ML20077R565

Power Reactor EVENTS.January-February 1983

ML20077R565
Person / Time
Issue date:	08/31/1983
From:	Massaro S, Trenery S NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
To:
References
NUREG-BR-0051, NUREG-BR-0051-V05-N1, NUREG-BR-51, NUREG-BR-51-V5-N1, NUDOCS 8309200526
Download: ML20077R565 (47)

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1 NUREC/BR-0051 6% POWER REACTOR EVENTS

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United States Nuclear Regulatory Commission January-February 1983/Vol. 5, No.1 Power Reactor Events is a bi-monthly newsletter that compiles operating experience information about commercial nuclear power plants. This includes summaries of noteworthy events and listings and/or abstracts of USNRC and other documents that discuss safety-related or possible generic issues. It is intended to feed back some of the lessons learned from operational experierie 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 at1717 H strert. Washington, DC 20555 for a copying fee. Subscriptions and additional or back issues of Power Reactor Events may be requested from the NRC/Gl'O sales Program,(301) 492-9530 or at PHIL-016. Washington, DC 20555.

Table of Contents 080 1.0 SUMMARIES GF EVENTS 1.1 Failure of A utomatic Reactor Trip System............................................

1 1.2 Main Feedwater Line Break Due to Water Hammer.................................

8 1.3 Loss of All Charging Pumps Due to Empty Common Reference Leg.............

11 12 1.4 Blocking of Automatic Safety injection Signals......................................

1.5 Inadvertent RPS Trip with POR V Actuation..........................

14

1. 6 Radioactive Retease.................................................................

15 16 1.7 RCIC Switch Failure Due to Corrosion....................

17 1.8 Particle intrusion Affects APRM Scram Settings..........

1.9 Pressurizer Code Safety Valve Problem - Update..................................

21

1. 10 Re feren ces.........................................................................................

24 2.0 ABSTRACTS OF OTHER NRC OPERATING EXPERIENCE DOCUMENTS 2.1 Abnormal Occurrence Reports (NUREG-0090).......................................

27 28 2.2 Bulletins, Circulars, and information Notices...........................................

32 2.3 Engineering Evaluations and Case Studies.............................................

34 2.4 G eneric L e t ters........................................................................................

38 2.5 Operating Reactor Event Memoranda...................................................

39 2.6 Regulatory and Technical Reports.........................................................

Editor: Sheryl A. Massaro Associate Editor: Steven E. Trenery Office for Analysis and Evaluation of Operational Data U. S. Nuclear Regulatory Commission Published in:

August 1983 Washington, D. C. 20555 8309200526 830831 PDR NUREO DR-0051 R PDR

1.0 SUMMARIES OF EVENTS 1.1 Failure of Automatic Reactor Trip System On February 22 and 25,1983, the Salem Unit 1* reactor control rods failed to insert upon receipt of an automatic trip signal from the reactor protection system. Upon receipt of a manually initiated trip 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 was jeopardized when plant operating conditions required a fast shutdown to protect the integrity of the reactor core.

Safe control of certain anticipated operating transients depends on the reliable and fast operation of a reactor trip, either automatically or manually.

Event Descriptions At 12:21 a.m. on February 25, 1983, a low-low water level condition in one of the four steam generators at Salem Unit 1 initiated a reactor trip signal in the reactor protection system (RPS). The reactor was at 12% rated thermal power at the time, preparatory to power escalation after a recently completed refueling outage. Upon receipt of the valid reactor trip signal, both of the redundant reactor trip breakers (RTBs) failed to open. The failure of both RTBs to open for such an event is referred to as an anticipated transient without scram ( ATWS) event.

About 25 seconds later, operators manually initiated a reactor trip from the control room, which caused the RTBs to open. The opening of the RTBs deenergized the holding coils of the control rods, resulting in the insertion of all control rods and shutdown of the reactor. Following the manual trip, the plant was stabilized in the hot standby condition. All other systems functioned as designed. Later that morning, when the cause of the failure to automatically scram had been detemined by the licensee, the plant was placed in cold shutdown at the request of the NRC.

This ATWS event brought into question whether the reactor trip event of February 22, 1983 had also been an ATWS. Accordingly, the NRC requested the licensee to make a detailed post-trip review of the February 22 event. This review was perfomed on February 26, 1983, and revealed that a similar failure had occurred on February 22 at Unit 1.

This event began at 9:55 p.m. on February 22, with the reactor at 20% power. Operators were attempting to transfer the 4160 V group electrical busses from the station power transfomers to the auxiliary power transfomers, which is a standard procedure durir.g power esc al ation. During the transfer attempt, however, one of the 4160 Y busses failed to transfer and deenergized, resulting in the loss of one reactor coolant pump and power for the operating main feed pump control and indication.

At 9:56 p.m., a low-low level condition occurred in one steam generator (due to the loss of the main feed pump), initiating a reactor trip signal. Due to the abnormal conditions created by the loss of the 4160 V bus, and in anticipation of loss of steam generator water levels, the operator was directed at about the same time to manually initiate a reactor trip.

It was understood by plant personnel and was reported to the NRC that the automatic reactor trip signal due to the low-low level in one steam generator had, in fact, caused the reactor to trip. On February 26, as a result of NRC queries, the sequence of events computer printout for February 22 was reviewed in detail and it revealed Salem Unit 1 is a 1079 MWe (net) PWR located in New Jersey, 20 miles south of Wilmington, Delaware, and is operated by Public Service Electric and Gas.

J

s i that the RTBs actually opened in response to the operator's manual trip signal. Consequently, it is now evident that on February 22 (as on February

25) the two RTBs failed to open upon receipt of an automatic trip signal from the RPS.

Since the operators initiated a manual reactor trip shortly after receipt of the automatic trip signals on both February 22 and February 25, no adverse consequences occurred and the reactor was in a safe condition. On February 22, the operators initiated a manual trip even though they were unavare that the automatic trip had failed.

Background

Nuclear plants have safety and control systems to limit the consequences of abnonnal operating conditions. " Anticipated transients" are defined as abnormal operating conditions (e.g., loss of feedwater, loss of offsite power, tripping of the turbine generator), which are likely to occur one or I

more times during the life of a nuclear power plant.

In some such cases, a rapid shutdown of the nuclear reactor (fast insertion of the control rods into the reactor core - a reactor trip) is an important safety measure to assure that acceptable fuel design limits are not exceeded.

If there were a potentially I

severe transient, and the reactor shutdown system did not function as designed, I

then an ATWS would have occurred. ATWS safety issues have been under study by the AEC/NRC and the nuclear industry for a number of years. A proposed ATWS technical position and ATWS rule are presently being developed by the NRC.

The reactor protection system (RPS) is a safety-related system that encompasses all electrical and mechanical devices and circuitry (from sensors to actuation device input terminals) involved in generating those signals associated with the protective function. These signals include those that actuate reactor trip. The reactor trip system (RTS) is part of the RPS and includes those power sources, sensors, initiation circuits, logic matrices, bypasses, interlocks, racks, panels and control boards, and actuation and actuated devices, that are required to initiate reactor shitdown. The RTS is designed to initiate automatically the reactivity contr91 ;ystem (control rods) to shut down the reactor, thereby assuring that af.ceptable fuel design limits are not exceeded, and is designed to fail safe for most internal component failures. The RTS can also be actuated manually by operator action.

Plants designed by Westinghouse use two redundant RTBs in series in the RTS.

Salem Unit i uses Westinghouse 00-50 RTBs, each including an undervoltage (UV) trip attachment and a shunt trip attachment to actuate (open) the trip breaker.

The UV device initiates a breaker tri;i when deenergized, while the shunt device initiates a breaker trip when energized. For an automatic trip, only the UV device is actuated; initiation of the UV devices in either or both RTBs will release the control rods by deenergizing their holding coils. A manual trip signal operates both the UY device and the separate shunt device, both of which are designed to cause the RTBs to open.

Other PWRs have experienced RTB failures, both before and after the February 1983 Salem events. None of them, however, involved an ATWS event. With few exceptions, all PWR plants designed by the three nuclear steam supply system vendors (Westinghouse, Babcock & Wilcox, and Combustion Engineering) use an

_ _ _ _ _ _ _ _ _ _ _ _ RTS design requiring circuit breakers to open to trip the reactor. Al though the basic designs of the P.TSs and the number of RTBs per plant differ considerably among the plant designers, each RTB generally includes a UV trip attachment and a shunt trip attachment to actuate the circuit breaker.

Westinghouse-designed plants use a Westinghouse-type breaker (DB-type being the most common) while the other two PWR designers use a General Electric-type breaker ( AK-type).

The RTB failures prior to the February 1983 events at Salem Unit I have been the subject of several acticns taken since 1971 by the AEC/NRC, Westinghouse, and General Electric.

The AEC issued IE Bulletin (IEB) 71-2 on December 9,1971 (Ref.1) as a result of three failures of Westinghouse DB-50 RTBs at Robinson Unit 2 during 1971, and two failures of similar breakers at Haddam Neck (Connecticut Yankee) on December 2,1971. The bulletin infomed operating PWR licensees of the RTB failures and requested infomation on the results of testing, inspections, and corrective actions taken, or planned, by other facilities using similar RTBs.

Following further failures at Robinson Unit 2 on December 21, 1973, Westinghouse issued Technical Bulletin NSD-TB-74-1 on January 11, 1974, and NSD Data Letter 74-2 on February 19, 1974, regarding the recommendations for inspection and maintenance of DB-type breakers.

Between April 25, 1975, and January 31, 1979, failures of General Electric AK-type RTBs were experienced at Arkansas Unit 1, Crystal River Unit 3, Oconee Units 1 and 3, and Three Mile Island Unit 1.

Because of these failures, and additional failures of similar breakers used in other safety-related applications, the NRC issued IEB 79-09 on April 17,1979 (Ref. 2). The bulletin, which included General Electric Service Advice Letter (SAL) No.187 (CPDD) 9.3 regarding inspection and maintenance of AK-type breakers, stipulated require-ments for establishment and perfomance of an acceptable preventive maintenance program for the RTBs.

Further, following a November 30, 1980 breaker event at St. Lucie due to an adjustment problem, the NRC issued IE Circular 81-12 on July 22, 1981 (Ref. 3). This circular recommended procedures for independently testing the shunt and UV trip devices.

Causes of the Salem Events On February 25, approximately two hours after the Unit 1 event, the cause of the failure to trip was detemined by licensee instrumentation technicians to be failure of the UY trip device to function as designed in both RTBs.

The same problem had occurred on February 22, but had not been recognized by the licensee.

As previously discussed, the plant on both occasions was shut down by manual operator action.

Possible contributors to the failure of the UY trip devices are (1) dust and dirt; (2) lack of lubrication; (3) wear; (4) more frequent operation than intended by design; and (5) nicking of latch surfaces, caused from repeated operation of the breakers.

Based on an independent evaluation of the failed UV trip devices identified by the licensee, the NRC staff concl,uded that, while the Salem Unit 1 breaker failures occurred as a result of several possible contributors, the predominant cause was excessive wear accelerated by lack of lubrication and improper maintenance.

J It appears that no preventive maintenance was conducted on the Salem Unit 1 DB-50 circuit breakers until January 1983.

Some of the recommendations of the Westinghouse 1974 Technical Bulletin and Data Letter were not imple-mented during the January 1983 maintenance, since personnel perfoming the maintenance (includf ag a Westinghouse service representative) were not aware of this infomation. The January maintenance was performed because of a breaker problem that occurred at Salem Unit 2 on January 6,1993.

In this event, a reactor trip had occurred due to a low-low water level condition in one steam generator, and only one RTB operated. The second KTB finally opened 25 minutes later. The licensee concluded that this failure was due to dirt and corrosion interfering with proper operation of the UV trip device. As a result of this event, maintenance was conducted on all Unit 1 RTBs, at lecst one of which involved supervision of the RTB vendor, Westinghouse.

The licensee also reported that all reactor trip breakers were tested after maintenance per plant procedures.

As noted previously, the licensee failed to recognize on February 22, 1983 that an ATWS event had occurred. This was due to a lack of a thorough and systematic review to achieve the necessary understanding of the event. This deficiency, and certain previously identified problems at Salem, led the NRC to require that a number of corrective actions, including management improvements, be taken before allowing either plant to be restarted.

