ML20149J171

Insp Rept 50-029/87-16 on 871027-880119.Violations Noted. Major Areas Inspected:Operational Safety Verification, Radiological Controls,Events Requiring Telephone Notification to Nrc,Plant Events & Maint Operations

ML20149J171
Person / Time
Site:	Yankee Rowe
Issue date:	02/12/1988
From:	Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20149J099	List: ML20149J096 ML20149J122 ML20149J171
References
50-029-87-16, 50-29-87-16, GL-87-09, GL-87-9, IEB-79-24, IEB-87-002, IEB-87-2, NUDOCS 8802220291
Download: ML20149J171 (31)

See also: IR 05000029/1987016

Text

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No.: 50-29/87-16

Docket No.: 50-29

Licensee No.: DPR-3

Licensee: Yankee Atomic Electric Company

1671 Worcester Road

Framingham, Massachusetts 01701

Facility Name: Yankee Nuclear Power Station

Inspection at: Rowe, Massachusetts  !

Inspection Conducted: October 27, 1987 - January 19, 1988 [

Inspectors: Harold Eichenholz, Senior Resident Inspector

Cynthia A. Carpenter, esident Inspector

Approved By: // k m

Donald R. Haverkamp, Chief

m ~[ 2//a/Jr

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Reactor Projects Section No. 3C v  !

Inspection Summary 1 Inspection on October 27, 1987 - January 19, 1987

(Report No. 50-29/87-16)

Areas Inspected: Routine onsite regular and backshift inspection by two

resident inspectors (250 hours0.00289 days <br />0.0694 hours <br />4.133598e-4 weeks <br />9.5125e-5 months <br />). Areas inspected included operational safety ,

verification, radiological controls, events requiring telephone notification to ,

the NRC, plant events, maintenance observations, surveillance observations,

emergency preparedness, organization and administration changes, licensee event  :

reports, cold weather preparations, Nuclear Safety Audit and Review Committee

activities, on site review committee activities, and licensee response to NRC

Bulletins.

Results; One violation was found involving the failure to meet the require-

ments of 10 CFR 50.72(b)(1)(A), in that the NRC was not notified within one

hour of the initiation of plant shutdown as required by Technical Specification (TS) 3.0.3. Areas needing increased licensee attention include the need to:

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(1) strengthen administrative controls to assure timely performance and docu- ,

mentation of post-maintenance testing activities; (2) re-evaluate the emergency  ;

action levels as an event evolves, and (3) review reliability and reportability r

concerns involving the nuclear alert system (Section 9). Fire protection and  !

housekeeping and maintaining control room annunciators in a black-board status c

(Section 3) and a conservative approach to declaring an Unusual Event and man-

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ning the emergency response facilities (Section 9) were considered notable

strengths. A positive trend continues to be observed in improving the perform- i

ance of the Security Program (Section 3).

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TABLE OF CONTENTS

Page

1. Persons Contacted........................................... 1

2. Summa ry of Facili ty and NRC Acti vi tie s. . . . . . . . . . . . . . . . . . . . . . 1

3. Operational Safety Verification............................. 2

a. Daily Inspection....................................... 2

b. System Alignment Inspection............................ 5

c. Biweekly and Other Inspections. . . . . . . . . . . . . . . . . . . . . . . . . 5

d. Backshift Inspection................................... 8

4. Radiological Controls....................................... 8

5. Events Requiring Telephone Notification to the NRC. . . . . . . ... 9

6. Plant Events................................................ 10

a. Plant Shutdown Oue to No. 2 Non-Return Valve Low

Nitrogen Pressure.................................... 10

b. Inoperable Main Steam Line Low Pressure Switches....... 12

7. Maintenance Observations.................................... 12

8. Surveillance Qbservations................................... 14

9. Emergency Preparedness...................................... 18

a. Noti fication o f Unusual Event. . . . . . . . . . . . . . . . . . . . . . . . . . 18

b. Initiation of Plant Shutdown Required by Technical

Specifications....................................... 19

c. Nuclear Alert System Operability....................... 23

10. Organization and Administration Changes..................... 24

11. Licensee Event Reports...................................... 25

12. Cold Weather Preparations................................... 26

13. Nuclear Safety Audit and Review Committee Activities........ 27

14. On-Site Review Committee Activities......................... 28

15. Licensee Response to NRC Bulletins............. ............ 28

16. Management Meetings...................... .................. 29

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DETAILS

1. Persons Contacted

Yankee Nuclear Power Station

B.- Orawbridge,= Assistant Plant Superintendent

T. Henderson, Technical Direttor

N. St. Laurent, Plant Superintendent

Yankee Atomic Electric Company

R. Berry, 'echnical Assistant to Vice President and Manager of Operations

G. Papanic, Licensing Engineer

W. Riethle, Manager Radiation Protection Group

E. Wojnas, Senior Emergency Planning Engineer

The inspector also interviewed other licensee employees during the inspec-

tion, including members of the operations, radiation protection, chem-

istry, instrument and controi, maintenance, reactor engineering, security,

training, technical services and general office staffs.

2. Summary of Facility and NRC Activities

At the completion of the last resident inspection period on

October 26, 1987, the plant was at 100% of rated power. Plant conditions

remained stable until November 21, 1987, when the licensee commenced an

unplanned load reduction to Mode 2 (startup) from full power operation.

The load reduction was prompted by a low nitrogen pressure alarm on the

No. 2 non-return valve (NRV). The plant remained at 2% of rated power

until repair to the NRV was completed the next day; the plant then re-

turned to full power. An unusual event was declared to comply with plant

emergency action level criteria. The plant remained at full power until

December 3,1987, when the licensee determined that the No. 3 low steam

line pressure switch was inoperable. The inoperable channel was not

placed in the tripped condition within the one-hour time frame required by

the Technical Specifications and the licensee commenced a plant load re-

duction. At 98% of rated power, the channel was placed in the tripped

condition and the licensee returned the plant to full power. The plant

remained at full power until January 15, 1988, when the licensee commenced

a planned load reduction to approximately 65% of rated power to perform

re packing of the Na. I heater drain pump and other miscellaneous main-

tenance. The plent returned to normal full power operations on

January 17, 1988. On January 19, 1988, the licensee commenced a plant

shutdown to approximately 75% of rated power to perform maintenance on the

No. 1 boiler feed pump (BFP) outboard motor bearing due to an oil leak.

The plant remained at 75% of rated power for the remainder of the

inspection period pending repair to the BFp.

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An NRC Region I operationally oriented team inspection was conducted dur-

ing the period of January 10-15, 1988, to review activities in the area of

operations, maintenance, surveillance, modifications and engineering

support.

On November 8,1987 Mrs. C. Carpenter was assigned as Resident Inspector

at Yankee Nuclear Power Station. During the ;,eriod of November 12-26, 1987,

the Senior Resident Inspector participated in the NRC's initial event

response and an Augmented Inspection Team for the loss of offsite power

event that occurred on November 12, 1987, at the Pilgrim Nuclear Power

Station. On December 2-3, 1987, the Resident Inspectors participated in

the NRC Region I observation of the unannounced full participation emerg-

ency exercise conducted for the Vermont Yankee Nuclear Power Station.

3. Operational Safety Verification

a. Daily Inspection

During routine facility tours, the inspector checked the following

items: shif t manning, access control, adherence to procedures and

limiting conditions for operations (LCOs), instrumentation, recorder

traces, protective systems, control rod positions, containment tem-

perature and pressure, control room annunciators, radiation monitors,

radiation monitoring, emergency power source operability, control

room and shif t supervisor log, tagout log, backshif t inspection and

operating orders. Based upon a review of licensee activities in this

area, the inspector noted the following:

(1) On December 28, 1937, the inspector observed that the No. 3

control rod primary position indicator channel was inoperable,

in that the control rod position, as indicated on the primary

and secondary indicator channels could not be determined within

3 inches of each other as required by TS 3.1.3.2. Only one-

third of the 90 light emitting diode (LED) displays for this rod

were brightly illuminated, with one third dark and the remaining

one-third faintly illuminated. The control room operators first

observed this condition at 8:45 p.m. on December 21, 1987. Fol-

lowing unsuccessful maintenance activity in the vapor container,

the primary position indicator channel for the No. 3 control rod

was declared inopterable. The shif t turnover and control room

log documented that the plant operators recognized the applicable

TSs. The inspector verified that TS 3.1.3.2, Action Statement

a.1, was performed by the licensee until January 6,1988, which

was when the licensee declared the indication channel operable

after interim repair was completed. The action statement

required the licensee to determine the position of the non-

indicating rod indirectly by the movable incore detectors at

least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,

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(2) On November 5 and 6, 1987, the operations department issued

special orders87-116 and 117 respectively, that described two

recent events at operating plants that involved failure of those t

licensees to preclude unlicensed personnel from manipulating

controls at their plants. The special orders re-emphasized the  !

license #'s policy that only licensed operators or persons t

enrolleJ in a license training program are allowed under direct -

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supervision of licensed operators to operate the reactor con- ,

trols or other equipment that could affect reactor reactivity.

