ML20204F731

Insp Rept 50-293/86-14 on 860428-0602.Violations Noted: Inadequate Surveillance Testing of HPCI Sys Uncorrected for 6 Months & Equipment Overdue for Calibr Used on Three Occasions

ML20204F731
Person / Time
Site:	Pilgrim
Issue date:	07/30/1986
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20204F697	List: IR 05000293/1986014 ML20204F694 ML20204F713 ML20204F731
References
50-293-86-14, NUDOCS 8608040293
Download: ML20204F731 (19)

See also: IR 05000293/1986014

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TABLE OF CONTENTS

Page

1. Summary of Facility Activities ........................ A

2. Followup on Previous Inspection Findings . . . . . . . . . . . . . . 1

3. Routine Periodic Inspections .......................... 3

Daily Inspection, System Alignment Inspection,

Biweekly Inspections, Plant Maintenance and

Surveillance Testing

4. Review of Plant Events ................................ 7

a. Residual Heat Removal Minimum flow Protectior. Logic

Design Deficiency ................................ 7

b. Loss of Safety Bus 8-10 .......................... 7

c. Broken Cap Screws on M0-1400-4A Motor Operator ... 8 l

d. Operators, Maintenance Workers, and Clerical

Wo r ke r S t r i ke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

e. Loose RPS Wiring 9

5. Observations of Physical Security ..................... 10

6. Radiation Protection .................................. 10

7. Quality Assurance Audit Review ........................ 11

8. Confirmatory Action Letter (CAL 86-10) Followup . . . . . . . 14

9. Strike Activities...................................... 15

j 10. Review of Licensee Event Reports (LER's) . . . . . . . . . . . . . . 16

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11. Management Meetings ................................... 17

Attachment I - Persons Contacted

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B600040293 860730

PDR ADOCK 050002 3

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DETAILS

1.0 Summary of Facility Activities

The plant was shut down on April 12, 1986 for an unscheduled maintenance

outage. Subsequently, the NRC issued Confirmatory Action Letter 86-10

which required that the licensee seek approval from the NRC Regional

Administrator for reactor restart. The outage continued throughout the

current inspection period.

On May 16, 1986, plant operators, maintenance workers, and clerical staff

went on strike. Laborers for the major contractor on site, Bechtel also

went on strike during the inspection period. Neither strike had been

settled by the end of the inspection period.

2.0 Followup on Previous Inspection Findings (Differential Relay Problem)

(Closed) Unresolved Item (86-07-03). Failed Diesel Generator Lockout

Relay. On April 26, 1986, the licensee experienced failures of the A

diesel generator differential and lockout relays. The function of the

differential relay is to provide generator protection against

phase-to phase or phase-to ground faults by energizing the lockout relay

if such s. condition is sensed. When energized, the lockout relay trips

open the generator breaker and mechanically locks in the tripped state

until manually reset. As the lockout relay reaches full locked out

position, its relay coil is deenergized. On April 26, 1986, one of the

three coils associated with the differential relay failed, causing an

erroneous signal to be generated. The lockout relay energized but did

not operate to the full locked out position. Due to the incomplete

actuation the lockout relay coil remained energized. The continuously

energized coil failed, resulting in a small fire. The licensee rebuilt,

tested, and reinstalled the lockout relay. Equipment history indicates

no similar lockout relay problems. Corrective action taken regarding the

differential relay was to electrically bypass the failed component,

leaving the unaffected "A" coils and the "B" diesel generator

differential relay intact.

During review of the incident, the inspector noted that the differential

relay in question was a General Electric Model 12CFD relay. IE

Information Notice 85-82, issued October 18, 1985, identifies this model

relay as being not seismically qualified. When questioned regarding the

continued use of the unqualified relay in an active safety related

application the licensee provided the inspector with Engineering Service

Request (ESR) Response Memorandum NED-85-788 dated July 23, 1985. The

ESR had been initiated in response to industry information concerning

this problem. NED-85-788 confirms that the differential relays installed

at PNPS are not seismically qualified and will require replacement. It

also contains a " Justification for Continued Operation" which briefly

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addresses the impact of spurious relay operation on three scenarios:

Seismic Event with a LOCA, Loss of Offsite Power with a LOCA, and Seismic

Event with Loss of Offsite Power. This JC0 was not reviewed by onsite or

offsite safety review committees. Two of the discussed scenarios require

timely if not immediate operator action to reset the resulting generator

breaker trips. Operator action in these instances entails recognition of

the problem by the control room staff and dispatching an operator to a

remote location to clear the condition. The inspector also reviewed PNPS

Procedure 5.2.1, Revision 7, Earthquake. While the procedure does direct

the operator to check the electrical buses for spurious trips, it does not

provide any specific guidance and also requires the operator to perform

numerous parallel tasks. No operator training or procedure enhancements

had been implemented to highlight the potential problem area.

