ML20204F731
| ML20204F731 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 07/30/1986 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20204F697 | List: |
| 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 . . . . . . . . . . . . . .
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3.
Routine Periodic Inspections ..........................
3
Daily Inspection, System Alignment Inspection,
Biweekly Inspections, Plant Maintenance and
Surveillance Testing
4.
Review of Plant Events ................................
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a.
Residual Heat Removal Minimum flow Protectior. Logic
Design Deficiency ................................
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b.
Loss of Safety Bus 8-10 ..........................
7
c.
Broken Cap Screws on M0-1400-4A Motor Operator ...
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d.
Operators, Maintenance Workers, and Clerical
Wo r ke r S t r i ke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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e.
Loose RPS Wiring
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5.
Observations of Physical Security .....................
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6.
Radiation Protection ..................................
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7.
Quality Assurance Audit Review ........................
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8.
Confirmatory Action Letter (CAL 86-10) Followup . . . . . . .
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9.
Strike Activities......................................
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10.
Review of Licensee Event Reports (LER's) . . . . . . . . . . . . . .
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11. Management Meetings ...................................
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Attachment I - Persons Contacted
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B600040293 860730
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.
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
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stated that the relays in question would be replaced with seismically
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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
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valve, MO 1400-4A, operator mounting bolts found loose. This item was
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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
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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
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and other licensee documentation.
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
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being evaluated by the utility staff.
The MSIV's installed at
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Pilgrim are also manufactured by Atwood-Morrell.
In addition
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cracking of the pilot poppet return springs has been identified.
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The inspector discussed with licensee maintenance personnel the
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event at Fermi Unit 2, its relevance to Pilgrim and plans for
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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.
Review of Station Salt Service Water Pump Maintenance History
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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:
Procedure 1.3.36, " Measurement and Test Equipment", section
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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.
The I&C equipment issuance policy is verbal and not always
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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
the equipment lockers.
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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
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calibrated. The timer-counter that was used in March with an
expired calibration has since been checked and was found to be in
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calibration.
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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
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Multimeter no. S8600A, was last calibrated on October 28, 1985 and
was due for calibration on April 28, 1986.
The instrument is
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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
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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
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noncompliance as required by 10 CFR Part 21. The inspector will
review the corrective actions taken by the licensee and any written
responses required by Bulletin 86-01 during the next inspection
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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
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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
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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
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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
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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
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
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always requesting VP extensions.
For example, DR's 1456 and 1466
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were both passed their initial 90-day completion dates by at least
12 weeks at the time of the May 9 status report. However, VP
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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
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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:
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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
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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
MSIV's had been assembled in the sequence required by the original
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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
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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
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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
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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
T. Sowdon, Radiological Section Head
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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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