(3) During a tour of the control room, on January 6, 1988, the

inspector observed that the low pressure surge tank (LPST)

level indicator had a "Not Operating" sticker affixed to it. -

The inspector reviewed the status ' of the LPST level instrumen

tation and determined that it was declared inoperable on  ;

December 31, 1987. This instrument is used by the control room

operators to record on an hourly basis, in Rowe _ Station Log

Sheet No. 2. , the level in the LPST. The inspector questioned -

the primary side control room operator on the mechanism they

were using to log the level indication. According to the oper- .'

ator, an auxiliary operator takes a reading from a local level

indicator and calls this information into - the control room.

However this is accomplished on a two-hour interval. The hourly

values missed were filled in by the control room inspector who

assumed that conditions have not changed from the most recent  ;

data.

Inspector concerns in this area involved 1) the manner in which

operators were recording values for which no data were avail-  !

able; 2) the log sheet was not being annotated in the remarks l

sections that local readings were being utilized; and 3) Rowe

Station Log Sheet No. 2, which is controlled by procedure

Ap-2007, Rev. 22, Maintenance of Operations Departmental Logs,  ;

requires hourly readings, but no procedural change was initiated i

to cover shift personnel determinations that twice per hour

readings would be acceptable. There appears to be a point of

confusion with procedure AP-2007, in that, it >pecifies that  !

temporary or permanent safety related logsheet changes will be

handled per procedure AP-0001, Plant Procedures and Instruc-  !

tions, as if it was a procedure change. It would appear that

i this statement on procedure AP-2007 provides a mechanism for

i non-safety logsheet changes to occur without performing the

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procedure change requirements of procedure AP-0001. The inspec-

tor brought the conflicting condition to the attention of the

, technical services manager for resolution.

In response to the inspector's observations and concerns, the  !

l plant operations manager issued a memorandum to all control room ,

l personnel on January 7,1988 that provided reinstruction on the  !

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methods of providing log sheet readings of equipment that is out  :

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of service. In addition, the technical services manager

informed the inspector that he would initiate action that will

revise procedure AP-2007 to be in conformance with. the proced-

ural change requirements of procedure AP-0001. The inspector "

had no further questions on this item.

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(4) Throughout the inspection period, the inspector noted the return

to an excellent level of performance of the licensee in main-

taining he control room annunciators in as close to a "black- -

board" status as possible.

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(5) During a control room tour on January 13, 1988, the inspector

noted a few downscale excursions on the recorder trace for the

No. 4 steam generator blowdown monitor ( RM-PRR-200) . The

inspector questioned a control room operator about this condi-

tion. The operator demonstrated an awareness of the observation

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and was monitoring the situation. Prior to the end of the

shift, maintenance request (MR) 88-90 was issued to initiate

maintenance activity to provide a mechanism to resolve this

item. *

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(6) The inspector noted on January 18, 1988 that the control room

annunciator N-A 35, Main Coolant Hot Leg High Temperature, was

illuminated. The 9:15 a.m. control room log entry attributed

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this condition to a high alarm on the No. 4 hot leg narrew range  ;

! channel. Maintenance request (MR)88-115 was initiated to '

, resolve this high alarm condition on the narrow range channel.

Additionally, control room operators were trending the channel's

output on the safety parameter display system (SPDS). The SPOS

was indicating a value of approximately 562 F. The alarm set-

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point for the annunciator is 558 F, All other main coolant

loops were indicating below the alarm setpoint. Plant operator

response to the alarm condition was in accordance to the alarm

l response Procedure OP-3534. Although the condition appeared to

only be an instrumentation problem, the inspector verified that

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i no core thermal limits were being exceeded. As a result of

I reviewing licensee activity on this item, the inspector noted a i

i weakness in control room operator's knowledge level pertaining '

to the hot leg temperature indication system. Neither the con- ,

trol room log entry nor the MR reflected the fact that the wide

i range instrumentation channel was also involved, since it was i

indicating a high temperature condition. Both the licensee's

operator training manual and procedure OP-6201, Rev. 10, Main

Coolant Hot Leg Narrow Range and Wide Range Temperature Channels

Calibration, indicate that the SPOS input is derived from the ,

wide range channel. However, the inspector noted that the I&C [

personnel involved in the troubleshooting activity were fully

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No violations or deviations were identified in the review of this .

program area, i

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b. System Alignment Inspection

Operating confirmation was made of selected piping system trains.

Accessible valve positions and status were examined. Power supply

and breaker alignments were checked. Visual inspection of major

components were performed. Operability of instruments essential to

system performance was assessed. The following systems were checked

during plant tours and control room panel status observations:

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Low pressure accumulator system.

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Non-return valves

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Charging system (control board status observations)

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Emergency diesel generator units

No violations or deviations were identified in the review of this

program area.

c. Biweekly and Other Inspections

(1) General Facility Observation

During plant tours, the inspector rustn ed shift turnovers,

compared boric acid tank sample ar,'yse' 5 <d tank Ir.vels to

Technical Specification requireneo., . ad rev ewed thre use of

radiation work permits and i a ..icn p o..ction procedures.

Area radiation levels and air m initw uw i operational status

were reviewed. Verification of .put : 4.r.u cated the action was

properly conducted. Based upon . rovim of licensee activities

in this area, the inspector noted , . .ollowing:

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On January 13, 1987 the inspector observed an inadequate

method of restraining a high pressure cylinder located in

the valve room of the upper primary auxiliary building

(PAB). The original wall mounted restraint had deterior-

ated, which resulted in licensee personnel attempting to

compensate for this condition by temporarily tying the

bottle to a rigid support, which subsequently became loose.

Licensee corrective action was initiated to address the

inspector's concern by removing the bottle from the area.

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During a tour of the post accident sampling cubicle in the

pAB on January 13, 1987, the inspector found two one gallon

plastic bottles of demineralized water to be in a frozen

state. This condition appeared to result from the

extremely cold outside temperatures and the location of the

water bottles near the cubicle floor. Smaller bottles of

demineralized water located higher in the cubicle space had

not frozen.

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Licensee procedure DP-9451, Rev. 1, Inventory of Post

Accident Sampling Materials and Equipment, lists these two

bottles as required inventory to successfully conduct post

accident sampling. The inspector brought this condition

to the attention of a chemistry department technician who

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was in the immediate area and requested corrective actions.

The inspector discussed the matter with the chemistry '

' department manager, who acknowledged the inspector's com-

ments and concerns and agreed that actions would be taken

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to preclude recurrence. Subsequently, the inspector

verified that the licensee's actions to preclude recurrence

were appropriate.and successful.

No violations or deviations were identified in the review of t

this program area, i

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(2) Fire Protection and Housekeeping L

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No inadequacies were noted regarding licensee housekeeping  ;

practices. A strong commitment to proper housekeeping '

conditions and practices by the plant staff is routinely

observed by the inspector.

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Throughout the inspection, the licensee has experienced the  ;

loss of fire protection - barriers, detection systems, and i

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firefighting features of the plant. The losses of function i

resulted from both preventive maintenance and unexpected

j- equipment inoperabilities. In all cases, the inspector has

i observed a rapid deployment of compensatory measures by the

operating staff. The licensee's performance in the area of

fire protection and prevention continues to be viewed by

the inspector as a licensee strength. '

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On December 7, 1987, the inspector followed up on an off-

normal shift turnover log entry that involved switchgear

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and battery rooms fire detection system's backup batteries.

The licensee's I&C personnel considered the batteries sus-

pect because of erosion found on the battery terminals dur-  ;

l ing the functional test of the detection system. The

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licensee issued MR 87-1535 to replace the batteries. On i

l November 21, 1987, MR 87-1916 was initiated to correct a '

series of battery trouble alarms on this system. As a

result of these two MRs, the I&C department considered the  ;

batteries to be inoperable, control room personnel were  !

informed and a shift turnover log entry was made. [

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The FSAR Section 229, Fire. Protection and Detection  !