Actions Taken to Prevent Recurrence Licensee - The licensee has completed or committed to complete many corrective actions to preclude or minimize the likelihood of future ATWS events. These actions involve operating procedures, training and responses to ATWS events, and management issues.

Actions taken by the licensee include installing new UV trip devices on all Salem Units 1 and 2 RTBs, which incorporete all design changes made to the devices; augmenting surveillance test requirements, developing a c'mprehensive maintenance procedure; and incorporating Westinghouse recommenda-t'ans regarding maintenance and testing. Actions concerning operator procedures, training, and response issues include revising emergency procedures to identify actions to be taken in the event a reactor trip signal is received, conducting additional operator training, and evaluating certain aspects of the control room design. Actions concerning management issues include reviewing past maintenance and procurement documents to ensure that the problems associated with the RTBs did not extend to other safety systems; strengthening administrative controls over maintenance, procurement and post-maintenance testing activities; establishing additional safety review groups within the company; developing a fomal post-trip review procedure; instituting a program to update vendor-supplied infomation; and subjecting the company to independent management assessment by external consulting organizations.

Vendors - Westinghouse fomed an intercompany task force to conduct an internal review of their procedures for dissemination of technical infomation to utili ties.

In addition, they reviewed the testing program for the breakers.

Since there were generic implications associated with the Salem Unit 1 events, Westinghouse worked with the Owners Group (licensees of Westinghouse-designed plants) to review operating and emergency procedures, to review for similar type failures in other plant systems, and to assure that the owners have a current listing of Westinghouse technical infomation.

Westinghouse also developed updated maintenance procedures for RTBs, which will be given to the licensees with DB-type breakers.

In addition, ba:;ed on Westinghouse's review of problems experienced with their DS-type breakers at the Farley and McGuire facilities, they have alerted the NRC and appropriate licensees to potential deficiencies involving clearance and dimensional problems and retaining ring seating defects which could create conditions under which the RTBs might not open automatically on demand from the RPS. Westinghouse also developed procedures for the affected licensees to follow. DS-type breakers are currently used in five operating plants (Farley Units 1 and 2, McGuire Units 1 and 2, and Summer) and specified for use in 24 plants still under construction.

Combustion Engineering and Babcock & Wilcox also made similar reviews, and in cooperation with General Electric, developed updated maintenance pro-cedures for RTBs, which will be given to the licensees with AK-2 type breakers.

Other Licensees - In response to N'<C IEBs 83-01 and 83-04 (discussed later),

the licensees either perfomed the RTB testing required (or stated why they were exempt) or provided a schedule for when it would be perfomed, and took the other actions required by the bulletins regarding maintenance, operating procedures, etc. During, and subsequent to the required testing, additional cases of RTB failures occurred.

NRC - Due to the serious nature of the known automatic trip failure in both redundant RTBs on February 25, the NRC issued IEB 83-01 (Ref. 4) on the same day to all PWR facilities holding an operating license for action, and to other nuclear power reactor facilities for infomation.

The bulletin infomed the licensees of the Salem February 25 event (the similarity of the February 22 event had not yet been ascertained), and mentioned that failures involving only one of the two breakers had previously occurred at Salem Unit 2, Robinson Unit 2, Connecticut Yankee, and St. Lucie.

The bulletin referenced the two previously discussed pertinent NRC documents; i.e., IEB 71-2 and Circular 81-12, which were issued on December 9,1971 and July 20, 1981, respectively. Also mentioned was the previously discussed Westinghouse technical infomation issued on their breakers; i.e., Technical Bulletin NSD-TB-74-1 dated January 11, 1974 and NSD Data Letter 74-2 dated February 14, 1974. Action items required of licensees using Westinghouse DB type breakers by IEB 83-01 included:

(1) testing of the Westinghouse DB-type breakers, (2) assuring maintenance is in accord with the recommended Westinghouse program, (3) notifying licensed operators of the Salem Unit 1 events, (4) reviewing with the operators the procedures to follow in the event of failure of trip, and (5) reporting the results to the NRC.

During the testing required by IEB 83-01, no further failures of Westinghouse DB-type RTBs occurred. However, even though not required to do so by the bulletin, Southern California Edison decided to test the General Electric AK-2 breakers on its Combustion Engineering-designed San Onofre Units 2 and 3.

1 On March 1,1983, one of eight RTBs in Unit 3 failed to trip on undervoltage.

On March 8,1983, three of eight RTBs in Unit 2 failed to trip on undervoltage.

(Note: Contrary to the Salem design in which an automatic trip signal is fed only to the UV trip devices, the trip signal is fed to both the UV and shunt trip devices for the San Onofre Units 2 and 3 design.

Since the shunt devices functioned properly, the RTBs would have tripped from an automatic trip signal during operations.)

During the investigations of these events, it was found that previous failures had occurred at these units during 1982 but had not been reported to the NRC.

Accordingly, IEB 83-04 (Ref. 5) was issued on March 11, 1983 to all PWR facilities hciding an operating license (except those with Westinghouse DB-type breakers) for action, and to other nuclear power reactor facilities for information.

The bulletin described the San Onofre events and mentioned that similar events involving the General Electric AK-2 breakers had previously occurred at Arkansas Unit 1, Crystal River Unit 3, Oconee Units 1 and 3 Three Mile Island Unit 1, St. Lucie Unit 1, and Rancho Seco Unit 1.

The bulletin referenced the two previously discussed pertinent NRC documents; i.e., IEB 79-09 (which included General Electric recommended data on the AK-2 breakers) and Circular 81-12, which were issued on April 17, 1979 and July 20, 1981, respectively. Action items to be taken included:

(1) actions similar to those required by IEB 83-01; (2) that licensees provide a description of all RPS breaker malfunctions not previously reported to the NRC; and (3) that all licensees verify that procurement, testing, and maintenance activities treat the RPS breaker and UV devices as safety-related.

In response to IEB 83-04, additional cases of RTB failures were reported to the kRC.

In addition, other failures occurred after the testing required by IEBs 83-01 and 83-04.

In all cases, the NRC closely monitored the corrective actions taken by the licensees to assure that the plants were safe for continued operation.

On April 1,1983, the NRC issued Inspection and Enforcement Information Notice 83-18 (Ref. 6) to all nuclear power reactor facilities holding an coerating license or construction permit. The notice included these findings:

(1) based on the results of testing required by IEBs 83-01 and 83-04, breakers may not be achieving tne performance reliability expected of them, apparently due to the UV trip attachments; (2) the problem has ramifications not only for RTBs, but for similar breakers used in other plant applications; (3) regular, careful maintenance of RTBs is important (updated maintenance procedures have been developed by all PWR vendors);

(4) there may be limitations associated with the design life of UV devices I

such that periodic replacement may be necessary due to wear; (5) the torque available to trip the General Electric AK-2 breaker by the UY device is critical to proper operation so that certain measurements are needed periodically to detect the onset of problems; and

. (6) a thorough post-trip analysis, including close scrutiny of the events recorder, is important.

On February 28, 1983, the NRC Executive Director for Operations (ED0) directed NRC Region I to develop a detailed report of the Salem Unit 1 events; this report was subsequently issued as NUREG-0977 (Ref. 7).

The EDO further directed that a special NRC task force be fomed to evaluate the generic implications of the events.

The special NRC task force prepared a report (kUREG-1000, Vol.1) addressing the generic implications of the Salem events (Ref. 8). The NRC actions to be taken based on the task force efforts include the issuance of a letter to licensees addressing intermediate term generic actions; amendments to the ATWS rule; and improvements to the regulatory programs affecting licensee management performance, maintenance activities, quality assurance, and the collection and analysis of operating experience.

Several briefings were given to the Commissioners by the staff regarding the Salem problems and other ongoing studies. Prior to allowing Salem to restart, the Commission not only required the satisfactory implementation of the short tem corrective actions, but also required that certain management improvements be satisfactorily addressed. As stated previously, the licensee agreed to pemit outside consulting fims to evaluate management effectiveness at the Salem plants.

Af ter reviewing the consultants' recommendations, the licensee will generate a plan to incorporate them. On April 26, 1983, the Commission agreed that the plants could be returned to service, after the NRC staff is satisfied with the licensee's commitment to meet restart conditions.

The licensee's commitments for both restart and long term conditions, including schedule for implementation, were submitted to the NRC on April 28, 1983. The NRC incorporated these commitments into an Order dated May 6,1983. The licensee's commitment for restart was:

Before entering any new mode, all systems and components required to be operable for that mode, in accordance with Technical Specifi-cations, shall be reviewed to confirm operability.

If all or part of a system or component has not been shown to be operable within 30 days prior to April 28, 1983, a review shall be conducted to detemine if maintenance or other activity has taken place on such system or component since the last operability confirmation.

If such maintenance or other activity has taken place, operability shall be verified by applicable surveillance testing and/or preparation of a written analysis, available for NRC inspection, demonstrating that the system or component is capable of perfoming its intended function.

This procedure will be followed until the first entry into Mode 1 for each unit subsequent to April 28, 1983.

The review of documentation and additional surveillance testing necessitated by the licensee's commitment delayed plant startup until May 20, 1983.

The RRC safety evaluation related to plant restart was forwarded to the licensee by a letter dated April 29,1982 (Ref. 9).

l On May 5,1983, the NRC forwarded to the Salem licensee a Notice of Violation and Proposed Imposition of Civil Penalties (for $850,000) for problems identified at the facility (Ref.10). The general issues associated with RTB failures remains under active review by the nuclear industry and the NRC.

1.2 Main Feedwater Line Break Due to Water Hammer On January 25, 1983, Maine Yankee

• experienced a reactor trip which sub-sequently caused a water hammer in the feedwater lines for two of the thrre steam generators, with a resultant feedwater pipe rupture.

The plant uses a three-loop reactor coolant system design, each loop containing a steam generator (SG), a reactor coolant pump, and associated connecting piping. The SGs employ a vertical U-tube design.

Feedwater is normally provided to the secondary side of each SG by operating one of two motor-driven main feedwater ptanps when the plant power level is less than 50%,

or a turbine-driven feedwater pump for power levels greater than 50%.

(This is a new feedwater configuration for Maine Yankee; until recently, the plant did not have a turbine-driven feedwater pump and main feedwater had been provided only by motor-driven pumps for all power levels.)

If all sources of main feedwater are lost, an auxiliary feedwater system is available to supply the three SGs using portions of the nomal feedwater lines.

On January 25, the plant was operating near 100% power with only its new turbine-driven feedwater pump supplying feedwater; both motor-driven feedwater pumps were out of service for maintenance. While operator: :ere attempting to isolate an electrical ground in the control rod drive systems, a reactor trip occurred. As a result, both the main turbine and the turbine-driven feedwater pump tripped. This resulted in a complete loss of nomal feedwater flow, followed by a nomal reduction in SG water level associated with the reactor trip. When the SG water level reached approximately 30% (on the narrow range indicator), auxiliary feedwater flow automatically initiated, as designed.

Approximately 15 minutes after the trip, a loud noise was heard in the plant machine shop, which is just below the main feedwater lines. Additionally, a containment fire' detector (temperature sensitive) alamed and containment humidity began to rise. The containment was entered for inspection, and the feedwater line for SG No. 2 was found to be leaking severely near the inlet nozzl e.

The leak rate was estimated to be a maximum of 100 gpm.

Feedwater flow to SG No. 2 was teminated and its level maintained by inter-connecting the tube sheet drains for all three SGs. Nomal station cooldown was initiated to facilitate inspection and repair.

Reactor coolant system parameters were stable and within nomal ranges for this operating condition.

During the cooldown period (about 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) leakage continued through the feedwater line. This spillage was routinely removed and disposed of through the containment auxiliary sump drain system.

(

Maine Yankee is an 810 MWe PWR located ten miles north of Bath, Maine, and is operated by Maine Yankee Atomic Power.

- - - - - - _ _ _ - _ _ _______________ _____ ____ _ _________________.___ y

__ ____ _ __ Subsequent inspection of the SG No. 2 feedwater piping showed that a through-wall crack had occurred in the pipe adjacent to the weld joining the pipe and SG safe end. It is believed that the water hammer had caused an existing crack to propagate on through the pipe wall. The location of the crack coincided with a stress riser area in the piping. Radiographic examinations showed similar cracking had also begun on the SG No.1 and No. 3 feedwater pipes.

