ML20210P435
| ML20210P435 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 09/02/1986 |
| From: | Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20210P324 | List: |
| References | |
| 50-293-86-25, NUDOCS 8610060773 | |
| Download: ML20210P435 (27) | |
See also: IR 05000293/1986025
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report No. 50-293/86-25
Licensee: Boston Edison Company
800 Boylston Street
Boston, Massachusetts 02199
Facility: Pilgrim Nuclear Power Station
Location: Plymouth, Massachusetts
Dates: July 8, 1986 - August 4, 1986
Inspectors: M. McBride, Senior Resident Inspector
J. Lyash, Resident Inspector
G. Nejfelt, Resident Inspector
L. Doer 11 , Project Engineer
Approved by: _
A
( . Strosnider, Chief, Reactor Projects
7 /88
Date
ection IB
Summary: July 8, 1986 - August 4, 1986
- Inspection Report 50-293/86-25 ,
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Areas Inspected: A routine resident inspection was conducted of the control
room, accessible parts of plant structures, plant operations, radiation protec-
tion, physical security, plant operation records, plant events, maintenance,
surveillance, and reports to the NRC. The inspection totaled 350 hours0.00405 days <br />0.0972 hours <br />5.787037e-4 weeks <br />1.33175e-4 months <br /> by three
resident and one regional inspector.
Results: Two violations were identified regarding the failure to follow sur-
ve111ance test procedures (section 3.e) and failure to initiate Failure and
Malfunction Reports (F&MR) for deficient fire barriers (section 7). A devia-
tion from an NRC commitment concerning fire brigade training was also identified
(section 2). Lack of operations personnel sensitivity to control rod drive ac-
cumulator status lights is discussed in Section 3a. Inadeauacies in the oper-
ating and alarm procedures for the hydrogen and oxygen monitors is discussed in
section 3.b. The licensee's plans to replace secondary containment dampers in
light of a 1985 commitment to the NRC and recent damper problems is discussed
in section 3.d. Possible weaknesses in preventive maintenance on ATWS (antici-
pated transient without scram) equipment, in maintenance records control, and
in the design of the feedwater check valves are also discussed in section 3.d.
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Recent calibration drift in safety bus undervoltage relays is discussed in
section 4.e. Concerns about the control, calibration, and testing of certain
480 VAC and 125 VDC undervoltage relays and concerns about the use of fuses and
solid links in safety-related motor control circuits are discussed in section
4.e and 4.f respectively. An inaccurate NRC safety evaluation supporting an
exemption from the requirement to install a hydrogen recombiner is discussed in
section 4.h. Excessive security guard overtime is discussed in section 5.
8610060773
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TABLE OF CONTENTS
Page
1. Summary of Facility Activities ........................ 1
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2. Followup on Previous Inspection Findings . . . . . . . . . . . . . . 1
3. Routine Periodic Inspections .......................... 6
Daily Inspection, System Alignment Inspection,
Biweekly Inspections, Plant Maintenance and
Surveillance Testing
4. Review of Plant Events ................................ 10
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a. Loss of 480 VAC Bus B-23 and Resulting
i b. Low Level Contamination of Onsite Sewage Tanks
i c. Anticipated Transient Without Scram Monthly
- Functional Test Discrepancies
] d. Reactor Building Ventilation Sample Pump
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Failures
e. 4160 VAC Safety Bus Undervoltage Voltage
j Relay Calibration Failures
f. HPCI Area Unit Cooler Breaker Fire
g. Protective Instrumentation Rack 2205
Upscale Drift
h. Hydrogen Recombiner Safety Evaluation
1. Intermediate Range Neutron Monitors
5. Observations of Physical Security ..................... 14
6. Radiation Protection and Chemistry .................... 15
7. Station Fi re Barrier Deficiencies . . . . . . . . . . . . . . . . . . . . . 15
8. Local Leak Rate Test Program .......................... 16
9. Independent Verification of Operating Activities . . . . . . 16
10. Review of Licensee Event Reports (LER's) . . . . . . . . . . . . . . 17
11. Confi rmatory Action Letter 86-10 Update . . . . . . . . . . . . . . . 19
12. Congressional Staff and NRC Commissioner Visits to .... 19
Pilgrim
13. Management Meetings and Meetings with Local Groups .... 20
Attachment I - Persons Contacted
Attachment II - Summary of Security Force Overtime
Attachment III - NRC Questions Regarding the Supplement of Response to CAL 86-10
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OETAILS
1.0 Summary of Facility Activities
The plant has been shutdown since April 12, 1986 for unscheduled
maintenance. Subsequent to the shutdown, the NRC issued Confirmatory
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continued throughout the report period.