Systems, specifies that to ensure reliability the fire i

detection system is supplied with its own 24-volt de bat- f

tery power in the event of an ac power interruption. As a ,

result of holding discussions with ~ plant operators, the t

inspector was unable to determine what actions would be -l

taken by these operators with regard to system inopera-  !

bility and Technical Specifications requirements.

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The inspector discussed the matter with I&C personnel and ,

the plant's fire protection coordinator. The inspector  ;

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learned that the batteries had successfully passed their t

eight-hour discharge test during the .last functional test i

of the detection system. However, the licensee was treat-  !

ing the matter in a conservative manner by declaring the j

batteries inoperable. Notwithstanding these facts, the l

inspector informed the fire prot 9ction coordinator that is i

was appropriate to provide a written 10 CFR 50.59 review of- i

the current operating configuration and ensure that ,

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instructions are in place that would result in required ,

compensatory actions by the licensed operators in the event

this fire detection' system experiences a loss of ac event. .

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On December 7, 1987, the operations depa<tment issued i

special order 87-126, which prescribed the required opera- l

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tor response should ac power be lost to the switchgear room '

and battery rooms detection system. The inspector verified i

that the stipulated operator response was appropriate and  ;

considered the requirements of TS 3.3.3.4. Additionally,  ;

, the fire protection coordinator issued a 10 CFR 50.59 i

i safety evaluation that provided the basis that operating <

l the system with the hatteries considered inoperable was not

l an unreviewed safety question,

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The inspector noted that a situation involving questionable  !

i battery performance had occurred on a fire detection system

i in September, 1987. At that time the fire protection coor- [

] dinator initiated action that resulted in the issuance of a

special order, which insured proper operator response con-  !

2l sistent with TS requirements would occur in the event there

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was a loss of ac to the detection system.

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(3) Observations of physical Security

Selected aspects of plant security were reviewed during regular

and backshift hours to verify that controls were in accordance

with the recurity plan and approved procedures. Based upon a

review of licensee activities in this area, the inspector noted

the following:

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There appears to be a problem with access control equipment

at the gatehouse, which involves alarm thresholds that are

overly sensitive. In response to the inspector's concerns,

the licensee is evaluating equipment performance and cali-

bration requirements.

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The inspector observed on January 13, 1987 poor attention

to detail by one of the gatehouse officers, as he performed

one of the access control activities required for personnel

entry to the protected area. Corrective measures were

expeditiously implemented following the inspector's iden-

tification of the problem. As a result of routinely re-

viewing security personnel performance in the area of

access control, the inspector concluded that the observa-

tion noted on this date was an isolated incident. The

inspector had no further questions of the licensee on this

matter.

With respect to security equipment maintenance, the licensee's

I&C department has expanded its departmental staffing by one

technician to be responsive to security program needs. The

inspector noted significant improvements in licensee oversight

that generally results in resolution of security system and

equipment malfunctions in a timely manner.

No violations or deviations were identified in the review of this

program area.

d. Backshift Inspection

The inspector conducted backshift, weekend or holiday inspections on

November 14, December 12, January 10, 16, 17 and 18. Operators and

shift supervisors were attentive and responded appropriately to

annunciators and plant conditions. No violations or deviations were

identified in the review of this program area.

4. Radiological Controls

Radiological controls were observed on a routine basis during the repor-

ting period. Standard industry radiological work practices and conform-

ance to radiological control procedure and 10 CFR Part 20 requirements

were observed. Independent surveys of radblogical boundaries and random

surveys of nonradiological areas throughout the facility were taken by the

inspector.

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During a routine tour of the plant, the inspector noted several discrep-

ancies in the licensee's radiological controls practices. In the pump

room (outside a controlled area), the top part of a multistage pump

impeller was noted to be wrapped in yellow polyethylene. In the upper

accumulator room, a crescent wrench was noted to be secured in the area

with a lanyard made of yellow and magenta contamination control ribbon.

Also, an item wrapped in yellow poly was noted in a trash can in the pump

room and a saw horse was noted outside the turbine building with yellow

poly on it. These items were discussed with the radiation protection

manager as an NRC concern; the use of yellow wrapping in an uncontrolled

area and the use of contamination control ribbon on an uncontaminated item

does not illustrate good work practices for a nuclear plant. The radia-

tion protection manager acknowledged the inspector's concerns and has

committed to review the policy of using yellow polyethylene and similar

material in uncontrolled areas. The inspector will follow this item

du.*ing future routine inspections.

No violations or radiation safety conuerns were identified in this program

area.

5. Events Requiring Telephone Notif; cation to the NRC

The circumstances surrounding the following events, which req ~ ired NRC

notification via the dedicated Emergency Notification System (RS) tele- '

phone line were reviewed. A summary of the inspector's review findings

follows or is documented elsewhere as noted below:

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At 9:05 a.m. on November 21, 1987 the NRC was notified in accordance

with 10 CFR 50.72(a)(1)(1) that an Unusual Event had been declared as '

a result of commencing an unplanned shutdown to Mode 2 (Startup) frem

full power operation. The shutdown was prompted by a low nitrogen

pressure alarm on the No. 2 NRV. This matter is discussed further

in Section 6 of this report.

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At 1: 40 p.m. on December 3,1987, the NRC was notified in accordance

with 10 CFR 50.72 (b)(1)(1)(A) of the initiation of plant shutdown as

required by Technical Specifications. Initiation of plant shutdown

was caused by the inability to place the channel No. I main steam

line pressure switch on the No. 3 steam line in the tripped condition

within one hour of declaring the pressure switch inoperable. The

pressure switch was declared inoperable at 10:40 a.m. and the plant

shutdown in accordance with TS 3.0.3 was initiated at 11: 40 a.m.

Although the shutdown was terminated at 11:45 a.m., a 10 CFR 50.72

event requiring notification had occurred, but a timely NRC notifica-

tion was not made. Subsequently, the assistant plant superinten-

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dent's review of the events resulted in a determination that the ENS '

reportable event had occurred. The licensee attributed this notifi-

cation failure to personnel error on the part of the shift supervisor

to make the required determination of reportability. Further dis-

cussion of this event is documented in Section 8 of this report. ,

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In a previous event on May 31, 1987 the licensee failed to make a

timely notification to the NRC in accordance with 50.72(b)(2)(11),

as documented in Inspection Report 50-29/87-06. The failure to make-

the required report, in each case, was determined by the NRC to be a

licensee identiftad violation. The May 31 event also involved

personnel error on the part of the shift supervisor, and corrective

actions were not effective in preventing recurrence as evidenced by

the December 3 repetitive violation.

Therefore, the licensee's failure to make a timely notification of

the required one-hour report on December 3,1987 is considered a

licensee-identified violation for which enforcement discretion is not

being taken (50-29/87-02-01).

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At 4:40 p.m. on January 14, 1988, the NRC was notified in accordance

with 50.72 (b)(1)(v) that the safety parameter display system (SPOS)

would be out-of-service for a period greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This

condition was the result of a hardware problem.

6. Plant Events

a. plant Shutdown Due to No. 2 Non-Retu*n Valve Low Nitrogen pressure

At 6:15 a.m. on November 21, 1987, a low nitrogen pressure alarm for

the main steam system's No. 2 NRV was received, and at 7:10 a.m., the

NRV was declared inoperable. Plant shutdown was initiated at 7:10

a.m. to take the plant offline into Mode 2, close the valve and con-

duct troubleshooting. The licensee declared an Unusual Event es a

result of commencing plant shutdown to Mode 2. With the plant stable

,

at less than 2% of rated power, the NRV was shut and the licensee

l secured from the Unusual Event. The unusual event is discussed

'

further in Section 9 of this report,

, Troubleshooting revealed that after receipt of the low nitrogen

l pressure alarm, the low accumulator pressure switch on the No. 2 NRV

l had subsequently f ailed. The accumulator pressure was found to be

l 1790 psig (charging pressure should have been greater than 2000 psig,

depending on ambient temperature), and the pressure switch was

replaced. The nitrogen accumulator was charged using plant proced-

ures and the NRV opened; the low accumulator pressure alarm did not

i clear as expected. The NRV was closed and the accumulators pressure

l was measured and determined to be 1800 psig. The accumulator was

charged a second time, the sequence repeated, with unsatisfactory

results. The nitrogen accumulator was again charged, but this time

using test equipment instead of the charging instruments, the valve

was re-opened and the low pressure alarm cleared.

!