One scenario assumes a seismic event coincident with a loss

of offsite power. Under these conditions, a spurious operation of these

relays results in a total loss of station AC power; a condition not

analyzed in the safety analysis. In any event the reliability of the

emergency diesel generators is lessened by the presence of unqualified

components. Prior to identification of these concerns by the inspector,

the licensee had no scheduled plans for replacement of these relays.

This item is considered unresolved and will be the subject of further

review (86-14-01).

The inspector discussed this matter with Nuclear Engineering Department

and station management. The inspector was informed that a Failure and

Malfunction Report and Potential Condition Adverse to Quality Report had

been initiated to track the component deviation. An evaluation will be

performed to determine the ramifications of operating with the

unqualified components. The inspector will review the type and content

of any evaluation performed. Engineering is conducting a review of ESR

dispositions during the preceding year to identify any similar

circumstances. In addition, it was stated that engineering department

personnel have received training regarding proper implementation of the

corrective action program.

Nuclear Operations Department and Engineering Department management

. stated that the relays in question would be replaced with seismically

j qualified components prior to startup. In the interim on shift

operations personnel have been trained regarding the possible problems

associated with the current condition.

Based on issuance of the above unresolved item, this item is closed.

(Closed) Unresolved Item (293/85-06-03). Core spray recirculation test

! valve, MO 1400-4A, operator mounting bolts found loose. This item was

l last updated in inspection report 85-08. During a routine tour, on

April 26, 1986, operations personnel identified two broken operator

mounting capscrews on the 1400-4A valve. Corrective actions taken by the

licensee in response to this recurring problem were reviewed by the

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inspector, and are discussed in section 4 of this report. Design changes '

implemented appear to be adequate. Periodic inspections by both opera-

tions and maintenance personnel will identify any additional problems.

The inspector had no further questions. This item is closed.

(Closed) Unresolved Item (293/86-07-04). Review of corrective action for

failed cap screws on core spray valve MO 1400-4A. Licensee corrective

actions dealing with the above problem are discussed in detail in section

4 of this report, and under item 85-06-03. Based on the changes

described, and on the licensee's commitment to continue periodic

inspection of the valve, this item is closed.

(0 pen) Violation (86-01-08) Failure to follow procedures for completing a

post trip review and failure to log disabled control room annunciators.

The inspector reviewed the licensee response letter, dated April 11,

1986. In the letter, the licensee indicated that an evaluation of

control room equipment problems would be conducted and the resident

inspector informed of the results of the evaluation by May 11, 1986.

However, at the end of the inspection period, the licensee had not

completed these actions. The inspector discussed the commitment with the

Plant Manager, who indicated that he would check on the status of the

evaluation and inform the resident inspector of the results. This item

will remain open, pending further NRC review of licensee actions in this

area.

(Closed) Follow Item (86-06-10). Review resolution of audit findings for

QA audits 84-34 and 85-25, including Deficiency Report 1466. This NRC

open item highlighted DR 1466, a QA audit finding concerning high

pressure coolant injection (HPCI) system testing. On May 16, 1986, the

recently appointed Plant Manager asked the inspector about DR 1466. The

Plant Manager indicated that he had been asked to review the DR by senior

licensee management. This DR was issued by QA on November 8, 1985 and

had been contested by the Nuclear Operations Department since that time.

The new Plant Manager promptly determined that he agreed with the QA

finding. The licensee notified the NRC of the HPCI surveillance test

problem later that day. This DR and the audit findings are discussed

further in section 7 of this report. This item will be administratively

closed. Further NRC followup will be conducted in response to the

violation in section 7.

3.0 Routine Periodic Inspections

a. Daily Inspection

During routine facility tours, the following were checked: manning,

access control, adherence to procedures and limiting conditions for

operation (LCO's), instrumentation and recorder traces, control

, room annunciators, safety equipment operability, control room logs

and other licensee documentation.

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No unacceptable conditions were identified.

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b. Systems Alignment Inspection

Operating confirmation was made of selected piping system trains.

Major motor operated and manual valve positions for safety equipment

were verified during routine checks of the control room. Valve

power supply, breaker alignment, and safety equipment controller set

points were also checked.

No items for further inspection were identified and no unacceptable

conditions noted.

c. Biweekly Inspections

During plant tours, the inspector observed shift turnovers and

checked: plant conditions, valve positioning and locking (where

required), instrumentation lineup, radiological controls, security,

safety, and general adherence to regulatory requirements. Plant

housekeeping and cleanliness were evaluated. The inspector had

no further questions.

d- Plant Maintenance

he inspector observed and reviewad maintenance and problem

investigation activities to verify compliance with regulations,

administrative and maintenance procedures, codes and standards,

proper QA/QC involvement, safety tag use, equipment alignment,

jumper use, personnel qualifications, radiological controls for

worker protection, fire protection, retest requirements, and

reportability per Technical Specifications.