Further examination showed various degrees of damage to some snubbers and other supports for the SG No. 2 and No. 3 feedwater lines, a feed ring support for SG No. 3, and the safe ends and nozzles (including distorted themal sleeves) for SGs Nos. 2 and 3.

The water hammer probably occurred when the outlet nozzle at the bottom of the SG feed ring became submerged in the rising SG water level and the steam in contact with cold feedwater within the ring suddenly collapsed.

The cause of the event is attributed to incomplete consideration, in ongoing design and operational plant upgrading, of previous generic safety concerns related to SG water hammer and feed line themal stress cracking. The installation of a steam turbine-driven main feed pump and automatic initiation of the cold water auxiliary feedwater system without the addition of J tubes and operational pro-cedures to alleviate these concerns increased the potential for feedwater piping thermal shock and water hammer at Maine Yankee.

Before the design and operational changes were made, the plant had apparently not experienced any water hammer problems.

Review of plant operating history indicated that previous full load trips were followed by continuous main feedwater flow to the SGs via the bypass valves.

(These valves bypass the nomal feedwater regulating valves at low flow rates.) This flow was provided by the motor-driven main feedwater puinps that continued to operate, feeding about 5% of full flow to each SG through the bypass valves fc110 wing the trip. Hence, wam feedwater would be supplied, minimizing the potential for thermal shock and water hammer.

In two recent prior trips in which main feedwater was lost, power levels were below 50% so that SG 1evel shrinkage was less. Also, the auxiliary feedwater system was manually started and the flow rate controlled by the plant operators.

In the January 25 event, the trip was from full power.

Since the turbine-driven feedwater pump tripped, all main feedwater was lost. Auxiliary feedwater was initiated automatically when the SG 1evel reached approximately 30% (on the narrow range indicator). However, the auxiliary feedwater was drawn from the demineralized water storage tank at 60*F.

By comparison, nomal feedwater temperature is about 440*F. The extreme temperature differential between the nomal and auxiliary feedwater can cause two problems.

First, it can cause potentially high themal stresses and cracking in the feedwater piping.

Second, it may rapidly condense any steam in the feed lines and lead to a higher possibility of water hammer in the feed ring and feedwater line.

The licensee repaired components damaged by this event. This included replacing cracked feedwater piping and replacing or repairing damaged piping supports and SG internals. The licensee also implemented a design change and operational changes to minimize the potential for future water hammer; some of the changes will also minimize the themal cycling of the feedwater lines and SG nozzles, and the potential for any future themal fatigue failures.

l l

The design change consisted of adding J-tubes to the top of the SG feed rings.

This change increases the area for pressure equalization.

It also greatly reduces the rate at which the feed rings drain when the SG water level drops below the feed ring after a trip; thus, on early initiation of auxiliary feedwater flow, the feedwater line and feed ring are expected to remain full.

The design change has been used at other plants to reduce the possibility of water hammer events. The operational changes are as follows:

(1) During nonnal power operation with less than two motor-driven feed pups, at least one motor-driven feed pump will be in the standby mode. On loss (trip) of the turbine-driven feed pump, the standby pep will automatically start and its discharge valve will open. This will ensure that the residual heated water in the feed train will be used to its best advantage.

(2)

To ensure that the auxiliary feedwater is as warm as possible, the deminer-alized water storage tank will be maintained between 80*F and 100*F.

(3)

When auxiliary feedwater is automatically initiated, the operator will determine if the main feedwater system is operating.

If this is the case, he will trip off the auxiliary feed pumps and restore the steam generator level via the feedwater bypass valves.

Should continued auxiliary feedwater be needed, then the operator will re-route the flow through the first stage heaters, to minimize thermal transients.

Stable system operation would be required before this changeover is made.

(4)

If all feedwater flow is lost for several minutes due to a loss of all ac power (a low probability event), then feedwater flow would be reintro-duced at veey low flow rates.

(In the event of loss of ac power, Maine Yankee's steam-driven auxiliary feedwater pump is currently started manually.)

This is a precaution based on the assumption that the feed ring has partially drained and could be subject to water hammer loads.

However, actual measurements indicate the feed ring drain time would then be in excess of two hours.

(5) When in hot standby or shutdown, the auxiliary feedwater flow will be wanned by auxiliary steam in the first stage heaters.

The licensee conducted a series of tests to verify the integrity of the feedwater lines, and to verify that the design change and operational changes were effective.

The first set of tests were hydrostatic tests of the individual feedwater lines from each SG back to the main feedwater control station. The second set of tests verified the ability of the J-tube addition to the feed rings to mitigate water hammers in the feedwater lines.

In these tests, conditions similar to those occurring at a full power trip were simulated at low or zero power. Water level in the SG was lowered, uncovering the feed rings. This initiated auxiliary feedwater flow to restore the SG water level. Any water hammer accompanying this transition could be monitored by plant personnel and test instruentation.

The licensee stated that the actual test results gave virtually no indication of any water hammer problem.

The licensee plans to carry out additional work to minimize the potential for recurrence of this event, and to ensure thermal cycling does not lead to other equipment or component failures. This includes removing all feedwater piping between the feedwater check valves and 90* down-turning elbows to modify the stress risers. Also, the additional stresses to SG nozzles due to the distorted thermal sleeves will be analyzed.

If needed, the thermal sleeves in the SG nozzles will be repaired or replaced at the next refueling outage.

Future hardware and procedural changes to the plant will also be evaluated.

(Re fs.11 through 13.)

1.3 Loss of All Charging Pumps Due to Empty Common Reference Leg On October 23, 1982, with St. Lucie Unit 1* in hot standby during recovery from a reactor trip, the three inservice positive displacement charging pumps (PDPs) stopped circulating coolant to the reactor coolar t system because the volume control tank (VCT) was pumped dry. The VCT was empty although its two liquid level sensors each indicated an acceptable liquid inventory and, hence, an apparently acceptable inflow / outflow balance from the VCT.

The VCT was pumped dry because the two liquid level sensors (LT 2226 and LT 2227) were erroneously indicating an acceptable level of liquid within the VCT.

The false level indication was caused by an snpty reference leg that is shared by both liquid level sensors. The reference leg was found to be leaktight and the cause of the enpty reference leg is not known. During the loss of charging flow, there was no significant decrease in pressurizer level. The pagps were restored to operation by repeated venting after filling the VCT to a high level. Two charging pumps were operating at a reduced flow within 15 71nutes; the third pump was restored to operability in about 30 minutes.

\\

During recovery from the reactor trip, and just before the loss of charging flow, the pressurizer level had been restored to above the heater cutoff level by operating all three charging pumps. The primary system had stabilized at no-load T-average and reactor coolant system (RCS) pressure was 1960 psia. The event began when plant personnel noticed that pressurizer level was no longer continuing to increase. A loss of charging flow was confirmed by checking the flowmeter in the common discharge header of the charging pumps.

It was reading zero. The PDP casing vent valves were opened, and gas came out instead of liquid, indicating the charging system had lost its prime. The operators continued to investigate upstream of the PDPs until they discovered the VCT to be dry and the source of the gas. There was no known injection of gas downstream of the PDPs.

One of the primary purposes of the charging pumps at St. Lucie is to provide normal RCS makeup flow; another is to borate or deborate the RCS. All of the three charging pumps at Unit 1 are positive displacement (piston) triplex pumps manufactured by ARMC0 with a rated capacity of 44 gpm each.

Their rated net positive suction head (NPSH) is 9.0 psia. The pumps are located on the floor level of the reactor auxiliary building and take suction from the VCT, which is located on the next higher floor level, to provide a positive suction head. Normally, one charging pump is running to balance letdown purification flow and reactor coolant pump (RCP) leak-off flow with St. Lucie Unit 1 is a 777 MWe (net) PWR located 12 miles southeast of Ft. Pierce, Florida, and is operated by Florida Power and Light.

)

charging flow into the reactor coolant system. The second and third pumps 4

^

automatically start and stop on demand as pressurizer level decreases or increases with load transients or varying plant conditions.

The liquid level sensors at St. Lucie Unit 1 are Fisher & Porter Co. Model delta-T(P) transducers.

Both sensors share common high and low level penetration taps in the VCT. These two instruments also share the same

(

instrument sensing lines with the common connecting point being in close proximity to the point of connection to the instruments. This instrument and 4

its spare are calibrated on a monthly basis. Although there had been no previous problems, the licensee was aware that if some degree of reference j

leg liquid is lost, no disagreement in indication between sensors would be i

apparent and the operator would not realize the indicated VCT level was incorrect.

~

Liquid level sensors are actually differential pressure transducers with input taps connected to high and low points of the VCT.

The measured VCT i

liquid level is proportional to the differential pressure sensed by the transducers. The reference tap of the differential pressure transducers is filled with liquid to provide a measurement that is independent of the elevation of the transducer. With a common reference leg, if some degree of reference level is lost (either by loss of actual liquid or by drift of the electrical bridge), there is no induced disagreement beteen sensors, and an undetectable offset exists between the indicated tank level and true tank level.

In the St. Lucie event, with an empty reference leg, the offset was sufficient to indicate an acceptable VCT level when, in fact, i

the VCT was dry.

Corrective actions included replacing the Fisher 4 Porter pressure trans-ducers (which are no longer available) with Rosemount Model 1153 Series D transmi tters.

Separate instrument lines, including separate reference legs for each instrument, are being routed as close as possible to the takeoff (root) valves.

In addition, the maintenance procedure will be modified to indicate that each instrument reference leg must now be filled monthly prior to calibration.

(Refs. 14 and 15.)

1.4 Blocking of Automatic Safety Injection Signals In 1982, Trojan

• and North Anna' Unit 1** experienced inadvertent blocking of both trains of automatic safety injection (SI) while each plant was in an operating mode that required the trains to be operable thus violating the technical specificationso Since both plants are PWRs designed by Westinghouse, these events are being discussed because they suggest a possible generic problem with the interpretation of the standard technical specifications (STSs) for Westinghouse PWRs.

f Trojan is a 1080 MWe (net) PWR located 42 miles north of Portland, Oregon, and is operated by Portland General Electric.

North Anna Unit 1 is an 865 MWe (net) PWR located 40 miles northwest of

' Richmond, Virginia, and is operated by Virginia Electric and Power Company.

s

E s

4

_ 13 _

On August 18, 1982, while preparations were being made to restart the Trojan plant after a refueling outage, both trains of automatic SI were unblocked prior to entering hot shutdown, in accordance with general operating instructions.

Th'ey were subsequently reblocked, however, without the use of a required safety-1

",' related equipment outage worksheet, to prevent a spurious SI while still in cold shutdown. Both trains remained blocked upon entry into hot shutdown

~

7 and subsequent entry into hot standby for a total duration of about 44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br />.

Shift operations pe sonnel were aware that automatic SI was blocked and had discussed contingency action should SI be required; they were not aware that the/ situation was in violation of STS 3.2.2.1 which requires that automatic SI

- be operable from hot shutdown through power operation. The problem was discovered by the operational supervisor during a routine walkdown of the control room. The reactor trip breakers were closed on August 20, which automatictlly unblocked the SI signals.

On December)SI' on December 5, it was discovered that both trains of automatic

~

,1982, while North Anna Unit 1 was in-hot standby following an inadvertent SI had been b1'ocked.for a period of 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> and 30 minutes. Following the inadvertent SI, an operator had " set" the automatic SI block per the applicable emergency procedure. The Licensee Event Report for this event (Ref.17) states that the emergency procedure implied that the automatic SI block required resetting within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> after an SI initiation; however, Westinghouse STS Table 3.3-3 }equires that both channels of SI automatic actuation logic be operable from hot shutdown through power operation.

The licensee revisea emergency procedures to include a step in the SI securing instructions to cycle the reactor trip breakers, which will reset the automatic SI block.

During the periods that automatic SI was blocked at North Anna and Trojan, both plants lad no challenges that required automatic SI. Had SI been required, only manual initiation was available, since all automatic signals were blocked.

As stated previously, for both plants, the STS requires that both channels of SI automatic actuation logic be operable from hot shutdown through power operation.