On July 14, 1986, Commissioner James Asselstine met with NRC and licensee
representatives on site to discuss the performance of Pilgrim, and
- program improvements made to date. A station tour followed the meetings.
On July 25, 1985, Boston Edison announced that three major tasks will be
added to the current outage which will extend the projected startup date
from September 1986 until early 1987. The tasks are (1) the completion
of fire protection modifications at the station (2) the installation of
certain enhancements to the Pilgrim Mark I primary containment structure,
and (3) refueling the reactor. The Pilgrim outage was discussed during a
i licensee management meeting in the NRC Region I office on July 30, 1986.
2.0 Followup on Previous Inspection Findings
l Violations
(0 pen) Violation (83-23-01), perform IST of ECCS/RCIC injection check
valves. This item was last updated in inspection report 84-16. The
licensee has established procedures for performing a manual exercise test
of the HPCI and RCIC injection check valves. These procedures verify
that the valve discs are free to rotate, but do not verify that the valve
seats on reversal of flow. Similarly, no reverse flow testing of the
core spray system injection check valves is conducted. In response to
the Confirmatory Action Letter (CAL) 86-10, the licensee has commi;ted to
leak test the RHR injection check valves. During followup of CAL 86-10
the inspector questioned the licensee regarding the need to also leak
test the HPCI, RCIC and core spray check valves. No response had been
received from the licensee prior to close of the inspection period.
Unresolved Items
(0 pen) Unresolved Item (86-01-03), review licensee evaluation of the use
of fuses and metal links. This item was last updated in inspection
report 86-21. During the period High Pressure Coolant Injection System
Area Cooler breaker 1822 caught fire due to a control circuit fault, and
installation of a solid link. This event is described in section 4;f of
this report.
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(0 pen) Unresolved Item (86-14-01), operation with unqualified diesel
generator differential relay. The inspector reviewed Boston Edison
Memorandum NED 86-583, Evaluation of Emergency Diesel Generator (EDG)
Differential Relay Issues. The memorandum's conclusions were 1) the use
of the unqualified relays placed the plant configuration beyond the
design basis as set forth in the FSAR, 2) the use of the Engineering
Service Request process for addressing the discrepancies was inadequate
with respect to the timeliness and completeness of the disposition, 3)
the use of the company " corrective action program" would have ensured
adequate and timely action, including 50.59 safety evaluation and 4)
the safety significance of the unqualified relays was small.
If the established corrective action program described in the Boston
Edison Quality Assurance Manual, had been followed comprehensive and timely
engineering analysis and corrective actions could have been taken. This
will be addressed by the licensee in their written response to inspection
report 50-293/86-14. This item will remain open pending an NRC review of
the General Electric station blackout analysis supporting the licensee's
evaluation.
(0 pen) Unresolved Item (86-07-02), review licensee corrective action for
failed secondary containment seals. The inspector reviewed the licensee
evaluation of the two secondary containment boot tears. Thermal movement
of the pipe, vibration, localized harsh environment and some material
degradation were identified as the most probable cause for the boot
failures. The licensee repaired the subject tears by overlaying the area
with sealant. Initial plans were to reinspect all penetrations in the
steam tunnel, including the damaged boots, during RF0 #7. Other
recommendations included replacement of the damaged boots during RF0 #7.