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Cracked MSIV Return Springs at Fermi-2

During the inspection period it was reported that four return

springs in two of the Fermi Unit 2 MSIV's were found to be

broken. The vendor for the Fermi Unit 2 MSIV's is Atwood-

Morrell. The supplier of the springs in question is Duer Spring

, and Manufacturing Company. A part 21 notification is presently

! being evaluated by the utility staff. The MSIV's installed at

l Pilgrim are also manufactured by Atwood-Morrell. In addition

l cracking of the pilot poppet return springs has been identified.

l The inspector discussed with licensee maintenance personnel the

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event at Fermi Unit 2, its relevance to Pilgrim and plans for

l addressing the potential problem. The licensee had not

responded to the inspector's questions by the end of this report

period. This issue will be examined in a future inspection

(86-14-02).

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Refueling Bridge Replacement: Heavy Load Handling Procedures

During the inspection period the licensee transported the

components necessary for replacement of the existing refueling

bridge from an outside laydown area to the refueling floor.

Components were transported from the laydown area into the

reactor building truck lock at elevation 23', rigged for lift-

ing, and hoisted up through the equipment hatch to elevation

117' using the reactor building crane. The inspector reviewed

Plant Design Change number 86-58, Refueling Bridge Replacement,

to verify that proper precautions, procedures, inspections and

safe load paths had been established. The inspector also

examined Pilgrim Nuclear Power Station Procedure 3.M.1.4,

General Maintenance Procedure for Heavy Load Handling Opera-

tions, to determine if lifts planned under PDC 86-58 were in

accordance with station policy. In addition, completed lift sign

off sheets were examined. Operations appear to have been well

planned and in accordance with the established heavy load

handling program. The inspector had no further questions.

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Review of Station Salt Service Water Pump Maintenance History

During the report period the licensee experienced varying

problems with three of the station salt service water (SSW)

pumps. The D pump was rebuilt due to excessive vibration and

low discharge pressure. The E pump also demonstrated high

vibration. A fault developed in the C pump motor and the motor

was subsequently rewound. The inspector reviewed past

inservice testing results for the service water pumps and

determined that while the recent coincident problems appear

significant, individual pump histories do not indicate

accelerated pump wear. The inspector will evaluate any future

SSW pump problems and inservice test data during routine

inspections.

e. Surveillance Testing

The inspector observed parts of tests to assess performance in

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

completed), removal and restoration of equipment, and deficiency

review and resolution.

On May 15, 1985 at 11:00 p.m., the inspector noted an I&C test

instrument in the control room with an expired calibration sticker.

The instrument was a Hewlett-Packard timer-counter, no. 135 that was

last calibrated on October 18, 1985. The calibration due date on the

instrument was April 18, 1986. The licensee later indicated that the

instrument had only been used for the calibration of channel one of

the main stack gas radiation monitor. The monitor was subsequently

recalibrated. The plant was in cold shutdown at the time of the

incident.

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The inspector reviewed I&C instrument issue records and discussed

the counter with I&C personnel. The following problems were noted

during this review:

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Procedure 1.3.36, " Measurement and Test Equipment", section

D.1, states that measuring and test equipment storage areas

shall provide sufficient separation of ready-to-use equipment

(calibrated and limited use) from other equipment (rejected) as

to preclude inadvertent use. Contrary to this requirement,

test equipment with expired calibrations were not promptly

separated from other equipment. Issuance records indicated

that instruments with expired calibrations were left in the

instrument lockers for several weeks to three months in one

case. The records indicated that a second timer-counter, no.

134, was used with an expired calibration on March 13, 1986.

This instrument was not removed from the instrument locker

until two weeks after the calibration due date.

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The I&C equipment issuance policy is verbal and not always

followed. The policy, according to I&C management, requires

that instruments be signed out using an instrument issuance

sheet. This was not consistently done. For example, the

timer-counter in the control room on May 15 had not been signed

out. Also, calibration due dates were not recorded on the

sheets as required, in many cases.

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The I&C personnel did not have confidence that all test

equipment was included on the preventative maintenance (PM)

data base. This data base is used to identify equipment coming

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due for calibration so that the equipment can be removed from

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the equipment lockers.

As immeatate corrective action, the licensee agreed to check

equipment records to ensure that the instruments without due date

entries on the equipment issuance sheets were in calibration. The

timer-counter in the control room was removed and will be

! calibrated. The timer-counter that was used in March with an

i expired calibration has since been checked and was found to be in

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calibration.

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l An additional test instrument with an expired calibration was used

by personnel in the Onsite Safety and Performance Group to check a

local leak rate cart on May 23, 1986. This instrument, a Fluke

l Multimeter no. S8600A, was last calibrated on October 28, 1985 and

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was due for calibration on April 28, 1986. The instrument is

l maintained by the Onsite Safety and Performance Group.