The applicable action statement reads, "With the ntsnber of OPERABLE channels one isss than total number of channels be in at least H0T STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />..." The action statement does not address having both channels of automatic SI signals inoperable. However, STS 3.0.3, states, "In the event 'an LCO [ limiting condition for operation] and/or associated ACTION requirements cannot be satisfied because of circumstances in excess of those addressed in the specification, the unit shall be placed in at least HOT STANDBY within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />..." This requirement then became the LCO. This LC0 implicitly allows both channels to be blocked for only one hour.

In addition, STS 3.0.4 is explicit in stating, " Entry into an OPERATIONAL MODE or other specified condition shall not be made unless the conditions for LC0 are met without reliance on provisions contained in the ACTION requirements." Hence both plants were in violation of TS requirements.

The automatic SI block features of Westinghouse PWRs are provided to enable plant operators to reset SI and manually control safety injection and associated safety-related equipment.with an SI signal locked in.

Such a feature allows operators to go from injection to the recirculation mode following an actual

___ event requiring SI or to return the plant to normal configuration following a spurious SI actuation. For the Trojan and North Anna Unit i events, both SI channels were blocked per plant procedures which subsequently led to a violation of technical specifications. The condition may have been avoided had the STS, in Section 3.3.2 on Engineered Safety Feature Actuation System Instrumentation and associated Table 3.3-3, explicitly addressed the blockage of both channels of Automatic SI Actuation Logic following an SI actuation.

These events are presented here to alert operators at Westinghouse PWRs of the possibility that leaving automatic SI blocked following SI initiation may lead to an inadvertent violation of their plant's technical specifications.

(Refs. 16 through 18.)

5 1.5 Inadvertent RPS Trip with PORY Actuation On February 3,1983, with Calvert Cliffs Unit 2* in hot standby (P=2250 psi; Tavg=500*F), a-testing sequence resulted in the inadvertent trip of the reactor protection system (RPS), with subsequent actuation of the power-operated relief valve (PORV). Testing wa3 in progress on the No. 21 inverter in the 120 V vital ac system, which supplies power to the RPS. Prior to returning the No. 21 inverter to service, the shift supervisor directed an operator to deenergize channel A of the RPS so that fuses would not be blown in channel A.

The operator mistakenly deenergized channel D of the RPS cabinet.

When the No. 21 inverter was lined up to channel A, the fuses did blow, thus deenergizing channel A.

Since channels A and D were deenergized, the RPS was actuated. The two-of-four coincidence of the pressurizer pressure high signal opened the PORV. The resulting blowdown to approximately 1500 psi caused an engineered safety features actuation signal on low pressure. However, pressure did not get low enough for water to actually be injected. The rupture disk in the quench tank opened to the containment, but no significant quantities of water or radiation were released. The D0RV subsequently was closed and the reactor coolant system was repressurized.

RPS channel A deenergized because a de input fuse to the No. 21 inverter blew while returning the inverter to service. The fuse blew due to crossed power leads in the inverter. The leads had been crossed the previous day during maintenance which required them to be lifted and replaced with a resistor bank for load testing the inverter. The leads have now been returned to their correct location.

The licensee is making a procedural change to insure that either a functional test is performed on equipment in which leads have been lifted during maintenance, or that the initial and final position of all leads lifted during maintenance is recorded. Also, all licensed operators and maintenance personnel have been informed of the event.

(Refs. 19 through 22.)

i Calvert Cliffs Unit 2 is an 825 MWe (net) PWR located 40 miles south of Annapolis, Maryland, and is operated by Baltimore Gas and Electric.

(

_A

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ 1.6 Radioactive Release On January 16, 1983, a radioactive release to the Tennessee River occurred from Browns Ferry Unit 3.*

At the time, Unit 3 was in cold shutdown for maintenance; Unit 2 was down for refueling; and Unit 1 continued to operate during the event without interruption.

An operator observed an increase in the radiation count rate on the RHR service water effluent monitor. Then, at 12:14 a.m. on January 16, 1983, the licensee placed the 3B pump and heat exchanger on Unit 3's residual heat removal (RHR) system in service and removed the 3D pump and heat exchanger after a routine RHR service water sample indicated high activity (1.9 times maximum permissible concentrations). However, no alann had been received from the service water effluent monitor. The licensee declared an Unusual Event at 2:04 a.m.

At this time, only the 3B RHR was operable since both the 3A and 3C RHRs were previously out of service for valve maintenance.

In the process of pressurizing the 3D heat exchangee to verify a leak, a radiation monitor on the service water effluent alarmed at 8:25 a.m.

The radiation monitor is common to both the 3B and 3D heat exchangers; therefore, until the cause of the alarm could be determined, the licensee isolated the 3B pump and heat exchanger. Since this resulted in a temporary loss of normal shutdown cooling capability for Unit 3, the licensee then dec' ired an Alert at 8:30 a.m. in accordance with procedures.

Until the licensee could confirm that the 3B heat exchanger was not leaking, an alternate means of core cooling was established by use of the condenser, control rod drive, and the reactor water cleanup systems.

Reactor coolant temperature increased from 185'F to a peak of 205*F and then started decreasing.

In addition, a cross tie to the Unit 2 RHR could have been established for cooling had it been necessary.

Pressure testing indicated that the 3B heat exchanger was not leaking. The 3B punp and heat exchanger were returned to service and the licensee cancelled the planc Alert at 7:17 p.m.

Both sides of the 3D heat exchanger were isolated and drained; however, until this could be accomplished, the defective 3D heat exchanger leaked reactor coolant into the RHR service water system which discharges into the Wheeler Reservoir and on into the Tennessee River. The amount of radioactivity released, about 0.015 curies in over 200,000 gallons of water, was in excess of technical specification limits; however, no environ-mental effects would be expected, particularly considering the large dilution of the radioactivity.

It was later determined that the 3D heat exchanger contained 12 dented tubes, with one dented tube leaking. All 12 tubes were plugged to remove them from service. An investigation will continue during the next refueling. outage to determine the cause.

(Refs. 23 through 25.)

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

4 1.7 RCIC Switch Failure Due to Corrosion At Hatch Unit 2* on August 28, 1982, two switches were discovered to be inoperable during surveillance testing of reactor core isolation cooling (RCIC) turbine exhaust diaphragm pressure instrumentation. Valves 2E51-F007 and -F008 were found closed, and the RCIC system was declared inoperable per technical speci-fications.

The event was caused by component failure of the switches after they sustained water and heat damage and subsequently became corroded. This damage was the result of a reactor trip on August 25, 1982, in which the scram discharge volume was exposed to full reactor pressure for an unusually long duration (45 minutes to one hour). A leaking scram discharge drain valve allowed hot water and steam to enter the building and equipment clean radwaste (CRW) drain sump.

Steam emerged from the CRW drain sunp into the RCIC room through an uncapped CRW hub. This emerging steam resulted in a sharp rise in the RCIC room temper-ature (above 180*F), which contributed to RCIC instrument setpoint drift. This rise in temperature also activated one of the RCIC room fire protection deluge system's spray heads, which resulted in the spraying of the RCIC instrunent rack. This sequence of events has implications of common mode failure of ECCS equipment, if other hubs are left uncapped, since all four diagonal (corner) rooms are interconnected with drains and hubs.

Combined with the high room temperature, this water damage resulted in an instrument isolation of RCIC on August 25, just as an operator was attempting to restart RCIC. At the time of this isolation, the reactor was being taken from the hot standby mode to cold shutdown because of the reactor trip mentioned above.

The licensee has cleaned, recalibrated, and tested the RCIC exhaust diaphragm switches per procedures. All other RCIC switches, valve motors, relays, and circuitry within the RCIC room subjected to the adverse environment following the reactor trip were also inspected, calibrated, and tested before return to service on August 29, 1982.

The scram discharge drain valve's air operator was found to have loose linkage hardware which allowed pressure to unseat the valve disk. The valve was disassembled and visually inspected; the internals were in satisfactory condi tion. The valve was reassembled. The valve's air operator linkage hardware was adjusted and tightened. The valve assembly was then satisfactorily tested, and was returned to service before the next unit startup.

The CRW drain hub in the RCIC room has been capped to prevent steam and water entering from other sources. Drain hubs have been inspected in each corner room and verified as being installed. The caps will be tar.k welded to the hubs to assure they remain installed. (Ref. 26.)

Hatch Unit 2 is a 771 MWe (net) BWR located 11 miles north of Baxley, Georgia, and is operated by Georgia Power.

_ The circumstances associated with the reactor trip on August 25, 1982 remain under review by NRC's Office for Analysis and Evaluation of Operational Data, and will be presented as an update in a following issue of Power Reactor Events.

1.8 Particle Intrusion Affects APRM Scram Settings On August 18, 1982, the reactor coolant system (RCS) conductivity at Pilgrim

• increased to 18 micromho's/cm due to a Powdex resin intrusion from the cleanup system following an inadequate backwash and pre-coat evolution. After con-ductivity returned within specifications, nomal power increase was resumed.

On August 20, while at 80% power, a reactor engineering technician noted that the process computer perfomance data indicated a problem with core flow from the jet pumps. This indicated that core flow calculated from the nomal recirculation / core flow relationship programmed into the computer was more than 5% greater than core flow from the jet pmps. The licensee determined that there was a mismatch between actual and expected recirculation-to-core flow relationship, and held power at 80%. The licensee was not sure at this time whether recirculation flow was high or core flow was low and proceeded to review supporting data.

A core flow calibration check was performed, and the core flow instruments were determined to be operating properly.

On August 21, the licensee concluded that the actual recirculation flow was approximately 3% too high compared with the indicated core flow. The senior reactor engineer realized the potential non-conservative effect on the average power range monitor ( APRM) flow-biased scram and rod block settings, and recommended that adjustments be made. The six APRM gains were adjusted to indicate about 3.5% higher than actual core themal power.

Conditions were closely monitored; without adjusting recirculation pmp speed, recirculation flow indication and the recirculation-to-core flow relationship returned to normal on August 24. Reactor power was not significantly changed during this period. (Ref. 26.)

The presence of resins and other impurities in the RCS coolant apparently causes a change in fluid properties which results in a reduction of the resistance to flow, and an increased recirculation flow for a given pep speed without a corresponding core flow increase.

If the mismatch between the recirculation / core flow relationship is merely due to an increase in recirculation flow without a corresponding increase in core flow, the APRM settings would be nonconservative (too high) for a given core thermal-hydraulic condition. The variable scram setting would be affected by a deviated flow. However, the fixed scram level would be unaffected by this event.

A recent study (Ref. 28) shows that polymer particle injection in turbulent water flow (in the order of a few ppm by weight) reduces drag substantially, up to I

70%; and the magnitude of the drag reduction is highly dependent on the particle Pilgrim is a 670 MWe (net) BWR located four miles southeast of Plymuuth, Massachusetts, and is operated by Boston Edison.

1 concentration in the water. Similar studies (Refs. 29 and 30) also demonstrate drag reductions due to different particle intrusion in turbulent flows, and the reductions seem to be highly dependent on the particle size, type, and degree or concentration of the suspended particles in the water. The studies also indicate that the drag coefficient is a function of the turbulent flow characteristics; i.e., Reynolds Number. The details of the drag reduction mechanisms are yet to be investigated. However, it is speculated that the suspended particles in the turbulent flow disturb the boundary layer and, thus, reduce the wall friction (wall shear stress), resulting in flow increase.

As shown in the attached flow path schematics (Figures 1 and 2), the suspended resin particles in the reactor water cleanup (RWCU) system are injected into the reactor vessel / core annulus through the feedwater line. The coolant in the annulus is divided into two components: one to the jet-ptanp driven now and the other to the recirculation loop flow (drive flow).

Since the recirculation flow is highly turbulent, any suspended particles in the recirculation loop cause drag reduction in the 'oop and, consequently, increase the recirculation flow under a given recirculation pump speed.

The increased recirculation loop flow is discharged into the intake ram-heads of the jet pumps, resulting in higher driving flows. However, the jet planp flow is only a function of a calibration constant (K-cal) and pressure gradient (AP) across the pump and is unlikely to be affected by the particle suspension.

Even though the K-cal is inversely proportional to M-ratio (a ratio of driven-to-drive flow), the effect of M-ratio change on the K-cal is extremely small.

Also, the AP across the jet pumps remains constant.

The jet pump flow thus is nearly independent of the particle suspension, and the flow remains approximately constant. Since the recirculation flow increases and jet pump flow (core flow) remains the same, the M-ratio (nomally 2.0) is decreascd. Therefore, if the recirculation flow is increased for a given feed flow, the driven flow has to be decreased ac-cordingly.