The current maintenance outage has been extended to encompass the
, refueling outage. The inspector questioned the licensee regarding any
revised plans, possibly including replacement of the boots during this
extended outage. Similar boots on the main steam lines were replaced
several years ago. This item remains open pending response from the
licensee regarding future boot inspection / replacement plans. !
(Closed) Unresolved Item (86-21-01), fire brigade drill requirements not
satisfied. Review of licensee training records for the period of i
January 1,1985 through July 31, 1986 indicate that a significant portion
of the station fire brigade have not participated in scheduled drills.
During calendar year 1985 approximately thirty of sixty-nine brigade
members did not participate in a drill. Thirty-two of seventy-five
brigade members have not drilled in 1986. Fourteen brigade members did
not participate in any drill during the nineteen month period between
January 1,1985 and July 31, 1986. Five individuals added to the brigade
in July, 1985, had not participated in a drill.
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The licensee committed in a letter to the NRC, dated March 1, 1977, to
conduct fire brigade training in accordance with item B.6.e.2 of NRC
Branch Technical Position APCSB 9.5-1, Revision 1. Item B.6.e.2 states
that required training can only be accomplished by conducting drills
several times a year (at least quarterly), so that all members of the
fire brigade have had the opportunity to train as a team, testing itself
in the major areas of the plant. This commitment was reviewed and
accepted by NRC:NRR in its fire protection safety evaluation, as
referenced in the facility operating license. Failure to ensure that all
individuals participate in at least one drill annually raises concern
regarding the ability of members to perform if called upon.
The inspector informed the licensee that the above failure to satisfy
commitments made to the NRC is considered a deviation (86-25-01).
Inspector Follow Items
(0 pen) Follow Item (84-44-02). The individual who performed sludge
lancing of a contaminated tank without supervisor's approval, and removed
his teledosimetry device, was terminated as an employee. The disregard
of radiological monitoring by the individual was outside the expected
reasonable activities addressed in the licensee's procedures such as
reporting lost, damaged, missing, abnormal reading, or off-scale
dosimetry to Health Physics (HP) - PNPS Procedure 6.2-11, Revision 5,
dated October 26, 1984. After a discussion with the inspector who opened
this item, it will remain open pending a specialist review.
(0 pen) Follow Item (84-44-03). The practice of making a verbal change to
a radiological work permit (RWP) is no longer permitted by PNPS Procedure
6.1-027 dated June 12, 1986. RWP revisions must now be in writing and
reviewed by a supervisor at the same level as for the approval of the
original RWP to assure that the radiological controls are within the
scope of the RWP or if a new RWP is required. Enforcement of this
procedure would prevent the potential problem made by a verbal change to
a RWP. After a discussion with the inspector who opened this item, this
item will remain open pending a specialist review.
(0 pen) Followup Item (84-44-05). A HP technician allowed another
technician to perform sludge lancing without a breathing zone air (BZA)
sampler, although required by the RWP. Use of BZA sampler and regulated
air sampler is stated in PNPS Procedure 6.3-160, Revision 9, dated
April 11, 1986. Special precautions and equipment needed to work safely
within existing radiological conditions is stated in PNPS Procedure
6.1-022, Revision 20. The current procedure controlling RWPs, PNPS
Procedure 6.1-027 dated June 12, 1986, requires an HP supervisor to change
the RWP in writing. This item will remain open pending a specialist
review.
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(Closed) Inspector Follow Item (85-27-51), H202 monitor acceptance
criteria not adequate for inspection. The inspector reviewed the
environmental qualification (EQ) files for the containment hydrogen
monitors. The component test report and evaluation sheets originally
identified a required yearly inspection. . Subsequent discussion between
the licensee and vendor determined that a yearly zero adjust and span
adjust is adequate. This determination was documented in a telephone
call record and Revision 1 to the EQ Evaluation Sheet dated November 8,
1985. System calibration is performed on a six month interval as
required by technical specifications. This item is closed.