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The multimeter was not entered in the PM data base. The inspector

also noted that the multimeter serial number and calibration due

date were not required to be recorded on LLRT test data sheets.

The licensee stated that the instrument was only used during the

test witnessed by the inspector. A second multimeter was obtained

and the LLRT cart checks repeated. No discrepancies were found.

10 CFR 50 Appendix B, criterion XII, requires that measures be

established to assure that measuring and testing devices used in

activities affecting quality are properly controlled. Failure to

ensure that test equipment is only used within its calibration

period is a violation of 10 CFR 50 (86-14-03). A previous citation

in this area was issued in 1985 (NRC Inspection Report

50-293/85-03).

4.0 Review of Plant Events

a. RHR Minimum Flow Protection Logic Design Deficiencies

On May 19, 1986, the licensee reported that a situation had been

identified where a single instrument failure could lead to loss of

all four RHR pumps. During review cf IE Information Notice 85-94 the

licensee discovered that a failure of either differential pressure

switch 1001-79A or 1001-798 would cause both system minimum flow

valves to remain closed on pump start. If the RHR minimum flow

valves failed to function while all other system discharge valves

were closed, pump damage would occur in 20 to 60 seconds. These

conditions would exist during a LPCI initiation with the reactor

vessel at pressures greater than 400 psig; during a small break LOCA.

The loss of all RHR functions including LPCI, drywell spray, torus

cooling and shutdown cooling represents a loss of safety functions

beyond the plant design basis.

IE Compliance Bulletin Number 86-01 was issued to all GE boiling

water reactors on May 23, 1986 addressing the problem identified by

, Boston Edison. This bulletin requires licensees to take prompt

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corrective action and to provide the NRC with written information

detailing problem resolutions.

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Boston Edison has submitted to NRC: Region I written notification of

! noncompliance as required by 10 CFR Part 21. The inspector will

review the corrective actions taken by the licensee and any written

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responses required by Bulletin 86-01 during the next inspection

period (86-14-04).

b. Loss of Safety Related 480V AC Motor Control Center B-10

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Safety related 480V AC Bus B-6 feeds 480V AC motor control certer

B-10 through breaker B603. MCC B-10 in turn powers the C Salt

Service Water (SSW) pump through breaker 1061. On May 12, 1986, -

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while attempting to start the C Salt Service Water pump, breaker B603

tripped open resulting in the deenergization of 480V MCC B-10. The C

SSW pump motor breaker, breaker 1061, did not act to protect MCC

B-10. Subsequent action taken by the licensee included testing of

breaker 1061 and 8603. Problems with the performance of the. time

delay trip function for two phases of the 8603 breaker were

discovered. This breaker was replaced with a tested spare and

shipped to General Electric for repairs. Testing of the C SSW pump

motor identified no problems.

On May 23, 1986 during start of C SSW pump installed spare breaker

B603 again tripped, resulting in a second loss of MCC B-10.

Licensee investigation revealed a fault in the C SSW pump motor.

Preliminary testing indicates that both breaker B603 and 1061 are

functioning properly.

Licensee investigation and evaluation is progressing under Failure

and Malfunction Reports86-115 and 86-123. This evaluation should

address the failure of component breaker 1061 to protect MCC B-10

and the failure of breaker 8603 time delay trip devices to perform

as designed. The inspector will review corrective actions taken

during a future inspection (86-14-05).

c. Broken Cap Screws on M0-1400-4A Motor Operator

On April 26, 1986 during an inspection of the 1400-4A valve the

licensee identified two sheared valve yoke to adapter plate

capscrews. Instances of loose or broken yoke to adapter plant

capscrews were documented in LERs83-010, 83-035 and in inspection

report 85-06. Previous efforts to alleviate the problem, including

increased capscrew installation torque, lockwire, and use of thread

locking compound have been ineffective. In response to the latest

problem recurrance the licensee performed a detailed review of the

valve design, examination of the failed capscrews, and conducted

testing to determine the contribution of system vibration to the

failure.

Review of the valve history indicates that M0-1400-4A was originally

a motor operated globe valve. The globe valve was replaced with a

! gate valve and the existing operator retained. The bolt pattern of

the operator was matched to the new gate valve yoke by installation

of an adapter plate. The adapter plate was fastened to the yoke and

the operator by a number of capscrews. It was determined that the

current operator torque switch settings, originally specified for

the globe valve application, are excessively high for use with the

installed gate valve. Performance testing revealed valve closing

thrust approximately 10,000 lbs. greater than that required to drive

the valve. It was also determined that the high capscrew

installation torque produced preload stresses contributing to the

problem. Licensee analysis of piping vibration data concluded that

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while vibration levels were not excessive they were a contributor to

the observed failures. The sum of the above contributors is

believed to constitute the problem root cause.

