.

Section 50.72 revises the immediate notification requirements for operating nuclear power reactors.

The new Section 50.73 provides for a revised Licensee Event Report System.

Cppies of each of these sections to 10 CFR Part 50 were enclosed in this letter.

Since paragraph (g) of Section 50.73 specifically states that:

"the requirements contained in this section replace all existing requirements for licensees to report ' Reportable Occurrences', as defined in individual plant Technical Specifications," the reporting requirements incorporated into the " Administrative Controls" section of a facility's technical specifications may require modification.

Also, the definition " Reportable Occur-rence" may need to be replaced by a new term, " Report-able Event." The NRC will make these changes in the current version of Standard Technical Specifications (STS) for.all nuclear power reactor vendors and in the technical specifications for plants not yet licensed..Because this change to the technical l

37

Generic Date Letter Issued Subject 83-43 specifications is clarifying and made at the request of (continued) the Commission, recipients of this letter were not required to remit a license fee for the change.

83-44 12/20/83 AVAILABILITY OF NUREG-1021, "0PERATOR LICENSING EXAMINiR STANDARDS" This letter provided an explanation to all power reactor licensees and applicants for operating licenses of NUREG-1021, which had been forwarded separately to the recipients.

The standards in NUREG-1021 provide direc-tion to NRC examiners and establish procedures and practices for examining and licensing applicants for NRC operator licenses pursuant to Part 50 of Title 10.

Comments on the standards are welcomed, and will be considered in the next revision.

Comments should be directed to Mr. Don Beckham, AR-5221, Washington, DC 20555, or at (301) 492-4868 f

r 38

t-i i

l 2.5 Operating Reactor Event Memoranda Issued in November-December 1983 r

l The Director, Division of Licensing, Office of Nuclear Reactor Regulation l

'(NRR), disseminates information to the directors of the other divisions and program offices within NRR via the operating reactor event memorandum (OREM) i system.

The OREM documents a statement of the problem, background informa-tion,. the safety significance, and short and long term actions (taken and planned).

Copies of OREMs are also sent to the Offices for Analysis and Evaluation of Operational Data, and of Inspection and Enforcement for their information, ho OREMs were issued during November-December 1983.

h 39

2.6 Regulatory and Technical Reports (NUREG-0304) Issued in November-December 1983 The abstracts listed below have been selected fiom the Office of Adminis-tration's quarterly publication, Regulatory and Technical Reports (NUREG-0304).

This document compiles abstracts of the formal regulatory and technical reports issued by the NRC staff and its contractors.

Bibliographic data for the reports are also included.

Copies and subscriptions of NUREG-0304 are avail-able from the NRC/GP0 Sales Program, PHIL-016, Washington, DC 20555 or on (301) 492-9530.

Report Title NUREG-0020 LICENSED OPERATING REACTORS STATUS

SUMMARY

REPORT (No. 8 -

Vol. 7, No. 8 Data as of 7/31/83; No. 9 - Data as of 8/31/83; No.10 -

November 1983; Data as of 9/30/83)

Vol. 7, No. 9 November 1983; This report provides data on the operation of nuclear units Vol. 7, No. 10 as timely and accurately as possible.

The information is December 1983 collected by the office of Resource Management from the Headquarters staff of NRC's Office of Inspection and Enforcement, from NRC's Regional Offices, and from utilities.

The three sections of the report are:

monthly highlights and statistics for commercial operating units, and errata from previously reported data; a compilation of detailed information on each unit, provided by NRC's Regional Offices, IE Headquarters and the utilities; and an appendix for miscellaneous information such as spent fuel storage capability, reactor years of experience and non power reactors in the U.S.

It is hoped the report is helpful to all agencies and individuals interested in maintaining an awareness of the U.S. energy situation as a whole.

NUREG-0304 REGULATORY AND TECHNICAL REPORTS Vol. 8, No. 3 November 1983 This compilation lists all NRC regulatory and technical reports published under the NUREG series during the third quarter of 1983.

NUREG-0485 SYSTEMATIC EVALUATION PROGRAM STATUS

SUMMARY

REPORT (Data Vol. 5, No. 10 as of 10/31/83)

December 1983 The Systematic Evaluation Program is intended to examine many safety-related aspects of 11 of the older ' light water reactors.

This document provides the existing status of the review process including individual topic and overall completion status.

NUREG-0540 TITLE LIST OF DOCUMENTS MADE PUBLICLY AVAILABLE (No. 9 -

Vol. 5, No. 9 Data as of 9/30/83; No. 10 - Data as of 10/31/83)

December 1983 Vol. 5, No. 10 This document is a monthly publication containing descrip-December 1983 tions of information received and generated by the NRC.

This information includes (1) docketed material associated with civilian nuclear power plants and other uses of 40 i

Report Title radioactive materials, and (2) nondocketed material received and generated by NRC pertinent to its role as a regulatory agency.