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l The NRV's are hydraulically opened and nitrogen closed main steam l

l isolation valves in the steam generator discharge lines. The actua- >

tor consists of a hydraulic cylinder with a stored energy system to j

provide emergency closure of the NRV. The energy to operate the  ;

! valve is stored in the form of coreressed nitrogen contained in the

upper head on one end of the actuator cylinder. The lower volume of

the cylinder, on the other side of the piston, is filled with

hydraulic fluid. This serves three purposes - to be throttled ,

j through a control system to control the closing speed, to provide a  ;

method to reopen the valve, and to hold 'the unit in the "stand-by"  !

position. When the actuator extends to close the valve, hydraulic l

fluid flows from the cylinder into the hydraulic control system. A  ;

'

pump is used to reopen the valve.

The nitrogen pressure that is used to close the valves is supplied i

( by the nitrogen stored in the accumulator for each valve. The accum-

ulator is pre-charged with nitrogen with the valve closed and the

'

4

nitrogen pressure is further increased when hydraulic fluid is pumped i

under the operating piston to open the valves. The valves are  !

located in a free standing enclosure immediately outside the vapor i

container. The accumulator is pre-charged, by procedure OP-4259, i

Rev. 4, NRV Main Accumulator and Thermal Accumulator Nitrogen Charg-  !

ing and Gauging, to a value in accordance with the pre-charge press- i

ure/ temperature graph provided. The higher the ambient temperature  !

in the NRV enclosure, the greater the pre-charge pressure (in psi).  !

A temperature gauge provided in the center of the enclosure is used  !

to determine ambient air temperature. After several unsuccessful  !

attempts to clear the accumulator low pressure alarm, localized  !

temperatures were taken near the existing temperature gauge and over

l the affected accumulators. The temperature differential between ,

,

ambient on the local temperature gauge (normally used) and over the  !

'

accumulator showed greater than 25 degrees F difference. l

l I

l Additionally, pressurization of the accumulator is done by increasing .

l the regulator setting while observing outlet pressure on a pressure i

gauge on a manifold. During troubleshooting, a test pressure gauge  :

was attached directly to the affected No. 2 NRV accumulator and I

observed during pre-charge, opening and closure of the valve. The  !

pressure on the pressure gauge board was found to be reading approxi- [

mately 60 pounds lower than the pressure gauge attached to the  ;

accumulator, indicating that the accumulator was not being fully I

pre-charged to the required setpoint. Therefore, when the valve was  !

stroked open, the pressure did not reach the setpoint required to  !

clear the alarm. l

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12

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The root cause was attributed by the licensee to be low nitrogen

precharge resulting from the suspected pressure and temperature

instrumentation inaccuracies. There was no detectable leakage of

nitrogen discovered during the investigation. The nitrogen pressures

of all four NRV accumulators were checked. The No. 1 NRV nitrogen

pressure was also found to be lower than expected. Only the No.1

and No. 2 accumulators were charged using the same charging rig and

instrumentation during the past refueling outage. Corrective action

by the licensee includes changing the procedure used to charge

nitrogen to the NRV's accumulator to provide for the use of more

accurate instruments during its performance, and to provide for the

use of test instruments during its performance,

A subsequent engineering evaluation determined that the available

pressure in the accumulator would have been adequate to close the NRV

and maintain it closed in the event of an automatic initiation from a

,

steam line break initiation signal.

The inspector noted that during the trouble shooting of the NRV,

engineering support and quality assurance personnel were not evident.

Oversight of the work was performed by the I&C Supervisor. No viola-

tions or deviations were identified in the review of this event.

b. Inoperable Main Steam Line Low pressure Switches

.

On December 3,1987, station personnel identified equipment problems

with the steam line low pressure switches that provide reactor

protection and engineered safeguards system input signals.

,

j As a result, the plant initiated a shutdown from full power opera-

tions due to the inability to accompitsh a one-hour TS action state-

ment requirement. This event and inspection details are contained in

Sections 5, 8, and 9 of this report

!

7. Maintenance Observations

The inspector observed and reviewed maintenance and problem investigation

activities to verify compliance with regulations, administrative and main-

tenance procedures, codes and standards, proper QA/QC involvement, safety

tag use, equipment alignment, jumper use, personnel qualification, radio-

logical controls for worker protection, fire protection, retest require-

ments and reportability per Technical Specifications. The following

activities were included:

--

Maintenance Request (MR) 85-1503, Thermocouple connections on south

east spare show signs of leakage

--

MR 87-217, Liquid tight connector disconnected at SI-MOV-24 junction

box

,

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--

MR 87-1535, Switchgear room fire system panel battery terminal

corrosion

--

MR 87-1916, Fire system trouble alarm - switchgear room

--

MR 88-118, No. 1 BFP (boiler feed pump) outboard motor bearing oil

leak

--

MR 88-115, Loop No. 4 THNR (temperature hot narrow range) reads high

--

MR 87-852, No. 2 NRV air pump continues to pump af ter valve is open,

hydraulic oil level low

--

MR 87-560, Overhaul of main steam NRV and actuators

--

MR 87-1915, No. 2 NRV accumulator low pressure (nitrogen)

--

MR 87-1980, Main steam NRV low pressure switch MS-PS-13 failed to

operate

--

MR 87-1984, Main steam NRV low pressure switch MS-PS-31 failed to

operate

--

MR 87-2075, Control rod No. 3 position indication-loss of lights

Based upon a review of licensee activities in this area the inspector

noted the following:

--

Inspector review of the maintenance activities associated with MRs

87-1535 and 87-1916 is contained in Section 3 of this report.

--

Regarding MRs 85-1503 and 87-217, the inspector noted that the retest

section of these MRs was still open as of November 14, 1987. The

work was completed on the MRs on September 9,1987 and May 28, 1987,

respectively. Licensee weakness in the process of specifying and

controlling post maintenance retest activity was identified in NRC

inspection report 50-29/86-17. Based upon discussions with licensee

personnel, the inspector concluded that the problem involves a fail-

ure to document retest and not a failure to perform retest. Proced-

ure AP-0205, Rev. 12, Maintenance Request, specifies retest is to be

performed and requires thc individual performing the retest to com-

plete the applicable portion of the MR. It was not clear to the

inspector as to how the licensee insures that retest responsibilities

are delegated.

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_________ ______ ______ _ __ _ - _ _ __-_

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14

.

The inspector held discussions with licen:ee representatives about

the issue and inspector concerns. The licensee informed the inspec-

tor that their MR Task Force was developing new administrative con-

trols to address the aforementioned and related problems. Current

planning includes the development and issuance by the end of March,

1988 of a new maintenance procedure to control post-maintenance

retest. This document, when implemented, will provide a program to

improve pre-job planning, provide more consistent retest require-

ments, and improve the documentation of the actual activities that

are performed. The inspector informed the licensee that a major

cornerstone for this new program to function as envisioned will

require improved interdepartmental cooperation, especially between

the operations and maintenance departments. In the area of retest

activities, the inspector has determined that interdepartmental

cooperation between these two groups do not represent a licensee

strength.

The inspector will continue to review post-maintenance testing

activities and licensee progress to resolve NRC concerns in this area

during routine inspections in this area.

--

The inspector reviewed the licensee's repair activities associated

with MR 87-1915, which covered the corrective maintenance for the low

nitrogen pressure condition in the accumulator of the No. 2 NRV. The

inspector's review is documented in Sectica 6 of this report.

--

The inspector reviewed the licensee's repair activities associated

with MRs 87-1980 and 87-1984, which covered the corrective mainten-

ance for the failure of main steam NRV low pressure switches MS-PS-13

and MS-PS-31 to operate. The inspector's review is documented in

Section 8 of this report.

No violations or deviations were identified in the review of this program

area.

8. Surveillance Observations

The inspector observed tests or parts of tests to assess rerformance in

accordance with approved procedures and LCO's, test results (if completed),

removal and restoration of equipment, and deficiency review and resolu-

tion. The following test results and procedures were reviewed.

--

OP-4656, Rev. 5, Functional Test of the NRV Main Steam Line Pressure

Channels

--

OP-7105, Rev. 11, Normal Operation of the Incore Flux Mapping System

--

OP-2167, Rev. 12, Boric Acid Mix Tank Makeup

--

OP-4716, Rev. 8, Vapor Container Personnel Hatch and CA-V-755 Leak

Test

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--

OP-4656, Rov. 6, NRV Pressure Switch Functional Test of the NRV Main

Steam Line Pressure Channels

--

OP-4272, Rev. 1, Accident Monitoring Instrumentation Channel Check

--

OP-4232, Rev.17, Vapor Container Inspection

--

OP-4202, Rev. 10, Control Rod Operability Check

--

OP-6201, Rev. 11. Main Coolant Hot Leg Narrow Range and Wide Range

Temperature Channels Calibration.