The inspector reviewed approved Plant Design Change (PDC) 86-32, ESR

Response Memorandum NED 86-411, and discussed these planned

corrective actions with responsible personnel. Changes specified by

these documents include: 1) use of high strength capscrews, 2)

reduction of capscrew installation torque, 3) reduction of operator

torque switch settings to valves consistent with the design, and 4)

placement of a segmented fillet weld between the valve yoke and

adapter plate. Licensee engineering staff believe that the problem

root causes have been identified, and adequately addressed by the

above described changes. In light of the recurring nature of these

problems periodic inspections of the valves seem prudent. Station

operations staff has in the past performed daily inspections of the

valves. One of the inspections had identified the most recent

failure. The operations department has committed to continue the

daily inspections, and to formally add the checks to the operator's

daily tour list. Based on review of the modifications and continued

inspections of the applicable valves the inspector considers the

issue resolved,

d. Operators, Maintenance Workers, and Clerical Workers Strike

On May 15, 1986 at midnight, plant operators, maintenance workers,

and clerical workers went on strike. The inspector observed the

plant turnover from the striking workers to management. No problems

were identified. This item is discussed further in section 9 of

this report.

e. Loose RPS Wiring

On May 2, 1986, the licensee found a loose wire connecting a relay

in the reactor protection system (5A-K18A) to the common ground bus.

On May 5, 1986, a loose ground wire caused relay 5A-K9A to

deenergize generating a half scram. The licensee subsequently

determined that the compression couplings which connect the

individual relay ground wires to the ground bus were too large, which

prevented the couplings from gripping the ground wiring tightly.

At the management meeting with NRC Region I on May 12, 1986, the

licensee agreed to discuss their evaluation of the loose wiring in a

supplemental response to CAL 86-10. This item will be reviewed

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further during followup to the CAL response (86-14-06).

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5.0 Observations of Physical Security

Checks were made to determine whether security conditions met regulatory

requirements, the physical security plan, and approved procedures. Those

checks included security staffing, protected and vital areas barriers,

personnel identification, access control, badging, and compensatory

measures when required. No problems were identified.

6.0 Radiation Protection

Radiological controls were observed on a routine basis during the

reporting period. Standard industry radiological work practices,

conformance to radiological control procedures and 10 CFR Part 20

requirements were observed. Independent surveys of radiological

boundaries and random surveys of nonradiological points throughout the

facility were taken by the. inspector. The following problems were noted.

a. Under-Responding Alarming Dosimeter

On May 9, 1986, the inspector learned that an integrating alarming

dosimeter had underresponded during use in a 70 R/hr radiation

field. Specifically, a Dositec model DOS-502A had been used during

work on a radioactive resin liner on April 30, 1986. Following the ,

work, the licensee noted that radiation dose recorded by the

alarming dosimeter, 290 mR, did not agree with the individuals

thermoluminsece.nt dosimeter (TLD) reading, 518 mR.

The worker had been in a radiation field as high as 70 R/hr during

the work on the liner. The licensee stated that monitoring by health

physics personnel, rather than the alarming dosimeter, was the

primary method to limit the worker's radiation dose. The alarming

dosimeter vendor subsequently told the licensee that the dosimeter

response to radiation was not linear above about 9 R/hr. However,

the vendor literature did not indicate this dose rate limitation.

The inspector informed Radiation Specialists in NRC Region I of the

l problem with the alarming dosimeter response. The adequacy of

radiological controls during work in the 70 R/hr field on April 30

will be reviewed during a future specialist inspection.

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b. Radiation Survey at Edgar Station

On May 16, 1986, NRC Region I received an allegation that

radioactive material was being stored at Edgar Station, a

decommissioned coal-fired power plant owned by the licensee. The

licensee indicated that non-radioactive material used at Pilgrim was

stored at the fossil station. This material included decontaminated

stagir.g stored in four large shipping containers.

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On May 21, 1986, the inspector observed a radiation survey of stored

material at the fossil station, including portions of the staging

and material stored in an adjacent building. The licensee surveyed

the material using an Eberline E140 instrument with an HP-210 pancake

G.M. radiation probe. Checks for loose contamination were also per-

formed. The inspector noted that the survey was conducted in a slow,

careful manner by licensee personnel.

Two items associated with the staging, a staging coupling and an

empty barrel, were found to have fixed radioactivity levels slightly

above background. Both had activity levels of 50 to 100 counts per

minute above background. These levels are below the licensee's

limits for releasing material from the site, i.e., 0.1 mr/hr fixed

activity or about 600 counts per minute on the survey instruments.

No loose radioactivity was detected on the two items.

The inspector had ne further questions concerning material stored at

Edgar Station. However, the inspector noted that the survey

instrument conversion factor for converting instrument count rate to

radiation exposure levels was not included in station procedures.