The APRM flow-biased rod block and trip setpoints are established as a linear function of the recirculation flow, even though the reactor power is proportional to the core flow. When the recirculation flow is increased due to particle intrusion without affecting the core flow, the proportional relationship between the core and the recirculation flow is modified such that the APRM setpoint is increased without a change in core power. Therefore, the APRM flow-biased setpoints have to be lowered by 0.66 Aw, where Aw is the increase in the recirculation flow or mismatch between the recirculation flow and the core flow. Eventually, the transient caused by the particle intrusion will return to a normal I

state, since the RWCU system will filter the particles deposited in the RCS from which the RWCU system takes a suction (bottom of vessel and recirculation loop), as shown in Figure 1.

I An NRC study of the event at Pilgrim and effects of particle intrusion on APRM scram settings conclude that there is no determined relationship

F TOP VIEW RING HEADER RX VESSEL L

J m

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r----

7 I

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l i

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RWCU

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L

___l FROM FROM RHR RHR SYSTEM 11 SYSTEMi 6-6 assage ze e5 1I TO RWCU <

II B$AS B ASI NETWORK TR NETWORK

^

=

s-x x-a TO CLEANUP TR SYSTEM A

n ON L--

PUMP MO MO PUMP FROM I

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Figure 1. REClRCULATION SYSTEM

. STEAM DRYERS 1 MAIN STEAM FLOW STEAM SEPARATORS l

A N

EXTERNAL RISERS O_.0) l _

regowa7ga

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37

1. 'I INTERNAL RISER M

MANIFOLD

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i

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JET PUMP

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MOTOR GATE VALVE h

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(PUMP FLOW COTrROL VALVE (BWR 15/6 ONLY)

Figure 2. SCHEMATIC OF RECIRCULATION SYSTEM

I between water conductivity and increase in recirculation flow.

In addition, the recirculation flow may increase without changes in core flow and recircu-lation pump speed whenever there is particle intrusion in feedwater flow.

This can be verified from process computer edits and recirculation loop flow elements.

(Ref. 31.)

1.9 Pressurizer Code Safety Valve Problem - Update This infonnation is provided as an update to " Pressurizer Code Safety Valve Problems," pp.1-4 of Power Reactor Events, September-October 1982/Vol. 4, No. 6.

The writeup discussed the temporary shutdown of Oconee Unit 2* on October 14, 1982, after the licensee (Duke Power Company) determined that, based on known ring valve settings, pressurizer code safety valve design flow could not be fully maintained if called upon. The licensee action was prompted by notification from the nuclear steam system supplier, Babcock and Wilcox (B&W) of a generic concern regarding the possibility that adequate flow might not be obtained for the pressurizer code safety valves, manufactured by Dresser Industries, for some combinations of backpressure and valve adjustment. The concern arose from B&W's review of data from the generic relief and safety valve test program recently completed by the Electric Power Research Institute (EPRI). The EPRI testing had been performed in response to NRC's NUREG-0737,

" Clarification of TMI Action Plan Requirements," which required that a relief and safety valve test program be conducted to verify operability of these valves (Models 31739A and 31709NA) under postulated accident conditions. The results of the testing, released on July 1,1982, indicated that with ring settings of

+11, -40, -48 (lower, middle, upper rings), the Dresser 31739A safety valve provided adequate relief under all expected conditions.

However, at Oconee Unit 2, these ring settings could result in an increase in blowdown (a rapid depres-surization) in some cases.

In light of the EPRI test data and Duke Power Company's discovery, the NRC gathered infonnation on the safety significance of these problems from pressurized water reactor (PWR) vendors, PWR regulatory response groups, and licensees using Dresser safety valves. A generic safety evaluation (SE) was perfonned to provide a justi-fication for continued operation of PWRs with Dresser safety valves until ring settings recommended by EPRI, Dresser, and PWR nuclear steam system suppliers (NSS5s) can be evaluated.

The NRC SE was done in two steps. First, the staff detennined the minimum primary safety valve relief capacity needed to meet ASME code limits for the most limiting transients. This step was done generically in most cases with separate consideration given to the general design of each PWR vendor - B&W, Westinghouse (W), and Combustion Engineering (CE).

In the second step, the staff detennined if the Dresser valves at each plant could provide the minimum relief capacity required to satisfy the most limiting transient.

Results of these analyses are shown in Table 1.

Oconee Unit 2 is an 860 MWe (net) PWR located 30 miles west of Greenville, North Carolina, and is operated by Duke Power.

t

3 l

Table 1 RATED VALVE PEAK RCS***

REQUIRED VALVE NSSS CAPACITY LIMITING PRESSURE CAPACITY (% OF VENDOR PLANT (LBS/HR-MWt)-

TRANSIENT-(PSIA)

RATED)

B&W Oconee 1/2/3 232 Subcritical

<2600 50 Rod Withdrawal B&W Crystal River 3 234 Subcritical

<2600 50 Rod Withdrawal B&W Arkansas 1 334 Subcritical

<2600 50 Rod Withdrawal B&W Rancho Seco 309 Subcritical

<2700 50 Rod Withdrawal CE Palisades 235 100% Load

<2400 25 Rejection CE Calvert Cliffs 1/2 220 100% Load 2550 25 Rejection 10*

CE Millstone 2 220 100% Load 2573 25 Rej ection CE Maine Yankee 228 100% Load 2689 25 Rej ection CE San Onofre 2 298 Feedwater 2860 100 Line Break W

North Anna 1/2 420 Seized RCP

<2750 40**

Shaft 10% is the plant specific calculation for Calvert Cliffs 1.

Based on Design Basis Loss of Load Transient.

For 100% Rated Capacity.

l The NRC concludes that this SE provides adequate justification for continued operation of plants using Dresser primary safety valves.

Each utility with plants using these valves is continuing to study the EPRI data in concert with vendors and owners groups. This justification is intended to support continued operation until the proper settings are adjusted. The NRC believes that plant shutdown solely to adjust the rings is not warranted.

It readjustment is necessary, justification for continued operation has been provided until the first outage of sufficient length to allow ring adjustments after the proper ring settings have been determined.

(Ref. 32.)

1.10 References (1.1) 1.

U.S. Nuclear Regulatory Commission, Bulletin No. 71-2, regarding Westinghouse DB-50 reactor scram circuit breakers, December 9,1971.

2.

U.S. Nuclear Regulatory Commission, Inspection and Enforcement Bulletin No. 79-09, " Failures of GE Type AK-2 Circuit Breakers in Safety-Related Systems," April 17, 1979.

3.

U.S. Nuclear Regulatory Commission, Inspection and Enforcement Circular No. 81-12 " Inadequate Periodic Test Procedure of PWR Protection System,"

July 22,1981.

i 4.

U.S. Nuclear Regulatory Commission, Inspection and Enforcement Bulletin No. 83-01, " Failure of Reactor Trip Breakers (Westinghouse DB-50) to Open on Automatic Trip Signal," February 25, 1983.

5.

U.S. Nuclear Regulatory Commission, Inspection and Enforcement Bulletin No. 83-04, " Failure of the Undervoltage Trip Function of Reactor Trip Breakers," March 11, 1983.

6._ U.S Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 83-18, " Failures of the Undervoltage Trip Function of Reactor Trip System Breakers," April 1, '1983.

7.

U.S. Nuclear Regulatory Commission, "NRC Fact-Finding Task Force on the ATWS Events at Salen Nuclear Generating Station, Unit 1, on February 22 and 25, 1983," USNRC Report NUREG-0977, published March 1983.

8.

U.S. Nuclear Regulatory Commission, " Generic Implications of ATWS Events at the Salem Nuclear Power Plant," USNRC Report NUREG-1000, Vol.1, published April 1983.

9.

Letter from D. G. Eisenhut, Director, Division of Licensing, NRC Office of Nuclear Reactor Regulation, to R. A. Uderitz, Vice President-Nuclear, Public Service Electric and Gas Company, transmitting "NRC Safety Evaluation Related to Plant Restart," Docket Nos. 50-272 and 50-311, April 29,1983.

10. Letter from Richard C. DeYoung, Director, NRC Office of Inspection and Enforcement, to Robert Smith, Chainnan of the Board, Public Service and Gas Company, transmitting a Notice of Violation and Proposed Imposition of Civil Penalties, Docket Nos. 50-272 and 50-311, May 5,1983.

i (1.2) 11.

U.S. Nuclear Regulatory Commission, Preliminary Notification PNO-I-83-03 (January 26,1983) and PNO-I-83-03A (January 27,1983).

12. Maine Yankee Atomic Power Company, Docket No. 50-309, Licensee Event Report 83-02, February 18, 1983.

_ _ _ _ _ _ _ _ _ _ 13. Letter from Robert A. Clark, USNRC/NRR, to John H. Garrity, Maine Yankee Atomic Power Company, transmitting a safety evaluation dated March 18, 1983, Docket No. 50-309, March 18,1983.

(1.3) 14. Florida Power and Light Company, Docket No. 50-335, Licensee Event Report 82-50, November 22, 1982.

15.

U.S. Nuclear Regulatory Commission, AE00 Engineering Evaluation E314,

" Loss of All Three Charging Pumps Due to Empty Common Reference Leg in the Liquid Level Transducers for the Volume Control Tank,"

June 28, 1983.

(1.4) 16. Portland General Electric Company, Docket No. 50-344, Licensee Event Report 82-15, September 3,1982.

17. Virginia Electric and Power Company, Docket No. 50-338, Licensee Event Report 82-82, December 20, 1982.

18.

U.S. Nuclear Regulatory Commission Memorandum from M. Chiramal, AEOD to K. Seyfrit, AEOD, transmitting Technical Review No. AE0D/T310, April 25,1983.

(1.5) 19.

U.S. Nuclear Regulatory Commission, Preliminary Notification PNO-I-83-07, February 4,1983.

20.

U.S. Nuclear Regulatory Commission Memorandum from D. H. Jaf fe, NRR/DL, to H. Denton, NRR, et al., re: Daily Highlight - Calvert Cliffs Unit 2 Inadvertent RPS Trip with PORY Actuation, February 4,1983.

21. Letter from L. B. Russell, Baltimore Gas and Electric Company, to R. C. Haynes, NRC/RI, re: LER 83-07, February 4,1983.

22. Baltimore Gas and Electric Company, Docket No. 50-318, Licensee Event Report 83-07, February 18, 1983.

(1.6) 23.

U.S. Nuclear Regulatory Commission, Preliminary Notification PN0-II-83-02, January 17, 1983.

24.

U.S. Nuclear Regulatory Commission Memorandum from R. J. Clark, NRR/0R, to H. Denton, NRR, et al., re: Daily Highlight - Browns Ferry Nuclear Power Plant Unit 3, January 17, 1983.

25. Tennessee Valley Authority, Docket No. 50-296, Licensee Event Report 83-04, February 15, 1983.

- 2ti -

(1.7) 26. Georgia Power Company, Docket No. 50-366, Licensee Event Report 82-100, Rev. 1, April 26, 1983.

(1.8) 27. Boston Edison Company, Docket No. 50-293, Licensee Event Report 82-31, September 15, 1982.

28. McComb, W. D., and Rabie, L. H. " Local Drag Reduction Due to Injection of Polymer Solutions into Turbulent Flow in a Pipe," AICHE Journal, No. 28, 1982, P. 547.

29. Shama, R.

S., " Drag Reduction by Fibers," Canadian Journal of Chemical Engineering, No. 59, 1981, p. 3.

30. Peyser, P., "The Drag Reduction of Chrysotile Asbestos Dispersions,"

Journal of Applied Polymer Science, No. 17, 1973, p. 421.

31.

U.S. Nuclear Regulatory Commission Memorandum from T. T. Martin, RI, to E. L. Jordan, IE, transmitting study on "Effect on APRM Scram Settings Due to Particle Intrusion," February 15, 1983.

(1.9) 32. NRC Memorandum LS05-83-04-041, from D. M. Crutchfield, NRR/DL, to R. Clark, NRR/DL, forwarding " Safety Evaluation by the Office of Nuclear Reactor Regulation - Support of Continued Operation by PWRs with Dresser Primary Safety Valves," April 18, 1983.