Based upon a review of licensee activities in this area, the inspector

noted the following:

a. The inspector reviewed post-makeup surveillance activity for the

boric acid mix tank (BAMT). Operations department procedure OP-2167,

Rev. 12, BAMT Makeup, controls the process, requires sampling to be

performed, and stipulates requirements to provide appropriate control

log entries. These entries provide documentation that the plant

ope ators are aware of the applicable TS action statement involving

an inoperable BAMT because of unknown percent-weight boric acid solu-

tion in the tank. The chemistry department implements procedures

OP-9416, Rev. 9, Chemistry Control of Primary Auxiliary Systems and

OP-9201, Rev 9, Titrimetric Analysis for Chloride, Boron, Chromate,

P and M (phenolphtalein and mixed indicator) alkalinity, to control

their activities. Documentation of the sample results are trans-

ferred to the control room each shift that analyses are completed by

use of the Chemistry Data Transfer Log, APF-9003.1. This transfer

log, and reporting out of specification chemical analysis resul*.s to

the control room, are described in chemistry procedure AP-9003,

Rev. 6, Chemistry Instructions, Reports and Records.

Based upon a review of activities in this area, the inspector con-

cluded that the licensee has developed and implemented procedural

controls that assure proper performance of personnel, as well as aid

in providing proper interdepartmental communications,

b. During the performance of OP-4656 on December 3,1987 to accomplish

the routine monthly Technical Specification surveillance requirement,

MS-PS-13 (Channel 1, No. 3 steam header pressure switch) failed to

actuate. At 10:40 a.m., MS-PS-13 was declared inoperable. These

switches are part of the engineered safeguards and reactor protection

systems. The licensee entered TS action statements No. 6 of Table

3.3.2 and No. 8 of Table 3.3.1 to place the inoperable channel in the

tripped condition within one hour. A temporary change request (TCR)

was prepared to accomplish the required action statement, but due to

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the time required to obtain PORC concurrence on the TCR (No.87-442),

the inoperable channel was not placed in the tripped condition within

the one hour time interval. At 11:40 a.m. with the first jumper

request approved but not yet implemented, the licensee initiated

plant shutdown per TS 3.0.3. At 11:45 a.m. with the plant at 98% of

rated power, the channel was placed in the tripped condition and the

licensee began returning the plant to full power operation. The

'

switch was replaced, the channel trip removed, and an ENS notifica-

tion to the NRC was made in accordance with 10 CFR 50.72(b)(1)(1)(A) ,

at 1:40 p.m.  !

Subsequent surveillances on the remaining main steam line pressure

switches revealed that three additional switches were found outside

TS setpoint requirements (MS-PS-24, MS-PS-33, MS-PS-34). Four addi-

tional switches were found out of the established administrative

limits, but within TS limits. These switches were adjusted back to

the required trip setpoint. A second failed switch, MS-PS-31 was

found, the channel was placed in the tripped condition per TCR 87-444

within the required one hour time frame, and subsequently replaced.

Each pressure switch was tested independently, subsequently adjusted

as necessary or replaced, and returned to service before proceeding

to the next pressure switch in sequence. ,

The inspector noted the following. The TS setpoint requirement for

the main steam header pressure switches is greater than or equal to a

pressure of 262.5 psig. On the No. 3 steam line, the first pressure

switch failed to operate. The second and third channels actuated at

293 psig and 240 psig, respectively. On low steam line pressure, the ,

NRV would not have 1sulated until pressure dropped to 240 psig, 22.5

psig below TS setpoint requirements. On the No. 4 stears line, the l

pressure switches actuated at 296.5 psig. 260 psig and 240 psig. On

this steam line, main steam isolation also would have occurred below l

TS setpoint requirements. The main steam isolation trip closes the

main steam line NRVs and causes a direct reactor trip which reduces f

the severity of cooldown and the ensuing transient effects resulting i

from a main steam if ne break. This trip also serves to assure the

availability of a secondary system heat sink. Although main steam

isolation TS setpoint limit is 262.5 psig, the analyzed safety

envelope for this system is 200 psig. The assumed setpoint on the

Final Safety Analysis Report for calculation of the main steam line '

isolation trip is 200 psig. Therefore, although the No. 3 steam line

would not have isolated until a steam line pressure of 240 psig, this

is still within the analyzed safety envelope of 200 psig. The

licensee attributes the cause of the out-of-tolerance setpo3nt

settings to instrument drift for the three re-adjusted switches (LER ,

50-29/87-15).

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The inspector had several concerns in this area. First, it was noted

that the reason MS-PS-13 was not placed in the tripped condition

within the required one-hour time interval was due to the time

required to process and obtain PORC review of the TCR. The TS action

statement requires the inoperable channel be placed in the tripped

condition, and, therefore, the NRC does not consider this action to

be an unanalyzed plant condition or an unroviewed safety question

requiring further PORC review. Licensee administrative controls,

that preclude o- inhibit the required performance of a TS action

statement, as developed in procedure AP-0018 are inappropriate.

Licensee corrective actions to correct this condition are warranted.

The licensee has experienced previous problems with the steam line

pressure switches and subsequently replaced the switches. These

events were reviewed in two previous inspection reports (50-29/85-15

and 50-29/85-24). In 1985, two ASCO pressure switches were found to

operate outside the TS limit (one at 120 psig and the other at 78

psig) on two separate occasions. The first occurrence was attributed

to "instrument drif t" and the second was attributed to manufacturer

applied lubricant dried and seized around the switch actuaticn

plunger, inhibiting free motion of the plunger. Both pressure

switches were replaced upon discovery of operating outside TS set-

point requirements. Upon completion of a licensee tecnnical evalua-

tion, the remaining pressure switches were replaced during the 1985

refueling outage and four ASCO pressure switches were sent to a

laboratory testing service for evaluation of a possible common mode

failure. It was determined that the switches were experiencing ran-

dom aging reactions as a result of exposure to combinations of steam,

heat and/ or pressure. It was recommended in licensee memoranda that

to reduce the possibility of further aging-related failure, that:

1) syphons should be added between the switches and their test

valves; and 2) a replacement schedule should be established to assure

that the transducer units remain in service no longer than four

years, and the replacements should be staggered such that all of the

redundant transducer units are not of the same age.

These recommendations were accepted by senior licensee management on

June 13, 1986 and at PORC meeting 86-56 on September 4,1986, PORC

agreed to initiate a program to replace the switches. The licensee,

in an ettempt to begin implementation of these recommendations,

l

planned to replace five of the pressure switches during the 1987

'

refueling outage. However, this did not occur due to the lead time

required to obtain spare switches. Yankee Atomic letters dated

September 10 and 16, 1987 indicate that the licensee is still evalua-

ting modifications to the sensing lines but has not implemented this

recommendation. The licensee appears to consider the sensing line,

i.e., the perculation of water up into the line, rather than the

instrument itself, to be the major contributor to the problem of the

short switch service life.

,- - - - _ _ - - _ _ - - . - - - - - - - . - - - . - - - - - - - - - - - - - - . - .

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4

The previous problems with the ASCO pressure switches occurred in ,

1985, with recommendations made and approved by licensee management, t

,. As late as September 1987, the licensee was still evaluating correc- l

tive actions to resolve the problem of random aging reactions to the  !

pressure switches. The inspector is concerned about licensee per-

manent corrective action to determine the root cause of the most  !

recent pressure switch problem and to prevent recurrent problems with

-

!

the pressure switches. This ' tem is to be followed up in NRC Inspec- t

tion Report 50-29/88-02. Temporary corrective actions for the recent  !