The licensee stated that the conversion factor (600 counts per

minute corresponds to 0.1 mR/hr) was derived from experience with

radiation fields in the plant, but not documented. The licensee

agreed to evaluate and document the conversion factors. The

inspector had no further questions.

7.0 Quality Assurance Audit Review

The inspector reviewed two licensee audits (84-34 and 85-25) which

examined licensee programs for compliance with certain technical

specification requirements. Several deficiencies were identified during

the audits and subsequently documented in deficiency reports (DR). The

following problems were noted with DR 1466.

DR 1466 (Audit 85-25) was issued on November 8, 1985. The DR identified

six high pressure coolant injection (HPCI) system valves that were not

adequately tested during simulated automatic initiation testing.

Specifically, the DR identified sections of electrical wiring for the

valves that were not checked during HPCI surveillance testing. The DR

was discussed between QA and the Nuclear Operations Department (N00) for

three months. The N00 argued that the valve wiring could be maintained

intact through plant configuration control and did not need to be tested

in the surveillance program. The QA Department rejected this approach to

surveillance testing. Poor plant configuration control in the mid 1970's

was recently blamed for an undetected wiring change that made a plant

electrical safety bus inoperable (Licensee Event Report 86-03 and NRC

inspection 50-293/86-06).

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The rejected DR 1466 response was listed in weekly DR status reports to

senior corporate management during January 1985. The DR was listed as

overdue in the status reports after the 90-day corrective action period

expired on February 6,1986. No Vice President extension was requested

for the DR.

The Nuclear Engineering Department subsequently issued a memo agreeing

with the QA interpretation on April 18, 1986. The QA Manager issued a

memo to the Vice President, Nuclear, on April 23, 1986 which requested

his assistance in resolving DR 1466. On May 16, 1986, the N00 agreed

with the DR finding and reported the inadequate surveillance test to the

NRC via the ENS telephone system.

Criterion XVI in 10 CFR 50 Appendix B requires in part that measures be

established to assure that conditions adverse to quality are promptly

corrected. Failure to conduct a full simulated automatic initiation test

of the HPCI system as required by technical specification 4.5.C.1 is a

condition adverse to quality. Failure to correct this deficiency for

more than six months after the problem had been identified in DR 1466 is

a violation of Criterion XVI in 10 CFR 50 Appendix B (86-14-07).

The following programmatic problems were also noted during the review of

QA audits 84-34 and 85-25. These problems may have contributed to the

lack of a timely response to DR 1466.

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Section 18.4.5 of the Boston Edison Quality Assurance Manual (BEQAM)

requires that deficiency reports be dispositioned within 90 days of

issuance or must have a DR extension authorized by the appropriate

Vice President. Contrary to the requirement, DR's routinely exceed

either the 90-day limit or the VP extension dates for long periods

of time without resolution. For example, a licensee DR status

report dated March 28, 1986, showed that eleven DR's had overdue

corrective actions; with some overdue by as much as twelve to

fifteen weeks. Anothar DR status report dated May 9, 1986, indicated

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that seven DR's were overdue; some by as much as 18 weeks. Overdue

DR's are either beyond the initial 90-day period or beyond the VP

extension date.

, A contributing factor to the late DR's was the practice of not

l always requesting VP extensions. For example, DR's 1456 and 1466

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extensions were not requested for either DR.

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Section 18.4.6 of the BEQAM requires that a written request for a

second response be forwarded to the appropriate Vice President if QA

can not obtain a satisfactory resolution of a DR. However, the QA

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Department routinely forwards requests for second responses to

l Department Managers rather than the Vice Presidents. As discussed

above, DR 1466 was not referred by QA to the appropriate Vice

President until after two DR responses had been rejected, over five

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months after the DR was issued. Although they are not sent the

requests for the second DR responses, senior corporate management is

sent weekly DR status reports that highlight overdue DR's and

rejected DR responses.

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Section 16.2.6 of the BEQAM defines "significant" as conditions that

indicate lack of or reducticn of management's ability to control

activities affecting quality. In addition, Section 16.2.9 of the

BEQAM states that conditions reportable to the NRC under 10 CFR

50.72 and 50.73 are significant. Department Managers are required

by the BEQAM to respond to a significant finding within one week.

However, deficiency reports involving inadequate surveillance

testing were not classified by QA as "significant". For example, DR

1321 (Audit 84-34) indicated that simulated automatic actuation

tests were not adequately conducted for the reactor core isolation

cooling (RCIC), core spray, low pressure coolant injection (LPCI),

and automatic depressurization (ADS) emergency cooling systems. A

similar finding was made in DR 1466 (Audit 85-25) concerning the

HPCI system. Neither finding was classified as significant. DR

1321 was not resolved for nine months. DR 1466 was resolved after

six months of review and was eventually reported to the NRC under 10

CFR 50.72 as a technical specification violation.