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

_ ______ 2.0 ABSTRACTS OF OTHER NRC OPERATING EXPERIENCE DOCUMENTS 2.1 Abnormal Occurrence Reports (NUREG-0090) Issued in January-February 1983 An abnormal occurrence is defined in Section 208 of the Energy Reorgan-ization 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 provisions of Section 208, the Office for Analysis and Evaluation lof 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.

Al so included in the quarterly reports are updates of some previously reported abnormal occurrences, and sunmaries of certain events that may be per-ceived by the public as significant but do not meet the Section 208 abnormal occurrence criteria.

Date Issued Report 1/83 REPORT TO CONGRESS ON ABNORMAL OCCURRENCES: JULY -

SEPTEMBER, 1982, NUREG-0090, VOL. 5, N0. 3 During the report period, there were two abnormal occurrences; one at the nuclear power plants licensed to operate and one at other NRC licensees. The first involved the loss of auxiliary electrical power at Quad-Cities on 6/22/82, and the second involved the rupture of at least one muericium-241 well logging source in 8/82 during well logging operations in Pennsylvania by the Consolidated Coal Company.

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

(1) steam generator feedwater flow instability at PWRs, first reported in NUREG-75/0090 (Jan.-June 1975); (2) loss of containment integrity, first reported in 1978, Vol.1, No. 4; (3) degraded engineered safety features, first reported in 1979, Vol. 2, No.1; (4) the accident at Three Mile Island, first reported in 1979, Vol. 2, No.1; and (5) seismic design errors at Diablo Canyon, first reported in 1981, Vol. 4, No. 4.

In addition, (1) the steam extraction line rupture at Oconee in 6/82, and (2) degraded safety relief valves at Hatch in 7/82 were discussed as items of interest that did not meet abnormal occu'-

rence criteria.

2. 7.

Bulletins, Circulars, and Information Notices Issued in January -

February 1983 The Office of Inspection and Enforcement periodically issues bulletins, circulars, and infomation notices to licensees and holders of construction permi ts. During the period, one bulletin and six 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 infomation 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, 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.

Circulars notify licensees of actions NRC recommends be taken.

Although written responses are not required, the licensees are asked to review the infomation and implement the recommendations that are applicable to their facility.

Information Notices are rapid transmittals of infomation 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 applica-bility of the infomation to their facility.

Date Bulletin Issued Subject 83-01 2/25/83 FAILURE OF REACTOR TRIP BREAKERS (WESTINGHOUSE DB-50)

TO OPEN ON AUTOMATIC TRIP SIGNAL This bulletin infomed licensees and holders of construction pemits about recent failures of Westinghouse DB-type circuit breakers to trip open on receipt of an automatic trip signal from the reactor protection system (RPS) and to require action of all operating pressurized water reactors to ensurt proper operation of those breakers in the future.

The most recent failure occurred during startup of Salem Unit 1 on 2/25/83, when both DB-50 RPS breakers failed to open automatically upon receipt of a valid trip signal on low-low steam generator level.

This breaker failure was attrib-uted to sticking of the undervoltage trip attactinent.

Other recent failures were caused by binding of the undervoltage trip attachment.

No circulars were issued in January-February 1983.

I

! Date Bulletin Issued Subject All holders of operating licenses for plants with this type breaker using undervoltage trip attachment in RPS applications were requested to:

(1) test undervoltage trip function independent of the shunt trip; (2) review their maintenance program; (3) notify all licensee operators of the 2/25/83 event at Salem; and (4) provide NRC with a written reply to the above within seven days of receipt of this bulletin.

Info rmation Date Notice Issued Subject 83-01 1/26/83 RAY MILLER, INC.

This information notice provided early notification of a potentially significant problem pertaining to fraudulent products (incorrectly marked piping, couplings, flanges, bushings, pipe plugs, etc.) that may have been sold to nuclear industry companies by Ray Miller, Inc., between 1960 and 1979. This problem may affect both BWR and PWR facilities.

This information notice was sent to all licensees and construction pennit holders.

83-02 1/28/83 LIMITORQUE H0BC, H1BC, H2BC, AND H3BC GEARHEADS This information notice provided notification of a potentially significant maintenance problem pertaining to the worm gear Limitorque H0BC, H1BC, H2BC, and H3BC gearheads. These gearheads may be used on manually operated valves or coupled with various sized Limitorque SMB-type actuators for power cperation.

It is advised that, should field maintenance be performed on any of these size gear-heads, the personnel involved should be cautioned to orient the worm gear segment with the butterfly valve travel as called for in Limitorque's maintenance instruc tions. These instructions are included as an attachment to the notice, which was sent to all licensees and construction permit holders.

83-03 1/28/83 CALIBRATION OF LIQUID LEVEL INSTRUMENTS This information notice provided notification on calibration of liquid level instruments which may have a safety significance.

Several licensees have reported inaccurate liquid level indications from instruments on various tanks, such as chemical

_ _ Infomation Date Notice Issued Subject i

addition tanks or boric acid storage tanks which contain liquid chemicals or solutions with densities different from that of water. Although density compensation is a basic requirement for accurate level measurements, it is periodically overlooked.

Density corrections including consideration of temperature, must be made for those liquids other than water that are contained in the tanks. The notice was sent to all licensees and construction permit holders.

83-04 2/18/83 FAILURE OF EU4A POWER SUPPLY UNITS This information notice provided early notification of potentially significant problems pertaining to 24 V DC power supply units manufactured by ELMA Engineering of Palo Alto, California. Degraded operation of these power supply units is character-ized by a high ripple voltage. At Peach Bottom, which experienced three failures within one year, the power supply degradation was attributed to a faulty capacitor.

Because of the potential safety significance and related generic implications of this problem, addressees are expected to review the infonnation for applicability to their facilities.

The notice was sent to all licensees and construction permit holders.

83-05 2/24/83 OBTAINING APPROVAL FOR DISPOSING OF VERY-LOW-LEVEL RADI0 ACTIVE WASTE - 10 CFR SECTION 20.302 The purpose of this infomation notice was to call i

I attention to a little-used section of NRC regulations that provides a method for obtaining approval of proposed procedures for disposing of licensed material and any other radioactive material involved, in a manner not otherwise authorized in the reg-ul ations. This section of the regulations may be used to obtain approval of proposed proc.dures for disposal of, among other things, large volumes of material contaminated at very low levels, such as contaminated soil, oil, or tools and equipment. The notice was sent to all production and utilization facilities, including nuclear power reactors and research and test reactors, holding an operating license.

' In formation Date Notice Issued Subject 83-06 2/24/83 NONIDENTICAL REPLACEMENT PARTS This information notice provided notification of continuing problems with replacement parts which differ sufficiently from the parts they replace to cause improper operation of the components. The following possibly defective components were discussed: Westinghouse Type W-2 control switches; ASCO solenoid-operated air pilot valves; Robertshaw control valves; and Power Conversing Products, Inc.

(PCP) battery chargers. The notice was sent to all licensees and construction permit holders.

t

_ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _. _ _ _ _ _ 2.3 Engineering Evaluations and Case Studies Issued in January -

February 1983*

The Office for Analysis and Evaluation of Operational Data ( AE00) has as a primary 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 engineering evaluation or a case study. An engineering evaluation is usually an immediate, general consideration to assess whether or not a more detailed, protracted case study is needed. The results are generally shori, 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 fonnal 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.

These AE0D 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 concerr ing the operational event (s) discussed, and do not represent the position or requirements of the responsible NRC program office.

Engineering Date Evaluation Issued Subject E301 1/19/83 FUEL DEGRADA; ION AT WESTINGHOUSE PLANTS On 1/h/83, the Westinghouse fuel inspection team discovered degradation of fuel cladding at Salem Unit 1.

Two complete ruptures wre visable on one pin of a fuel assembly and the fuel pellets were exposed. The cause of the ruptures was diagnosed as excessive rod growth due to pellet clad material interaction /ratcheting and neutron elongation. On 4/26/82, at Trojan, 17 assemblies were found with degraded fuel cladding. Portions of rodlets were missing and loose fuel pellets were found. This damage was caused by water-jetting induced vibration of the fuel pins adjacent to baffle plate joint 1ocations with enlarged gaps. The purpose of this engineering evaluation was to describe these instances of fuel degradation at Westinghouse p1 ants.

(For an f

additional detailed description of the Trojan event, see Power Reactor Events, Vol. 4, No. 3, pp. 1-2.)

No case studies were issued during January-February 1983.

l Engineering Date Evaluation Issued Subject E302 1/31/83 POTENTIAL LOSS OF SERVICE WATER FLOW RESULTING FROM A LOSS OF INSTRUMENT AIR A potential service water system (SWS) problem was discovered at Palisades on 8/19/82, as a result of a review conducted as part of the Systematic Evaluation Program (SEP).

It was postulated that a potential problem could occur following a loss of coolant accident (LOCA) with simultaneous loss of offsite power and the failure of a diesel generator. The consequence of the assmed failures is the total loss of service water which provides the communication path for the post accident heat loads to the ultimate heat sink.

This postulated problem was easily corrected by installing hard stops on the operators of the service water flow control valves located at the discharge of the component cooling water heat exchangers.

Considering the Palisades system design, there appears to be no cause for generic concern regarding the loss of service water resulting from a loss of instrument air.

E303 2/16/83 YALVE FLOODING EVENT AT SURRY On 11/28/81, a routine surveillance indicated that the service water valve pit was flooded.

The valves were subsequently declared inoper-able due to a grounded valve motor. The concern was that, should these valves be inoperable, and not closed when necessary there would not be suf-ficient water available to bring the reactor to cold shutdown following a LOCA concurrent with a total loss of offsite power.

Analysis showed that water is available for at least 13.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> before makeup to the intake canal is necessary, and that the valves may be closed manually if they are not operable electrically.

In the case of a steam generator tube rupture where one must be able to go to cold shutdown to end the event, the reactor coolant system main loop isolation valves may be used to isolate the leaking steam generator. Licensee corrective actions have included installation of dikes and lights, and upgrading of maintenance procedures to ensure that the valve pits do not flood in t5e future.

_ _ _ _ _ _ _ _ _ _ 2.4 Generic Letters Issued in January-February 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 infomation to, and obtain infomation from, reactor licensees, applicants, and/or equipment suppliers regarding matters of safety, safeguards, or environ-mental significance. During January and February 1983, 11 letters were issued.*

Generic letters usually either (1) provide infomation thought to be important in assuring continued safe operation of facilities, or (2) request information on a specific schedule that would enable regulatory decisions to be made regarding the continued safe operation of facilities. They have been a significant means of communicating with licensees on a number of important issues, the resolutions of which have contributed to improved quality of design and operation.

Generic Date Letter Issued Subject 83-01 1/11/83 OPERATOR LICENSING EXAMINATION SITE VISIT To assist the NRC in developing data for their operator license application review scheduling, manpower and resource allocation planning, and budget preparation through 1985, all reactor licensees and applicants were asked to provide best estimates on all requests for site visits during which certain operator licensing and instructor certification examinations would be given through 12/31/85.

Recipients were asked to respond by 2/28/83.

83-02 1/10/83 NUREG-0737 TECHNICAL SPECIFICATIONS All boiling water reactor licensees were requested to review their facilities' technical specifications to determine consistency with respect to NUREG-0737,

" Clarification of TMI Action P1an Requirements."

This NUREG document lists items for which technical specifications are required and were scheduled for implementation by 12/31/81. Each item is presented in an enclosure to the letter, as well as guidance on the scope of a specification which the NRC staff would find acceptable.

Recipients were asked to respond within 90 days of receipt of the letter.

83-04 2/4/83 REGIONAL WORKSHOPS REGARDING SUPPLEMENT 1 TO NUREG-0737, REQUIREMENTS FOR EMERGENCY RESPONSE CAPABILITY This letter informed all reactor licensees, applicants, and construction permit holders of workshops scheduled in NRC's five regions to answer questions regarding (1) the NRC's policy on requirements for emergency Generic Letter 83-03 has been cancelled; the subject matter contained therein has been covered under No. 83-15, to be abstracted in PRE, Vol. 5 No. 2.

Generic Date Letter Issued Subject response capability as discussed in NUREG-0737,

" Clarification of TMI Action Plan Requirements," and (2) the process to be used by NRC project managers for the implementation of these requirements.