'

pressure switch failures included ordering and having available more

spare pressure switches, determining the root cause of the most f

recent failure of the two pressure switches, and shortening the TS  ;

surveillance testing interval on the pressure switches from monthly '

to semi-monthly. During this event, the licensee discovered a mal- i

function in the heat tracing on the sensing line, which occurred t

during cold weather. This loss of heat tracing on the pressure i

switch sensing lines may have been a contributor to the possible '

common mode failure of the pressure switches. The licensee is also i

evaluating whether replacement of the switches with another type is  !

necessary. l:

1

Soon after the identification of the switch failures, the licensee's

station personnel had verbally requested Yankee Nuclear Services

Division (fNSD) project engineering group to arrange for a failure  !

analysis to be performed on the two switches that were replaced. As  !

of the end of the inspection period, these switches were still wait- r

ing for resolution as to where and when to send the switches for the .!

analysis. The inspector was concerned that the licensee had not i

placed an appropriate priority on the failure analysis effort. This

concern was discussed with licensee representatives, who acknowledged

the inspectors concerns, and indicated that a letter requesting the i

switch manuf acturer's assistance to perform the analysis would be i

transmitted shortly and the process expedited to address the NRC  !

concerns. With the exception of ensuring the timely conduct of a ,

failure analysis on the failed switches, the licensee has demon-  !

strated an appropriate level of concern and progress in providing l;

solutions that shojld result in improved reliability of the main

steam line low pressure switches. l

!

No violations or deviations were identified in the review of this program f

area. I

!

9. Emergency Preparedness

l

a. Notification of Unusual Event I

y

.

At 8:34 a.m. on November 21, 1987, the licensee declared an Unusual J

Event in response to an inoperable NRV and subsequently commenced a i

plant shutdewn to Mode 2 (see Section 6 for details of the event). I

The Unusual Event was declared to conply with plant emergency pro-  !

cedures, which specify that an Unusual Event be declared when a mode l

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19

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change is required by TS, concurrent with a loss of engineered safe-

guards. With the plant stable at less than 2% of rated power, the 1

'

NRV was shut and the licensee secured from the Unusual Event at 10:14

a.m. Appropriate state and NRC notifications were made in a timely

manner. ,

Although not required, the technical support center (TSC) was manned

and a minimal staff of 2 coordinators assembled in the emergency

operations facility (f0F) to check out equipment. The licensee's

Emergency Plan only requires the T!C coordinator and the E0F coor-

dinators to report, in response to an Unusual Evert; the TSC and 10F

are not activated. Additionally, the plant Technical Specifications

require each main steam NRV to be operable or closed within four

hours The licensee classified and declared the Unusual Event prior .

to the expiration of the allowed four hours to have the valve closed. '

Both items above demonstrate licensee management's conservative

approach and philosophy toward events that may have an effect on

public health and safety.

No violations oi deviations were identified in the review of this

event,

~

b. Initiation of Plant Shutdown Required by Technical Specifications

During an NRC team inspection conducted dudng the week of

January 10-15, 1983, a team inspector identified concerns regarding

an event that occurred on December 3, 1987. See Section 8 for

details of the event. Specifically, the team inspector questioned

whether the events regarding the initiation of plant shutdown

required by the TS warranted the classification and declaration of an

Unusual Event. The resident inspectors were directed by NRC RI

management to review aspects of the licensec's emergency preparedness

activities "elating to classifying an Unusual Event, with emphasis on

,

how these pertain to the events that occurred on December 3.

On December 3,1987, MS-PS-13 (Channel 1, No. 3 steam header pressure

switch) was declared inoperable; the licensce was required to place

the inoperable channel in the tripped condition within one hour per

TS. The inoperable channel was not placed in the tripped cendition

within the one hour time frame. At this time, the licensee ertered

TS 3.0.3, which requires that the plant be placed in at least hot

standby within one hour. Five minutes into plant shutdown with the ,

plant at 93% of rated power, the channel was placed in the tripped

condition and the plant was returned to full power operation.

The inspectors reviewed the sequence of events that occurred on

December 3, 1987 with respect to how the licensee determined the

classification of the event and management involvement in the class-

ification process. Interviews were conducted with the involved shift

supervisor, licensee management and YNSD emergency preparedness (EP)

personnel. ,

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When the licensee declared the pressure switch inoperable and entered

the TS action statement to place the switch in the tripped condition

within one hour, several actions occurred simultaneously. In the

control room, the shift supervisor and plant operations manager

reviewed OP-3300, Classification of Emergencies, to determine if

conditions warranted the classification of an Unusual Event. This

action occurred within ten minutes of the channel being determined

inoperable. As a result, the determination was made that an unusual

event did not exist at that time. Concurrently, a TCR (No.87-442)

was initiated by the I&C department to place the channel in the

tripped condition. Since this TCR affected an operating system,

plant procedure AP-0018 required a plant operations review committee

(PORC) review of the TCR. At the beginning of the PORC meetir.g. it

was recognized that due to the time required to obtain PORC concurr-

ence on the TCR, it would not be possible to place the inoperable

channel in the tripped condition within the required one hour and

that TS 3.0.1 would apply. Licensee management and supervisory ,

personnel were aware at that time that a plant shutdown would be {

initiated and collectively agreed that this condition did not fit any j

i

of the categories for an Unusual Event, based on the fact that it

would be only a matter of a few minutes past the one hour beferit the

jumper was installed and the channel placed in the tripped condition.

Procedure OP-3300, Rev. 5 Classification of Emergencies, specifies

under Event No. 22, General Events, that an Unusual Event is "Other

plant conditions exist that warrant increased awareness on the part

of the plant operating staff or State and/or local off-site author-

ities or require plant shutdown under Technical Specification

requirements or involve other .han a normal controlled shutdown. The

EAL (Emergency Action Level) is shift supervisor's opinion. The

licensee discussed this event at PORC, with the knowledge that plant

shutdown would be initiated as required by the TS, Plant and senior

corporate management were aware of the determination that an unusual

event was not considered to exist in this situation. This deter-

mination reflected the licensee's management philosophy concerning .

Event No. 22. The licensee considers Event No. 22 to me n that when

'

the licensee makes the actual determination that a plant shutdown is

equired, at that point, an Unusual Event will be declared. The

licensee does not consider Event No. 22 to mean the initiation of a

plant shutdown when it is apparent the problem will be fixed in a

timely manner. Licensee personnel discussed this event at a PORC

meeting, and the PORC was in agreement that the plant was not in a

condition that would result in an actual plant shutdown.

_ _ _ _ _ __ _

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21

.

The licensee considers Event ho. 22 to be a general statement, that

when, in the shift supervisor's opinion, en event is occurring that

indicates a potential degradation of the level of the safety of the

plant, the shif t supervisor is responsible to call an Unusual _ Event.

The inspector noted that, although this event illustrates manags-

ment's philosophy regarding event No. 22, this policy is not a

written policy to provide uniform guidance to all plant operating

personnel.

The shift supervisor has the responsibility to consider all the EAL's

and make the determination. Discussions with the shift supervisor

indicate that when the licensee declared the pressure swit.n inoper-

able and entered the TS action statement to place the switch in the

tripped condition, the licensee reviewed OP-3300 and determined at

that time an unusual Event classification did not apply. At the time

the licensee entered this TS action statemer.t, this determination by

the licensee was correct. None of the EAL's applied at this time.

The Shift Supervisor was not aware at that time that the channel

would not be tripped in a timely manner. However, as the situation

began to change, that is, when it became apparent that the channe ?

would not be tripped in the required one hour and that the licensee

would enter TS 3.0.3 to commence plant shutdown, the shift supervisor

did not consciously go back and re-evaluate the classification of the

event.

Discussions with the shift supervisor, however, indicated that even

if he had gone back to OP-3300 and re-evaluated the events requiring

an Unusual Event, he concurs that none of the events applied in this

situation. This is consistent with the licensee's management philos-

ophy on the event classification. The inspector is concerned, how-

ever, that as the event evolved, the shif t supervisor did not con-

sciously go back and re-evaluate the event as to classification.

Although not applicable to this situation, the inspector is concerned

that in the future an event classification may not be recognized as

'

the situation changes. A policy to go back and re-assess the event

and emergency action levels periodically and as the event develops /

changes may aid in properly and prcmptly classifying the event. The

inspector noted that this failure to re-assess the event as the event

changed (i.e., entered TS 3.0.3 to initiate plant shutdown) may have

contributsd to the late notification of the NRC of a 10 CFR 50.72

reportable event (See Section 5).

When the team inspection identified concerns regaraing this event,

licensee management was appraised of the NRC's concerns on January

13, 1988. During this meeting, the inspector noted that licensee

station management thought that the NRC concerns and commentary

pertained to Event No. 6, Plant Mode Reductions in accordance with

the Technical Specifications. Af ter the NRC focused the licensee's

attention on Event No. 22, they indicated that this event, in their

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22

9

opinion, did not apply to the conditions that occurred on

December 3, 1987. However, until further investigation could be per-

formed and a determination made by NRC: Region I (RI), the licensee

agreed to issue instructions to the plant operating staff defining

more specifically how Event No. 22 should be used for classification,

as defined by the NRC. The licensee issued a Special Order (No.