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A nonagressive surveillance testing philosophy is evident in the N00

responses to the QA findings. For example, DR 1322 noted that the

RCIC flow rate test at 150 psig was not adequate because a test

potentiometer rather than the RCIC flow controller was used during

the test. The NOD disputed this finding for three months before

finally agreeing to change the RCIC test. The response to DR 1466

is another example of the limited surveillance philosophy. Also,

the licensee's response to NRC surveillance findings (NRC report

50-293/85-03) was limited.

As corrective action for these problems, the HPCI surveillance procedures

have been modified and the wiring in question will be tested prior to

declaring HPCI operable during the next reactor startup. The revised

HPCI procedure was not reviewed during the inspection period, but will be

reviewed during the followup to the citation in this section.

Contractors are reviewing the licensee's surveillance testing program for

completeness and technical adequacy. The results of this review will be

evaluated during a future NRC inspection. The licensee has indicated that

to identify and resolve QA problems more quickly, daily meetir.gs will be

held between QA representatives and the Plant Manager. In addition, the

BEQAM will be modified to require that disputed DR's be escalated to a

Vice President 45 days after issue; further escalated to the Senior Vice

President in an additional 15 days; and finally escalated to the President

75 days after issue.

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Lack of aggressive action on QA findings has been previously noted.

Citations were issued in NRC inspection report 50-293/85-03 for failing

to promptly correct a surveillance testing problem involving reactor

protection system alarms and for failing to take prompt corrective

actions for other QA findings. In addition, the la:k of timeliness in

correcting QA/QC findings was hignlighted as a program weakness in the

surveillance testing section and in the overall summary section of the

1985 NRC SALP report.

8.0 Followup to Confirmatory Action Letter 86-10

Confirmatory Action Letter (CAL) 86-10 was issued on April 12, 1986. The

letter contained concerns in three areas: spurious group one primary

containment isolation closures, the inability to open the outboard main

steam line isolation valves (MSIV) following the isolations, and primary

coolant leakage into the residual heat removal (RHR) system.

The inspectors observed portions of the following maintenance activities:

(1) replacement of the reactor mode switch, (2) reassembly of two MSIV

pilot poppets and one MSIV main poppet, (3). installation of the GETARS

computer system, and (4) disassembly and inspection of M0-1001-288 RHR

injection valve. A local leakage test of the MSIV's in the "B" main

steam line was also observed and is discussed in section 3.e of this

report. In addition, the inspectors reviewed training conducted for

management personnel who installed the SB-9 replacement mode switch and

documentation related to the various work activities.

The following problems were noted:

--

On May 10, 1986, the inspector observed set screw installation

during the assembly of the IC MSIV pilot poppet in the hot machine

shop. The inspector verified that torque wrenches used during the

.

assembly were calibrated and set properly. The work was controlled

by plant design change (PDC) 86-28. A QC inspector was present

during the assembly.

The inspector noted that the workers generally followed set screw

installation instructions. However, the workers did not drill and

tap the set screw holes in the pilot poppet in the order specified

in the instructions. The inspector noted that QC witness points in

the procedure could be affected by deviating from the specified

procedure sequence. The licensee indicated that the procedure would

be changed to more closely match the work and to clarify the QC

witness points. In addition, the workers were instructed to follow

the procedure sequence. The licensee also indicated that the other

i MSIV's had been assembled in the sequence required by the original

set screw procedure. The inspector had no further questions on this

item.

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On May 10, 1986, the inspector observed that workers removing the

reactor mode switch were not closely following the verification

steps in the procedure. Specifically, the workers signing a

verification step in the procedure were not always witnessing the

entire step. The licensee subsequently instructed the workers to

witness each step in its entirety prior to signing the procedure.

The steps in question were repeated. The inspector subsequently

noted that workers were more careful with the verification steps.

No further problems were identified.

--

On May 20, 1986, the inspector witnessed final disassembly and

initial inspection of RHR injection valve M0-1001-288. Activities

observed appeared well planned, and adequate safety precautions had

been established. The licensee conducted and documented inspection

of the valve internals upon disassembly. The inspector also

examined seating surfaces and valve internals. While no significant

seating surface degradation was identified, erosion / corrosion of the

valve poppet body was noted. This erosion / corrosion was documented

and forwarded to engineering for evaluation. Engineering

disposition indicates that continued use of the concerned poppet for

up to five years is acceptable, however a recommendation for

replacement during the next refueling outage has been made. The

licensee also plans to disassemble and inspect the MD-1001-28A valve

for similar conditions. The inspector had no further questions.

Periodically during the report period the inspector witnessed activities

associated with the installation of the GETARS monitoring system. The

inspector also reviewed temporary modification number 86-18 detailing the

installation of GETARS and its impact on the plant. Based on the infor-

mation presented in the temporary modification package it appears thet no

credible failure mode exists which could compromise the independence or

operability of the primary containment isolation and reactor protection

system channels. The inspector observed that installation activities were

conducted in accordance with the applicable instructions. The inspector

also discussed with the licensee the planned training for on-shift

! personnel addressing operation of the GETARS system. The inspector had no

further questions.