83-05 2/8/83 SAFETY EVALUATION OF " EMERGENCY PROCEDURE GUIDELINES ON REVISION 2, NED0-24934, JUNE 1982 All boiling water reactor licensees (except Lacrosse), applicants for licensees, and construction permit holders were infomed that following their review of NED0-24934 the NRC staff has found the guidelines to be acceptable for implementation, as well as a basis for a significant improvement over current emergency operating procedures. The following implementation of the guidelines was suggested:

(1) preparation of plant-specific procedures which confom as outlined in Supplement 1 to NUREG-0737 (transmitted by Generic Letter 82-33, 12/17/82); and (2) preparation of supplements to these guidelines based on changes, new equipment, or new knowledge and the resulting modifications to, plant-specific procedures.

An NRC safety evaluation report identifying several steps in the guidelines which reqire minor changes is also enclosed.

83-06 1/31/83 CERTIFICATES AND REVISED FORMAT FOR REACTOR OPERATOR AND SENIOR REACTOR OPERATOR LICENSES All reactor licensees and applicants, nuclear steao system vendors, reactor vendors, and architect-engineers were provided a sample certificate and issuing letter to reactor operators (R0s) and senior reactor operators (SR0s). At the time of original licensing or license renewal, a standard letter constituting a person's authorintion to perfom R0 or SR0 duties will be sent to licensed individuals as well as plant management.

83-07 2/16/83 THE NUCLEAR WASTE POLICY ACT OF 1982 All power and non-power reactor licensees, applicants, and construction permit holders were provided a copy of Section 302(b) of the above Act that requires licensed owners or generators of spent fuel or high-level waste to have a contract with the Secretary of Energy by 6/30/83 for the disposal of such waste.

Recipients having questions regarding the contracts were requested to contact Mr. R. M. Roselli of the Department of Energy at 301/353-4808.

.. Generic Date Letter Issued Subject 83-08 2/2/83 MODIFICATION OF VACUUM BREAKERS ON MARK I CONTAINMENTS During the latter stages of the generic resolution of the Mark I Containment Long-Term Program suppression pool dynamic load definition, a potential failure mode of the vacuta breakers in the chugging and condensa-tion oscillation phases of blowdown to the torus during a loss-of-coolant accident was identified.

At the. time this was discovered, the generic phase of the program was nearing completion, but the Mark I Owners Group committed to resolve the issue.

The NRC was infomed in September 1982 that this effort had been completed. The licensees of several plants listed in an attachnent to the letter were requested to provide, within 90 days of receipt of-the letter, a commitment to submit results of the plant-unique calculations which either forward the bases for modifications to the vacuum breakers or provide justification for their as-built accept-abil ity.

83-09 2/3/83 REVIEW 0F COMBUSTION ENGINEERING OWNERS' GROUP EMERGENCY PRSCEDURES GUIDELINE PROGRAM This letter infonned all reactor licensees, applicants, and construction permit holders for Coinbustion Engineering (CE) pressurized water reactors of NRC's preliminary acceptance of the CE Owners' Group Emergency Procedure Guidelines for implementation in plant-specific emergency procedures, and outlined NRC's requirements for additional work in this area.

The NRC suggests the implementation program contain:

(1) preparation of plant-specific procedures based on the guidelines referenced above, and implementation of the procedures as outlined in Supplement 1 to NUREG-0737, transmitted by Generic Letter 82-33 (12/17/82); (2) a program for supplements to the guidelines, or plant-specific guidelines which cover changes, and incorporation of these into the procedures; and (3) completion of and improve-ment to the guidelines as plant-specific procedures in the longer term.

In addition, a letter to the CE Owner's Group to provide a description of the program for steps (2) and (3) was attached to this letter.

l j Generic Date Letter Issued Subject 83-10A 2/8/83 RESOLUTION OF TMI ACTION ITEM II.K.3.5, " AUTOMATIC through 10f TRIP 0F REACTOR COOLANT PUMPS" This letter informed all licensees with Combustion Engineering (CE)-designed nuclear steam supply systems that the NRC has completed their evaluation of the CE Owners' Group analyses of LOFT (loss of fluid test) L3-6, and has approved the CE evaluation model for small break loss-of-coolant accidents under certain conditions.

In addition, require-ments for resolving TMI Action Item II.K.3.5,

" Automatic Trip of Reactor Coolant Pumps," were included in the letters 10a through 10f. These requirements superseded actions required under IE Bulletins79-05C and 79-06C.

83-11 2/8/83 LICENSEE QUALIFICATIONS FOR PERFORMING SAFETY ANALYSES IN SUPPORT OF LICENSING ACTIONS Since the NRC's experience with safety analyses using large, complex thermal-hydraulic computer codes such as RELAP and TRAC has shown that a large percentage of errors discovered in safety analyses can be traced to the user rather than to the code itself, all reactor licensees were informed that each licensee or vendor who intends to use a safety analysis computer code to support licensing actions should demonstrate their proficiency in using the code by submitting code verification performed by them, not others.

Recipients were requested to factor this verification into further licensing submittal pl ans.

83-12 2/24/83 ISSUANCE OF NRC FORM 398 - PERSONAL QUALIFICATIONS STATEMENT - LICENSEE All power and nonpower reactor licensees, applicants construction permit holders, and NSSS vendors were supplied a copy and description of the new NRC Form 398, to be submitted by all applicants for operator and senior operator licenses under 10 CFR 55 and applicants for instructor certificates. Recipients were asked to complete the form, in triplicate, and return to the NRC within 30 days of the date of this letter.

_________ - _____ _ _ - _ - _ _ _ _ _ _ _ _. _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 2.5 Operating Reactor Event Memoranda Issued in January February 1983 The Director, Division of Licensing, Office of Nuclear Reactor Regulation (NRR),

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

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

Copies of ORLi4s are also sent to the Offices for Analysis and Evaluation of Operational Data, and of Inspection and Enforcement for their information.

No OREMs were issued during January-February 1983.

l i 2.6 Regulatory and Technical Repcrts Issued in January-February 1983 1he abstracts listed below have been selected from the Office of Administration'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 tvaildle from the NRC/GP0 Sales'PNgram, PHIL-016, Washington, DC 20555 or on (301) 492-9530.

Report Title NUREG-0304 REGULATORY AND TECHNICAL REPORTS - COMPILATION FOR 1982 Vol. 7, No. 4 February 1983 This compilation lists all NRC regulatory and technical reports published under the NUREG series during 1982.

NUREG-0525 SAFEGUARDS

SUMMARY

EVENT LIST (SSEL)

R06 February 1983 The Safeguards Summary Event List (SSEL) provides brief summaries of several hundred safeguards-related events involving nuclear material or facilities regulated by the NRC.

Events are described under the categories of bomb-related, intrusion, missing / allegedly stolen, transportation, vandalism, arson, firearms-related, radiological sabotage and miscellaneous. The information contained in the event descriptions is derived primarily from official NRC reporting channels.

NUREG-0845 AGENCY PROCEDURES FOR THE NRC INCIDENT RESPONSE PLAN February 1983 The NRC Incident Response Plan, NUREG-0728/MC 0502, describes the functions of the NRC during an incident and the kinds of actions that comprise an NRC response. The NRC response plan will be activated in accordance with threshold criteria described in the plan for incidents occurring at nuclear reactors, fuel facilities and materials licensees, during transportation of licensed material, and for threats against facilities or licensed material.

In contrast to the general overview provided by the Plan, the purpose of these agency procedures is to delineate:

?

\\

(1) the manner in which each planned response function gs

.i is performed; (2) the criteria for making those response decisions which can be preplanned; (3) the information and other resources needed during a response.

An inexperienced but qualified person should be able to perform functions assigned by the Plan and make necessary decisions, given the specified information, by becoming familiar with these procedures. This rule of thumb has been used to determine the amount of detail in which the agency procedures are described. These procedures form a

_ _ _ _ _ _ Report Title foundation for the training of response personnel both in their normal working environment and during planned emergency exercises. These procedures also form a ready reference or reminder checklist for technical team members and managers during a response.

NUREG-0885 U.S. NUCLEAR REGULATORY COMISSION POLICY AND PLANNING 102 GUIDANCE 1983 January 1983 The purpose of the Policy and Planning Guidance is to provide a comon basis for establishing priorities throughout the NRC. The guidance should also be used for developing budget requirements. The goal of the document is to make the whole regulatory process more effective and more efficient. The document is organized in terms of seven major themes: Safe Operation of Licensed Plants; Near-Term Licensing Problems and Responses; Coordinating Regulatory Requirements; Improving the Licensing Process; Supporting Ncw Initiatives in Waste Management and the Cleanup of Three Mile Island; Improving Related Regulatory Tools; and Safeguards. The policy section in each theme is intended to establish a general framework for shaping NRC plans and programs. Planning guidance is furnished in those areas where the Commission believes more detail is warranted to meet specific priorities and schedules, or where major assumptions are needed for program development. Guidance with respect to each and every activity within NRC is not furnished, since it is not intended that the document be all-inclusive.

However, this should not be perceived as a Commission belief that other areas are not important to protecting the public health and safety.

NUREG-0940 ENFORCEMENT ACL ;NS: SIGNIFICANT ACTIONS RESOLVED / Quarterly Vol. 1, No. 4 Progress Report: October-December 1982 January 1983 This mompilation summarizes significant enforcement actions that have been resolved during one quarterly period (October-December 1982) and includes copies of letters, notices, and orders sent by the NRC to licensees with respect to enforcement actions.

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.

This publication is issued on a quarterly basis to include s

significant coforcement actions resolved during the preceding

(

quarter.

NUREG-0943 THREADED FASTENER EXPERIENCE IN NUCLEAR POWER PLANTS January 1983 This report identifies 44 incidents of threaded-fastener degradation and failure in nuclear power plants from

4 l

>i, "

Report Title October 1964 to March 1982.

It provides an overview of some of the threaded-fastener problems that have occurred since 1964. Safety implications of there incidents are discussed, and short-term regulatory actions and ongoing long-term regulatory actions are described.

Information included in this reportfrepresents the current NRC staff understanding of each issue.

NUREG/CP-002/

PROCEEDINGS OF THE INTERNATIONAL MEETIl4G ON THERl1AL NUCLEAR Vols. 1-3 REACTOR SAFETY February 1983 The Proceedings of the International Meeting on Thermal Nuclear Reactor Safety, held at Chicago, Illinois, August 29-September 2, 1982, contain the entire collection of papers submitted for presentation at the meeting, as s. ell as two special addresses, and four summarizing review articles.

The papers deal with a wide spectrum of subjects pertaining to the area of thermal nuclear reactor safety, including:

licensing criteria, safety goals, probabilistic risk assessment, reliability analysis, safety-related operational experience, man / machine interface, human factors, transient analysis, loss-of-c.colant analysis, structural analysis, fuel performance evaluatioi:, severe accident analysis, radiological source term evaluation, pressurized thermal y

shock.

In addition to papers on the above technical subjects, the Proceedings contain a number of papers describing safety-related programs in a number of countries, including Agrentina, Brazil, Canada, Fed. Rep. of Germany, Finland, France, Greece, Italy, Japan, Mexico, Spain, Sweden, and United Kingdom. The meeting was jointly sponsored by the American Nuclear Society, the Europecn Nuclear Society, the Canadian Nuclear Society, and the Japan Atomic Energy Society, and was organized and conducted in cooperation with the NRC and the International Atomic Energy Agency.

NUREG/CR-1894 MECHANICAL RELIABILITY EVALUATION OF A PROPOSED EMERGENCY February 1983 RESPONSE RADI0 IODINE AIR SAMPLER The purpose of this study was to evaluate the mechanical reliability of the air sampler component of the prototype system. Three air samplers previously used at Three Mile Island subsequent to the accident of March 1979 were tested.

During the tests, the repeatability and uaiformity or the air sampler flowrates were monitored to determine the effects i

of the temperature, relative humidity, rainfall, dusty air, 1

vibration, and mechanical shock. Although all three air samplers eventually failed due to scoring and seizure of the motor shafts and/or bearings, prior to failure the three samplers exhibited uniform and reproducible flowrates at all test conditions except one. The three air samplers would not

42 -

Report Title operate reliably on direct current voltage at or below 00F.