The following indexes are included:

Personal Author Index, Corporate Source Index, Report Number Index, and Cross Reference to Principal Documents Index.

NUREG-0606 UNRESOLVED SAFETY ISSUES SUMARY Vol. 5, No. 4 (Data as of 11/18/83)

November 1983 This report provides an overview of the status of the progress and plans for resolution of the generic tasks addressing Unresolved Safety Issues, as reported to Congress.

NUREG-0713 OCCUPATIONAL RADIATION EXPOSURE AT COMMERCIAL NUCLEAR Vol. 4 POWER REACTORS (Annual Report for 1982)

December 1983 This report summarizes the occupational radiation exposure information that has been reported to the NRC by commercial nuclear power reactors during tbe years 1969 through 1982.

The bulk of the data presented in the report was obtained from annual radiation exposure reports submitted in accordance with the requirements of 10 CFR 20.407 and license technical specifications.

Data on workers termi-nating their employment at nuclear power facilities was obtained from reports submitted pursuant to 10 CFR 20.408.

The annual reports submitted by the 75 nuclear power plants that had completed at least one full year of opera-tion as of 12/31/82 indicated that the number of personnel monitored during 1982 was 129,275 persons and the annual collective dose incurred by these individuals was 52,190 man rems. The average annual dose for each worker that received a measurable dose was 0.6 rems, and the average collective dose per reactor was 705 man-rems. The termination reports revealed that some 65,700 individuals completed their employment with one or more reactor facili-ties during 1981 (the most recent year for which all of the termination data are available for analysis).

Approximately 5,300 cf these workers could be considered transients and they received an average dose of about one rem.

NUREG-0871 SUMARY INFORMATION REPORT (data as of 9/30/83)

Vol. 2, No. 4 December 1983 This report provides summary data concerning NRC and its licensees for general use by the Chairman, other Commissioners and Commission staff offices, the Executive Director for Operations, and the Office Directors.

NUREG-0933 A PRIORITIZATION OF GENERIC SAFETY ISSUES December 1983 The report presents the priority rankings for generic safety issues related to nuclear power plants.

The 41

Report Title purpose of these rankings is to assist in the timely and efficient allocation of NRC resources for the resolution of those safety issues that have a significant potential for reducing risk.

The safety priority rankings are HIGH, MEDIUM, LOW and DROP and have been assigned on the basis of risk significance estimates, the ratio of risk to costs and other impacts implemented, and the consideration of uncertainties and other quantitative or qualitative factors.

To the extent practical, estimates are quantitative.

NUREG-0936 NRC REGULATORY AGENDA (Data for 6/83 - 9/83)

Vol. 2, No. 3 November 1983 The NRC Regulatory Agenda is a compilation of all rules on which the NRC has proposed or is considering action and all petitions for rulemaking which have been received by the Commission and are pending disposition by the Commission.

The Regulatory Agenda is updated and issued each quarter.

The Agendas for April and October are published in their entirety in the Federal Register while a notice of avail-ability is published in the Federal Register for the January and July Agendas.

CREG-0940 ENFORCEMENT ACTIONS:

SIGNIFICANT ACTIONS RESOLVED (Data for Vr1. 2, No. 3 7/83 - 9/83)

November 1983 This compilation summarizes significant enforcement actions that have been resolved during one quarterly period and includes copies of letters, notices and orders sent by the NRC to the licensee with respect to the enforcement action and the licensee's response.

It is anticipated that the information in this publication will be widely disseminated to managers and employees engaged in activities licensed by the NRC, in the interest of promoting public health and safety as well as common defense and security.

NUREG-0957 THE PRICE-ANDERSON ACT - THE THIRD DECADE December 1983 S'ibsection 170p. of the Atomic Energy Act of 1954, as amended, requires that the Commission submit to the Congress by 8/1/83 a detailed re, ort on the need for continuation or modification of M ction 170 of the Act, the Price-Anderson provisions.

The report is divided into four sections with detailed subject reports appended to the main report.

Sections I through III include an exami-nation of issues that the Commission was required by statute to study (i.e., condition of the nuclear industry, state of knowledge of nuclear safety, and availability of private insurance), and discussion of other issues of interest and importance to the Congress ard to the public.

The subjects covered are as follows:

(1) overview of the Price-Anderson system; (2) the state of knowledge of 42

I V

l Report Title nuclear safety; (3) availability of private insurance; (4) condition of the nuclear industry; (5) causality and proof of damages; (6) limitation of liability and subsidy; and (7) a proposal that would provide for removal of the limitation of liability but with limited annual liability payments.

Section IV of the report contains conclusions

[

and recommendations.

Section V contains a bibliography.