The inspectors will continue to follow the actions taken in response to

CAL 86-10 and document this follow up in future inspections.

9.0 Strike Activities

On May 15, 1986, plant operators, maintenance workers, and clerical staff

went on strike. Operations Department supervisors (licensed senior

j reactor operators) were shifted to licensed operator positions at

midnight on May 15. The inspector observed the shift turnover at

midnight and toured the facility. No discrepancies were noted, other

than a test instrument with an expired calibration (section 3.e of this

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report). During the remainder of the inspection period, the inspectors

periodically observed supervisors in licensed operator roles. No

problems were identified.

The licensee had prepared for the strike by stockpiling food and bedding

material onsite. Plant storage tanks were checked and topped off prior

to the strike deadline. Local officials were informed of the possible

labor action. Police officers were stationed at the entrances to the

owner controlled areas at the plant to assist the onsite guard force. No

disturbances occurred during the inspection period.

The licensee discussed operator staffing with the inspector prior to the

strike. Three operating shifts were established and manned by management

personnel. Only Operations Department supervisors who had been on watch

just prior to the strike were assigned to the licensed operator

positions. Licensed personnel in staff positions were assigned to act as

unlicensed operators during the strike.

Training plans for the acting licensed and unlicensed operators were

discussed in an NRC management meeting in Region I on May 19, 1986.

Additional discussions were held between Operator Examiners in Region I

and the licensee on May 21, 1986. During these discussions, the licensee

agreed to furnish additionai details in a written response to Region I.

The inspector had no further questiens at this time.

All nonessential plant activities were cancelled for two days after the

start of the strike to allow supervisory personnel time to adjust to the

reduced staffing size. The inspectors will continue to review plant

activities to ensure that the strike is not adversely affecting plant

safety.

In an unrelated labor dispute, laborers working for the chief contractor

onsite, Bechtel, went on strike on May 1, 1986. The strike did not

significantly affect operational activities at the plant. Construction

work involving some plant modifications were suspended due to the

strike.

10.0 Review of LER's

LER's submitted to NRC:RI were reviewed to verify that the details were

clearly reported, including accuracy of the description of cause and

adequacy of corrective action. The inspector determined whether further

information was required from the licensee, whether generic implications

were indicated, and whether the event warranted onsite followup. The

following LER's were reviewed:

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LER No. Event Date Report Date Subject

86-009-00 4/11/86 5/9/86 In series primary contain-

ment isolation valves MO-

1001-288 and 29B indicating

leakage past seats

86-010-00 4/15/86 5/15/86 Main Steam Line Isolation

while reactor shutdown

86-011-00 4/19/86 5/19/86 Leakage past MSIV's in

excess of LLRT criteria

The event described in LER 86-09 was reviewed and documented in

inspection report 86-07, licensee response to Confirmatory Action (CAL)

86-10, and section 8 of this report. Events documented in LER 86-10, as

well as several similar isolations, were reviewed by NRC Augmented

Inspection Team during inspection 86-17 and were addressed by the

licensee in the response to CAL 86-10. The MSIV problems described in

LER 86-11 and the corrective actions taken by the licensee are included

in the licensee's response to CAL 86-10, and are summarized in section 8

of this report.

11.0 Management Meetings

A+. periodic intervals during the course of the inspection period,

meetings were held with senior facility management to discuss the

inspection scope and preliminary findings of the resident inspector. No

written material was given to the licensee that was not previously

available to the public.

On May 19, 1986 a meeting between Region I and Boston Edison senior

management was conducted at Region I offices in King of Prussia. Purpose

of the meeting was to discuss Boston Edison's response to Confirmatory

Action Letter 86-10, future plans regarding pertinent issues and to

resolve or identify any CAL 86-10 outstanding issues.

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A

Attachment 1 to Inspection Report 50-293/86-14

Persons Contacted

L. Oxsen, Vice President, Nuclear Operations

A. Pederson, Nuclear Operations Manager

P. Mastrangelo, Chief Operating Engineer

D. Swanson, Nuclear Engineering Department Manager

K. Roberts, Director Outage Management

N. Brosee, Maintenance Section Head

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T. Sowdon, Radiological Section Head

J. Seery, Technical Section Head

E. Ziemianski, Management Services Section Head

S. Wollman, On-Site Safety and Performance Group Leader

B. Eldridge, Acting Chief Radiological Engineer

R. Sherry, Chief Maintenance Engineer

D. Mills, Construction Management Group Leader

J. McEachern, Resource Protection and Control Group Leader

E. Graham, Compliance and Administrative Group Leader

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