Based on the number of hcurs of operation in this study only, the minimum average lifetime of the three air sampler motors was determined as 44.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

In conjunction with the air sampler study, three additional type motors were investigated briefly:

a dual voltage motor similar to the original air sampler motcrs ard two single voltage motors.

NUREG/CR-2000 LICENSEE EVENT REPORT (LER) COMPILATION Vol. 1, No. 12 January 1983; This monthly report contains Licensee Event Report (LER)

Vol. 2, No. 2 operational information that was processed into the LER data February 1983 file of the Nuclear Operaticns Analysis Center (NOAC) during the one-month period identified on the cover of this document.

(Vol. 1, No. 2 covers the December 1982 period and Vol. 2, No. 1 covers the January 1983 period.) The LERs from which this information is derived are submitted to the NRC.by nuclear power plant licensees in accordance with NRC require-ments. Procedures for LER reporting are described in detail in NRC Regulatory Guide 1.16 and NUREG-0161, Instructions for Pre)aration of Data Entry Sheets for Licensee Event Reports.

The _ER summaries in this report are arranged alphabetically by facility name, and then chronologically by event date for each facility. Component, system, and keyword indexes follow the summaries. The components and systems are those identified by the utility when the LER c

form is initiated; the keywords are assigned by the NOAC staff when the summaries are prepared for computer entry.

NUREG/CR-2098 COMMON CAUSE FAULT RATES FOR PUMPS February 1993 This report presents estimates of common cause fault rates and related quantities, based on Licensee Event Reports (LERs) for pumps in nuclear reactors. The LER data base is described.

For estimating ratet. the binomial failure rate model is used, extended to allow for the substantial observed plant-to-plant variability, and for shocks that by their nature make all the pumps in a system inoperable. Every quantity is estimated by both a point estimate and a 90% interval.

All rates are expressed per hour.

NUREG/CR-2300 PRA PROCEDURES GUIDE /A GUIDE TO THE PERFORMANCE OF Vols. 1 and 2 PROBABILISTIC RISK ASSESSMENT FOR NUCLEAR.3WER PLANTS January 1983 This procedures guide describes methods for performing probabilistic risk assessments (PRAs) for nuclear power plants at three levels of scope:

(1) systems analysis; (2) systems and containment analysis; and (3) systems, containment, and consequence analysis. After reviewing its objectives and limitations, this document describes the organization and management of a PRA project and then

l l Report Title presents procedures for accident-sequence definition and systems modeling, human-reliability analysis, the develop-ment of a data base, and the quantification of accident sequences.

Procedures for evaluating the physical processes of core meltdown are presented next, followed by guidance on the evoiuation of radionuclide releases from the contain-ment as well as the analysis of environmental transport and offsite consequences. The analysis of external hazards is discussed next, including procedures for seismic, fire, and flood analyses. The guide concludes with suggestions for the development and interpretation of results and the performance of uncertainty analyses.

NUREG/CR-2770 COMMON CAUSE FAULT RATES FOR VALVES February 1983 This report presents estimates of common cause fault rates and related quantities, based on Licensee Event Reports (LERs) for valves in nuclear reactors.

The LER data base is described. Fo estimating rates, the binomial failure rate model is used, extended to allow for the substantial observed plant-to-plant variability, and for shocks that by their nature make all the valves in a system inoperable.

Every quantity is estimated by both a point estimate and a 90% interval.

NUREG/CR-2771 COMMON CAUSE FAULT RATES FOR INSTRUMENTATION AND CONTROL February 1983 ASSEMBLIES This report presents estimates of common cause fault rates and related quantities, based on Licensee Event Reports (LERs) of instrumentation and control assemblies in nuclear reactors.

The LER data base is briefly described and imperfections in the data are discussed. The components are grouped into assemblies for which rates are estimated.

For estimating rates, the binomial failure rate model is used, extended to allow for the sJbstantial observed plant-to-plant variability and for shocks that by their nature cause all the assemblies in a system to fail.

Every quantity is estimated by both a point estimate and a 90% interval.

All rates are expressed per calendar hour.

NUREG/CR-28/8 DETECTION OF SMALL-SIZED NEAR-5URFACE UNDER-CLAD CRACKS February 1983 FOR REACTOR PRESSURE VESSELS To provide confidence in the integrity of a reactor during an overcooling transient, it is necessary for nondestructive evaluation tc, demonstrate high probabilities of detecting cracks located 6.0 mn deep and deeper at the pressure vessel clad surface. The cracks of interest may be parallel or

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Report Title perpendicular to the clad lay.

Ultrasonic techniques developed ar.1 used in Europe are evaluated in this paper for their use on U.S. reactor pressure vessels.

Flaw detectability experiments were carried out by testing the inspection technique's ability to detect artificial flaws under several types of clad, including some flanual Metal Arc (MMA) clad.

Both ground and unground clad surfaces 3

were evaluated. Crack sizing tests of the inspection technique were made using a crack tip diffraction technique.

The data reported here indicate that for sufficiently smooth clad surfaces, the 700 compressional wave technique is extremely effective for detecting under-clad cracks.

In addition, results show that dramatic signal-to-noise improvements can be made by grinding the clad surface.

Specifically, a reduction in noise level of 10 to 12 dB was achieved by improving the surface condition by a factor of two from 0.012 in RMS to 0.006 in RMS. This reduction in noise moves the crack detectability confidence level from low to very high.

fiUREG/CR-2886 THE IN-PLANT RELIABILITY DATA BASE FOR fiUCLEAR PLAf4T January 1983 COMP 0NEf1TS:

INTERIM DATA REPORT - THE PUMP COMPONENT The objective of the In-Plant Reliability Data (IPRD) pilot program is to develop a comprehensive, component-specific data base for probabilistic risk assessment and for other statistical analyses relevant to component reliability evaluations.

This objective was attained through a cooperative effort with several utilities, wherein each utility provided access to the maintenance files and pertinent population information, and in return, received a computerized listing of both the component populations and the component maintenance records. This data base includes (1) a comprehensive component population list for each plant including electromechanical and mechanical equipment, i.e., pumps, valves, diesel generators, inverters, and batteries, and (2) a comprehensive component failure and repair history including all corrective maintenance action on each component.

This document details the data collection and analysis related to pumps in nuclear power generating stations. The data base is developed primarily from a comprehensive record of corrective maintenance actions obtained directly from nuclear plant maintenance files. A comprehensive pump population is also included in the data base. This report represents data and reliability statistics on PWR and BWR power plants.

NUREG/CR-?891 PERFORMANCE TESTING 0F PERSONNEL 00SIMETRY SERVICES: Final February 1983 Report of Test 3 In September 1977, the University of Michigan began a pilot study of the Health Physics Society Standards

.... Report Title Committee (HPSSC) Standard entitled, " Criteria for Testing Personnel Dosimetry Performance." Approximately 70 dosimetry processors volunteered to participate in one or more of three tests of the HPSSC Standard. The results from Tests #1 and #2 were used to evaluate and revise the Standard which was then adopted by the HPSSC in June 1981.

The Stardard was also adopted by the American National Standards Institute as ANSI i413.11-1982 in June 1982.

Test #3 of the revised HPSSC Standard was conducted from November 1981 to April 1982. The objectives of Test #3 were to determine if the Standard is acceptable for future testing programs and to provide experience with the final version of the Standard.

The passing rate among all the processors for Test #3 was 75% compared to passing rates of 48% and 62% for Tests

1. 1 and #2, respectively, with adjustments made for changes in the Standard following Test #2. Among all the individual dosimeters irradiated during Test #3, 89% had a reported dose within plus or minus 50% of the delivered dose compared to 79% and 85% of the dosimeters irradiated for Tests #1 and #2.

The HPSSC Standard was found to be an acceptable measure of minimum performance and an appropriate basis for a regulatory program to accredit dosimetry processors.

NUREG/CR-2892 PERFORMANCE TESTING OF PERSONNEL DOSIMETRY SERVICES: A February 1983 Revised Procedures Manual The U.S. Nuclear Regulatory Commission's pilot study of the Health Physics Society Standards Connittee Standard,

" Criteria for Testing Personnel Dosimetry Performance,"

was begun in 1977. A third test of this Standard was conducted from November 1981 through April 1982.

The objective of this Procedures Manual is to describe the procedures used for Test #3 which reflect the changes in the Standard from Tests #1 and #2. This Manual describes each of the radiation sources used for Test #3, as well as administrative procedures used during the testing program.

Methods of irradiation, quality control, data analysis, record keeping, and handling large numbers of dosimeters are presented. This Manual discusses the role of the National Bureau of Standards in verifying the validity of the calibration of each radiation source.

Suggestions for improving irradiation procedures are included as well as recommendations that will facilitate the operation of the permanent testing facility.

, Report Title NUREG/CR-2952 ENGINEERING EXPERTISE ON SHIFT IN NUCLEAR POWER PLANTS:

February 1983 THE FOREIGN EXPERIENCE This report describes the practices of selected foreign countries in providing enginaaring expertise on shift in nuclear power plants. The extent to which engineering expertise is made available and the alternative models of providing such expertise are presented. The implications of foreign practices for U.S. consideration of alternatives are discussed, with reference to the shift technical advisor (STA) position and to a proposed shift engineer position. The procedure used to obtain information on foreign practices was primarily a review of the literature, including publications, presentations, and government and utility reports. There are two approaches that are in use to make engineering expertise available on shift:

(1) employing a graduate engineer in line management for the position, and'(2) creating a specific engineering position for the purpose of providing expertise to the operations staff. The comparisons of these two models did not indicate that one system inherently functions more effectively than the other. However, the alternative models are likely to affect crew relationships and performance, labor supply, recruitment, and retention, and system implementation problems.

NUREG/CR-2993 EXAMINATION OF FAILED STUDS FROM NO. 2 STEAM GENERATOR February 1983 AT THE MAINE YANKEE NUCLEAR POWER STATION Three studs removed from service on the primary manway cover from steam generator #2 of the Maine Yankee station were sent to Brookhaven National Laboratory for examination.

The examination consisted of visual / dye penetrant examination, optical metallography and Scanning Electron Microscopy /

Energy Dispersive Spectroscopy evaluation. One bolt was "through cracked" and its fracture face was generally transgranular in nature with numerous secondary inter-granular cracks. The report concludes that the environ-mentally assisted cracking of the stud was due to the inter-action of the various lubricants used with steam leaks associated with this manway cover.

NUREG/CR-3008 AUDITORY PE'KCCPTION IN LOOSE-PARTS MONITORING January 1983 This survey assessed the safety information potentially available to operators in the audio outpat of loose-parts monitors for nuclear power reactors. Three tasks WCro completed:

(1) literature was reviewed to identify acoustic signal parameters of primary interest and to relate these physical parameters to known human auditory detection and recognition capabilities; (2) current use of auditory

l

! Report Title information and product descriptions were examined during visits to a limited number of manufacturers and nuclear power plants, and (3) optimal use of human auditory capabilities in loose-parts monitoring were recommended.

Conclusions were (1) audio surveillance can be enhanced by automatic monitoring supplemented by periodic operator listening for alarms; (2) training procedures could improve human auditory detection; (3) audio information may be used to diagnose location, number and size of detected loose parts - since both practical and theoretical limitations exist for the full automation of this function, human ability to perceive subtle spectral differences may be useful when combined with current automatic diagnosis; and (4) audio data can provide feedback on the response of sonically active remote equipment in limited access areas.

NUREG/CR-3092 CRITERIA FOR SAFETY-RELATED NUCLEAR POWER PLANT OPERATOR February 1983 ACTIONS:

INITIAL SIMULATOR TO FIELD DATA CALIBRATION This report presents preliminary comparisons of field and simulator operator performance data collected in an NRC-funded research program directed by Oak Ridge National Laboratory. The primary objective of the program is to develop an empirical data base on operator performance to support development of criteria and standards for safety-related operator actions. The comparison of simulator and field data is intended to provide a "calibra-tion" of simulator results so that they can be more confidently extrapolated to field conditions.

Collection of PWR/BWR field data was performed by the Memphis State University Center for Nuclear Studies. The collection of PWR/BWR simulator data was performed by General Corporation, using the Electric Power Research Institute's Performance Measurement System. The performance measure used in this study was the time required for operators to initiate the first correct manual action in response to an cbnormal or emergency event. Techniques for data collection as well as the problems and limitations of field data are reported, along with the initial results.

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