NUREG-0981 NRC/ FEMA OPERATIONAL RESPONSE PROCEDURES FOR RESPONSE TO 4

November 1983 A COMMERCIAL NUCLEAR REACTOR ACCIDENT i

Procedures have'been developed by the NRC and the Federal Emergency Management Agency (FEMA) which provide the response teams of both agencies with the steps to be taken in responding to an emergency at a commercial nuclear power plant.

The emphasis of these procedures is mainly on the interface between NRC and FEMA at their respective Headquarters and Regional Offices and at the various sites at which such an emergency could occur.

Detailed proce-l dures are nresented that cover, for both agencies, notifica-j' tion schemes and manner of activation, organizations at Headquarters and the site, interface procedures, coordi-nation of onsite and offsite operations, the role of the Senior FEMA' Official, and the cooperative efforts of each agency's public information staff.

1 NUREG-0995 SAFETY EVALUATION REPORT RELATED TO PLANT RESTART OF SALEM December.1983 NUCLEAR GENERATING STATION, UNITS 1 and 2 On February.22 and 25, 1983, the Salem Unit 1 reactor.

p control rods failed to insert upon receipt of an automatic trip signal from the reactor protection system.

Upon r

receipt of a manually initiated signal, however, the rods did insert and shut down the plant.' These events were of major' safety' concern because:the-automatic reactor trip capability was not available; therefore, the' plant safety 1

was jeopardized when plant operating conditions required a fast shutdown to protect the integrity of.the reactor I

core. ' Safe control of certain ' anticipated operating transients' depends on the reliable and fast operation of a.

e reactor trip, either. automatically or manually.'

Evaluation of these events'and the circumstances leading'

-up.to them revealed a number.of issues that require 1-resolution'by the licensee and/or-the NRC.

This safetyi evaluation' report briefly describes the NRC and licensee actions to' address and resolve equipment; operator i

procedures, training and response, and management issues.

identified by the NRC evaluation'of the two events at I

Salem Unit 1.

Actions for Salem as identified ~in this

~

J report fall in two groups:

(1) actions that weretrequired 43

~

-Report Title to be satisfactorily resolved before plant startup; and

~

(2) actions that could be completed after restart but which were required to complement the pre-start'sp items imple-mented on Unit 2 prior to its restart.

NUREG-1024 TECHNICAL SPECIFICATIONS - ENHANCING THE SAFETY IMPACT November 1983 This report documents the work of an interoffice, inter-disciplinary, NRC Task Group established in 8/83.

The i

Task Group was established to identify the scope and nature of problems with surveillance testing in current technical specifications and to devflop alternative approaches that will provide better assurance that surveil-lance testing does not adversely impact safety.

The Task Group concluded that some of the technical specifications have the potential for adversely affecting safety and some do not appear to be cost effective.

The Task Group developed five recommendations for improvement.

NUREG/CR-2000 LICENSEE EVENT REPORT (LER) COMPILATION (No. 10 -

Vol. 2, No. 10 Data for 10/83; No. 11 - Data for 11/83)

November 1983; Vol. 2, No. 11 This monthly report contains Licensee Event Report (LER)

December 1983 operational information that was processed into the LER data file of the Nuclear Safety Information Center during the one month period identified on the cover of this document.

The LERs, from which the information is derived, are submitted to the NRC by nuclear power plant licensees in accordance with Federal regulations.

Proce-dures for LER reporting are described in detail in NRC Regulatory Guide 1.16 and NUREG-1022, Licensee Event Report System.

The LER summaries in this report are arranged alphabetically by facility name and then chronological 1y'by event date for each facility.

Component, system keywords, and component vendor indexes follow the-summaries.

The components systems, and vendors are those identified by the utility when the LER form is initiated; the keywords are assigned by the computer using correlation tables from the Sequence Coding and Search System.

44

Report Title NuREG/CR-2987 IDENTIFICATION AND ANALYSIS OF HUMAN ERRORS UNDERLYING December 1983 ELECTRICAL / ELECTRONIC COMPONENT RELATED EVENTS REPORTED BY NUCLEAR POWER PLANT LICENSEES l-This report provides a useful and adaptable data base of over 700 human error events associated with the operation, testing, maintenance of instrumentation, control and in plant electrical power components in licensed nuclear power plants.

More than 8000 Licensee Event Report (LER) abstracts were retrieved from the Department of Energy (DOE)/ RECON Data Base, Nuclear Safety Information Center File for certain specific safety-related systems.

The data developed in this report were obtained by the application of a practical and workable human error identification methodology.

The resulting human error data base is several times larger.than would have been available based solely on licensee identification of human error.

This data base is intended to provide a realistic assess-ment of the real human error populations obtainable from the LERs.

As a result, this data will provide a synthesis with the NUREG/CR-3416 methodology (for a systematic-

i. valuation of the number of opportunities for these types of errors), thus permitting the generation of human error rates from nuclear power plant date and operational experience.