88-06) to the plant operating staff on January 13, 1988, stating that

the present interpretation (of Event No. 22) dictates that once the'

TS Action Statement grace period to repair, replace or otherwise

restore the component to operable status expires and a plant shutdown

is roquired, an Unusual Event must be declared.

The inspectors also reviewed NUREG 0654, Criteria for Preparation and

Evaluation of Radiological Emergency Response Plans and Preparedness

in Support of Nuclear Power Plants, and NUREG 0818, Emergency Action

Levels for Light Water Reactors and compared these to the licensee's

emergency action levels (EAL's) in order to gain an historical per-

spective on the licensee's development of the EAL's. The EAL's in

the licensee's emergency plan were developed directly from NUREG 0654

with the use of the additional guidance provided in NUREG 0818. This

is consistent in Event No. 22 of the licensee's emergency plan.

During the review of this event, the inspector discussed licensee and

NRC concerns regarding possible ambiguities with the EA L' s . In a

previous emergency preparedness inspection conducted by NRC:RI, an

open item was identified (87-03-04) that the EAL's should be evalu-

ated for inconsistencies and compared to the guidance of NUREG 0654.

The licensee has scheduled additional reviews to evaluate the effec-

tiveness of the EAL's in areas such as quantification of initiating

conditions. The licensee recognizes the need to improve the EAL's

and is considering forming a task force to accomplish this action.

The YNSD EP personnel are also involved in clarifying the EAL's. The

inspector noted that the licensee appears to be pursuing clarifica-

tion of the EAL's. This item will be followed during routine

emergency preparedness inspections.

Also reviewed was the licensee's training as it related to the EAL's

and classification of events. Discussions were held with training

personnel as to training methods; the lesson plans were reviewed as

were attendance sheets. Eight hours of classroom training on the

emergency plan were provided to on-shif t personnel as recently as

September / October 1987. The lesson plan appears to be comprehensive;

training for on-shif t personnel was focused on how to use the EAL's

to classity an event. The inspector had no further questions in this

area.

l

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!

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23

.

During the NRC's review of all aspects of the December 3,1987 event,

the inspectors noted that the licensee's TS 3.0.3 is currently not

consistent with the wording in the Standard Technical Specifications

(STS)'and Generic Letter 87-09. This inconsistency makes the licen-

see's TS 3.0.3 overly restrictive, such tnet strict compliance could

~

result in undesired rapid reactor shutdowns to Hot Standby. The

licensee's TS states that in the event a Limiting Condition for

Operation and/or associated Action Statement requirements cannot be

satisfied because of circumstances in excess of those addressed in

the specification, the facility shall be placed in at least Hot

Standby within one hour. Generic Letter 87-09 specifies for STS that

within one hour action shall be initiated to place the facility, as

applicable, in at least hot standby within the next six hours. The

licensee recognizes the limitations of their TS 3.0.3 and is con-

sidering a license amendment to reflect the current NRC endorsed STS

wording.

The events of December 3, 1987 and the licensee's policies concerning

the classification of events were discussed with NRC:R1 management

and emergency preparedness supervision and specialists. After review

of the events, NhC:RI concurred with the licensee's event classifica-

tion as it pertained to the events that occurred that day. The

inspector had no further questions of the licensee on this item.

'

No violations or deviations were identified in the review of this

event.

c. Nuclear Alert System Operability

During the inspection period, the inspector noted a number of control

room log entries that pertained to problems with the Nuclear Alert

System (NAS). The NAS is described in Section 7.0, Communicatioi.t,

in the licensee's Emergency Plan, which specifies that it originates

in the control room and is a microwave system used to notify the

State Police of Vermont and Massachusetts of any emergency. This

system is a secure (dedicated) communications arrangement and is

installed for the primary purpose of initial notification of the

states, via State Police, by the plant operators. This system is

manned on a 24-hour basis on both ends, the plant and the State

Police dispatching points. The backup to this system is the regular

telephone system. The ultimate arrangement for the activation of the

public notification system would stem from this 24-hour link to the

State Police.

The inspector reviewed the testing performed on the NAS by the licen-

see to insure availability. Licensee security procedure DP-0427,

Rev.13, Security Communications Systems, describes the testing per-

formed on a daily and monthly basis, with a requirement to document

the daily results in the Daily Security Activity Log (a safeguards

information document) and the monthly results on form OPF-0427.2.

Additional information about the use, testing, and actions required

,

- - - - -

- , ,-r- - . - - . , e -- - - - , , n a a

__ _ _ _ _ _ _ _ _ _ _

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24

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of licensee personnel as a response to loss / degradation of the NAS

are contained in OP-Memo 20-4, Nuclear Alert Telephone. According to

information supplied by a licensee representative, there were 34

different occasions between October 28, 1987 and January 14, 1988

that the licensee was unable to contact the Massachusetts State

Police (MSP) using the NAS. Since the licensee attempts to contact

the MSP three times a day, many of the occasions occurred in the same

day. The inspector noted that the licensee is testing the system far

more frequently that their commitment in the emergency plan, which

stipulates that it is tested on a monthly basis.

1

'

As a result of reviewing the licensee's activities in this area, the

inspector was unable to obtain a clear understanding of who in the

licensee's organization is responsible for identified system defici-

encies and their resolution. Equally unclear is the licensee's pro-

cedures and practices involving how it would report NAS unavaila-

bility events in accordance with 10 CFR 50.72(b)(1)(V). Inspector

concerns in this area were communicated to NRC:RI specialist inspec-

tors in the emergency planning area. It was concluded that the

inspector's observations in this area warranted further followup

during -a future routine specialist inspection. Accordingly, the

acceptability of licensee's oversight of the NAS and their 10 CFR '

50.72 reportability practices remains an Unresolved Item (50-29/

87-16-02). ,

10. Organization and Administration Changes

! During the inspection period, the inspector reviewed changes to the licen-

l see's staff or organization structure as described below. The review

included: verification that licensee's onsite organization structure is as

described in the facility TS, and verification that personnel qualifica-

tion levels are in conformance with ANSI N18.1-1971, as described in TS Section 6.3.1.

--

As a result of the retirement of the plant maintenance manager, the

licensee announced the promotion of the maintenance support super-

visor to fill this position effective December 1,1987. The main-

tenance support supervisor position was filled by the promotion and

transfer to the plant of a YNSD engineer that became effective on

January 1,1988.

--

On December 7, 1987, the licensee filled the position of the emerg-

ency planning coordinator in the technical services department. Al-

though this position has been vacant since September 11, 1987, the '

licensee had assigned a YNSD emergency planning engineer to assume

the position's duties.

.

f

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--

On January 5,1988, the licensee submitted Proposed Change No. 203,

Supplement 1 (FYR 87-119) to reflect, in part, restructuring of the

site security organization. This new organization has a security

manager that reports to the administrative services manager. The

licensee indicated that the new organization reflects a generally

elevated concern for security by plant management. On January 10,

1988, the licensee filled the position of . the security manager.

--

On January 5, 1988, the licensee informed the inspector that

Mr. Louis H. Heider, Vice President and Manager of Operations, was

planning to retire on January 31, 1988. The licensee informed the

NRC on January 20, 1987, that the responsibilities of this position

will be performed on a temporary basis by Mr. J. DeVincentis, Vice

President-Projects.

l No violations or deviations were identified in the review of this program

area.

11. Licensee Event Reports

l Licensee Event Reports (LERs) submitted to NRC:RI were reviewed to verify

l that the details were clearly reported, including accuracy of the descrip-

l tion of cause and adequacy of corrective action. The inspector determined

l whether further information was required from the licensee, whether

generic implications were indicated and whether the event warranted onsite

followup.

LER No. Event Date Report Date Subject

50/29/87-14 11/21/87 12/31/87 Plant Shutdown Because of NRV

Low Nitrogen Pressure Indica-

tion

50-29/87-15 12/03/87 12/31/87 Main Steam Line Pressure

Switches Inoperable

a. LER 50-29/87-14: The details of this event are contained in Section

6 of this Inspection Report. The inspector had no further questions

concerning this LER.

b. LER 50-29/87-15: The details of this event are contained in Section

8 of this Inspection report. With respect to the adequacy of the

l

LER, the inspector noted the following:

,

--

the licensee did not reference possible similiar past events

i

that have occurred with respect to these pressure switches.