A r.ote of caution is in order to minimize the improper use of the findings of this report.

The purpose of this report is to identify human errors, not to obtain human error rates.

NUREG/CR-3049 CLOSE0VT OF IE BULLETIN 79-15:

DEEP DRAFT PUMP DEFICIENCIES No, ember 1983 In 1978 serious manufacturing deficiencies in deep draft pumps were found in one facility.

Similar deficiencies, as well design deficiencies, were identified at about the same time in three other facilities which required pump rework and design changes, followed by extensive opera-tional testing.

These occurrences' raised questions concerning this type of pump in safety-related applications where there was insufficient pre-operational testing or operating experience to assure long term operability.

IE Bulletin 79-15 was issued to alert all facilities to the potential problem, to acquire information to determine the extent of the problem', and to request corrective action in facilities where the problem was found.

Review of utility response to the bulletin by NRC resulted in adding the evaluation of long term operability of deep draft pumps in safety-related applications to the normal ~1icensing process for plants under construction.

The operating plants where response information is judged not adequate to assure long term reliability are listed by Regions in Appendix C-45

Report Title together with proposed followup testing to satisfactorily assure long term operability and close out the Bulletin.

There are nine of these plants out of a total of 74 operating units.

Bulletin status remains open for one other facility where followup of response commitments, but no pump testing for assuring long term operability, is proposed.

NUREG/CR-3430 NUCLEAR POWER PLANT OPERATING EXPERIENCE (1981 Annual Report)

Vol. 1 December 1983 This report is the eighth in a series of reports issued annually that summarizes the operating experience of nuclear power plants in commercial operation in the United i

States.

Power generation statistics, plant outages, i

reportable occurrences, fuel element performance, and occupational radiation exposure for each plant are presented and discussed, and summary highlights are given.

The report includes 1981 data from 71 plants - 24 Aoiling water reactor plants, 46 pressurized water reactor plants, and one high-temperature gas-cooled reactor plant.

NUREG/CR-3458 AN EVALUATION OF THE NUCLEAR POWER PLANT 0.PERATOR LICENSING November 1983 EXAMINATION 1

This report contains findings and conclusions about the Nuclear Regulatory Commission's nuclear power plant operator licensing examination based on six months of field work in late 1981 and early 1982.

This report includes char.*.ers which describe and evaluate the examination systems as they existed at the time of the field work.

There are also discussions of the concepts of validity and reliability as they relate to the control room operator examination, operator performance measures, and performance-shaping factors.

The last half of the report focuses on what could and should be done to the cperator licensing system.

The report argues that any new examination must be based on task analysis and should incorporate methods for measuring an operator's problem-solving ability in ill-defined situations.

It is argued that the NRC needs to clarify whether their licensing examination is to be a test of minimal competence or a master test, whether the examination system is to serve the selection function, and whether separate licensing tests are needed for reactor operators and senior reactor operators.

The last chapter.

details a model of a new licensing process.

Features of-the process include validated selection procedures, a computerized basic knowledge examination, an apprenticeship l

period with documentation of performance, and a computerized, tailored test to assess, problem-solving ability and system i

i understanding.

l l-46

s i

~

Report Title NUREG/CR-3540 RADIOLOGICAL ASSESSMENT OF STEAM GENERATOR REPAIR AND December 1983 REPLACEMENT l_

Previous analyses of the radiological impact of removing l

and replacing corroded steam generators have been updated l

based on experience at Surry Units 1 and 2 and Turkey i

i Points Units 3 and 4.

The sleeving repairs of degraded l

tubes at San Onofre Unit 1, Point Beach Unit 2, and R.E.

l-Ginna are also~ analyzed.

Actual occupational doses incurred during application of the varicus technologies used in repairs have been included, along with radioactive waste quantities and constituents.

Considerable progress has been made in improving radiation protection and reducing worker dose by the development of remotely controlled equipment and the implementation of dose reduction strategies that have been successful in previous repair operations.

NUREG/CR-3568 A HANDBOOK FOR VALUE-IMPACT ASSESSMENT December 1983 This. handbook documents a set of uniform and acceptable procedures for providing information that can be used in-performing value-impact _ assessments of NRC regulatory actions.

It describes a systematic but flexible process for performing the assessment.

Chapter 1' introduces the-value-impact assessment process.

Chapter 2 describes the attributes most frequently affected by proposed NRC actions, provides guidance concerning the appropriate level of effort to be devoted to the assessment,-suggests a standard format for documenting the assessment, and discusses the treatment of uncertainty. : Chapter 3 details methods for evaluating each attribute affected by a regulatory action.

i Five appendices contain background information, tecnnical'

' data,.and example applications of the value-impact assess-ment procedures.

This edition of the handbook focuses

- primarily on assessing nuclear power reactor safety issues.

4

'47

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