--

the LER states that additional evaluations are being conducted

to determine if replacement of the switches with another type

is necessary and/or if a modification to the sensing lines from

the main steam lines to the switches is necessary. The inspec-

tor notes that tne licensee should inform the NRC of the results

of these evaluations by a supplement to this LER.

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26

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--

the licensee did not state what corrective actions will be taken

to preclude exceeding Technical Specification action statements

in the future.

The inspector held a discussion with the technical services manager

pertaining to the above items. He indicated that the LER would be

resubmitted to address the NRC concerns. Other than the deficiency

identified above, no violations or deviations were identified in the

review of this program area.

12. Cold Weather Preparations

The inspector reviewed implementation of the licensee's program for cold

weather protective measures to determine whether the licensee had

1) inspected systems susceptible to f reezing to ensure the presence and

operability of heat tracing, space heaters and/or insulation; 2) set the ,

thermostats properly; and 3) energized the heat tracing and space heating

circuits.

In preparing the plant for cold weather operation, the Operations Depart-

ment implements OP-2115, Rev. 13, Warm & Cold Weather Operation. The

inspector determined that this procedure was completed by the licensee on

November 18, 1987. To ensure the operability of the plant's heat tracing

systems, the Maintenance Department implements OP-5751, Rev. 9, Heat

Tracing Inspections, which was verified by the inspector to be completed

on November 20, 1987. A review of OP-2115 showed no discrepancies

existed. However, OP-2115, was started on September 22, 1987, but not

completed until November _18,1987. A review of past completion dates for

, these two procedures showed that OP-5751 is consistently completed by the

end of October. This is due to the fact that OP-5751 is tracked by the

Maintenance Department on an annual computerized printout and also on a

weekly computerized printout, to ensure timely completion. Contrary to

,

this, OP-2115 was shown to be historically completed as late as the second

-

week in December. This procedure is not on any surveillance tracking

program to flag the Operations Department that the procedure should be

completed. Placing OP-2115 on a surveillance tracking program would

ensure that prepartions for cold weather operation are performed prior to

freezing weather.

Throughout the cold weather period, the auxiliary operators for the pri-

mary and secondary sides of the plant perform routine shift checks on the

status of the heat trace and heating of systems and structures. The

inspector reviewed the PA0 and SA0 Log Sheets and verified these routine

activities were being accomplished. The licensee's actions associated

with cold weather preparations were determined the be consistent with

commitments made in its response to IE Bulletin No. 79-24, Frozen Lines

(WYR 79-123, October 10,1979).

-- - .. ,. _ _ - - - . - _ - = - - ..-

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27

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Additionally, the inspector reviewed plant' reporting records, determined

that events involving frozen systems or components are infrequent and,

when . they do occur, result in corrective action to preclude recurrence.

One event involving cold weather effects on components was reported in LER

87-02, involving the inoperability of the Safety Injection Building Vent

Fans PRV-1 and PRV-2. Follow-up of the LER and licensee corrective

actions was documented by the inspector in Inspection Reports 50-29/86-19

and 50-29/87-02.

Follow-up to freezing events was also reviewed and documented in Inspec-

tion Report 50-29/88-02.

No violations or deviations were identified in the review of this program

area.

13. Nuclear Safety Audit and Review Committee Activities

The Nuclear Safety Audit and Review Committee (NSARC) meeting minutes for 1

both special and regularly scheduled meetings were reviewed for the period

of March 22, 1985 to March 19, 1987. The Charter for the NSARC was also

reviewed. These were reviewed to verify the following:  :

--

The Charter and policies governing NSARC a-tivites were consistent [

with the Technical Specification and other Ngulatory requirements; ,.

--

The NSARC membership was as required by the Technical Specifications;

--

NSARC meetings were convened at the required frequency;

I --

Committee members who participated in reviews constituted a quorum; I

i

--

The NSARC reviewed all matters within the scope of responsibility as ,

defined by the Technical Specifications; and,

--

Audits required to be performed under the cognizance of the NSARC

were being performed as required by the Technical Specifications.

The inspector attended the regularly scheduled meeting of the NSARC on

November 18, 1987. The inspector verified that the composition, duties

and responsibilities of the NSARC are as stated in the Technical Specifi-

cations and that the NSARC routinely reviewed those matters within the

scope of its responsibilities. Briefings were presented to the Committee

members on past problems in the security and training areas, how the

licensee hcs addressed these problems, and the license's plans to upgrade

these areas.

No violations or deviations were identified in the review of this program

area.

_ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ _ _ ____-_ _ _ _ . - _____ __ _ . __-_.

28

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14. On-Site Review Committee Activities

The inspectors attended regularly scheduled meetings of the Yankee NPS

m-site review committee (PORC) on December 8,1987 and January 5,1988

to ascertain that the provisions of T.S. 6.5.1 were met.

No violations or deviations were identified in the review of this program

area.

15. Licensee Response to NRC Bulletins

The licensee's response to the following NRC Bulletin was reviewed. This

review included: adequacy of the response to bulletin requirements, time-

liness of the response, completion of identified corrective actions and

timeliness of completion.

NRC Compliance Bulletin No. 87-02: Fastener Testing to Determine Conform-

ance with Applicable Material Specifications, dated November 6, 1987.

This bulletin required the licensee to provide information concerning

their receipt inspection and internal control procedures for fasteners;

and the results of independent testing of fasteners. The licensee

selected ten non-safety related fasteners, ten safety-related fasteners,

and twenty safety-related nuts used with the aforementioned fasteners.,

The inspector participated in the licensee's selection process and ver-

ified that this process selected a representative sample of fasteners used  :

in the plant and was responsive to the bulletin requirements. Verifica-

tion was provided by the inspector that the licensee had properly tagged

the samples so as to assure traceability of the sample to the sample data

i sheet. When the licensee questioned particular aspects of the bulletin

requirements, the inspector provided resolution by discussing the issue

with cognizant NRC:RI specialist inspectors.

The inspector reviewed licensee letter FYR 88-06 to the NRC, dated

! January 11, 1988. This letter described the licensee's administrative

l

'

controls established for fastener receipt inspection storage and controls;

the sample selection process, the chemical and mechanical testing per-

formed on the selected samples; and the results of the testing.

According to the licensee's report, one non-nuclear safety fastener and

I

one safety-related nut did not meet the material specification tolerances.

,

An evaluation of the safety significance for the out-of-tolerance fasten-

'

ers was described. The licensee has placed the nonconforming safety-

related nut material on hold until additional testing of nuts from the

. same heat number as the out-of-tolerance nut can be performed. By

March 11, 1988 the licensee has committed to report the results of the

,

-- . - ~ .

r -- , -n.= .- - - ----. -,.e~, ,- , ,- , - - - . - , - n-,

, --- -

_

29

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additional testing, including the sa fety significance and application

limits. . In addition, to determine the extent of nonconforming fasteners

from the vendor, further ' sampling .and testing are to be conducted, with

results reported to the NRC by March 11, 1988. At that time, the licensee

will also report procedure revisions for procurement, receipt inspection,

and testing.

The inspector had no further questions of the licensee on this matter at

this time. This bulletin remains open pending the licensee's submission ,

of additional information enumerated above.

~

No violations or deviations were identified in the review of this program

area.

16. Management Meetings

During the inspection period, the following management meetings were con-

ducted or attended by the inspector as noted below: ,

--

The inspector attended an exit meeting held on January 15, 1988 by an

operationally-oriented, performance-based team inspection at the

conclusion of Inspection 50-29/88-02 to review activities in the area  ;

of operations, maintenance, surveillence, modifications and l

engineering support.

.

--

On January 13, 1988, the NRC Regior, I Reactor projects section chief

for Yankee Nuclear Power Station (YNPS) met separately with the YAEC

licensing engineer for YNPS and with the technical assistant to the

vice president and manager of operations. The meetings included:

.

'

(1) general discussions of acceptable methods for implementing the

NRC rules for correspondence handling, pursuant to 10 CFR 50.4 effec-

tive January 5,1987, (2) current points of contact with the NRC

Region I office for administrative, schedular and technical matters

including event communications with the Commonwealth of Massachusetts,

, and (3) current licensee practices both for internal tracking and for i

informing the NRC staff of the status and schedule for licensing

~

actions, including proposed technical specification changes and

Safety Issues Management Systems (SIMS) items.

--

At periodic intervals during the course of the inspection period,

'

meetings were held with senior facility management to discuss the

inspection secpe and preliminary findings of the resident inspectors.

L

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