(Closed) Inspector Follow Item (85-31-02), review licensee evaluation of
potential problems with RHR pump impeller wear rings. This item was last
updated in inspection report 86-21. During the current inspection period
the licensee began disassembly and inspection of all four residual heat
removal pumps and motors. This effort is scheduled to complete in mid
September. The inspectors observed portions of the pump motor work. GE
supervisors and GE QC inspectors were present during NRC review and
appeared actively involved with the ongoing work. The NRC inspectors
will continue to monitor work activities during routine inspections.
Specialist inspection of this activity is documented in NRC inspection
report (86-27).
(0 pen) Inspector Follow Item (86-14-04), evaluate implementation of RHR
minimum flow logic modifications, The inspector reviewed PNPS Plant
Design Change 86-33, Revision 1, MO 1001-18 A&B control modification.
This design change was initiated in response to the si:gle failure
susceptibility of the RHR pump minimum flow protection logic identified
by the licensee and discussed in IE Bulletin 86-01. PDC 86-33 changes
the minimum flow valve position from normally closed to normally open.
It also deletes the valve automatic close input from the flow sensing
instrumentation. The net effect of these changes is that the minimum
flow valves will initially be open and remain open during Low Pressure
Coolant Injection System (LPCI) operation. Because the valves remain
open throughout LPCI injection approximately 500 gpm per pump will be
diverted from the vessel. The licensee evaluation of the affect of the
reduced LPCI flow on the station accident analysis and technical
specifications will be reviewed in a future inspection.
TMI Action Plan Items
(0 pen) TAP Item II.D.3, Safety Relief Valve Position Indication.
Guidance provided in NUREG 0737 indicates that the safety / relief valve
position indication system should be environmentally qualified. The
licensee committed to install environmentally qualified indication prior
to startup from RF0 #5. Qualified indication was installed under Plant
Design Change Request 77-78. The design installation was reviewed in
inspection report 82-10.
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Regulatory Guide 1.97 designates primary system safety / relief valve
position indication as a category two variable. Guidance provioed on
category two equipment qualification states that instrumentation should
be environmentally quali-fied. The licensee, in submittals discussing
compliance with regulatory guide 1.97, designated this equipment as not
requiring environmental qualification. The NRC:NRR safety evaluation
addressing this area is not expected until 1987.
Based on the regulatory guide 1.97 submittals the licensee deleted the
position indication system from the EQ Master List and no longer
believes that the equipment must be maintained as environmentally
qualified. This item remains open pending resolution of this
discrepancy.
(Closed) TAP Item II.F.1.6, Post Accident Containment Hydrogen
Monitoring. The licensee has installed a primary containment hydrogen
M oxygen (H202) monitoring system. The system has been designated as
5 fgty related and applicable quality control requirements applied. The
WMM consists of two redundant safety trains, each independently
cace.ia .of taking samples from two drywell and one torus location.
Samp1M; system control and calibration can be accomplished locally or
remotely from the control room. System components are powered by class
IE power. Sample valves close on a containment isolation signal, but may
be reopened from the control room using an isolation signal override
feature after an accident. Reagent and calibration gas fill connections
outside secondary containment have been provided to allow recharge
following an accident if secondary containment entry is not possible.
Both H202 sample trains are maintained in a standby condition. This
ast.ures their availability within thirty minutes, but does not result in
the excessive equipment wear associated with continuous service. Oxygen
monitoring during normal operations is provided by a separate oxygen
analyzing system which alarms at 3% concentration. Technical
specifications addressing operability of containment combustible gas
monitoring were added undee amendment 55. These specifications were
reviewed by NRC:NRR and found acceptable as documented in a safety
evaluation provided to Boston Edison on July 5, 1985. Based on the above
this item is closed.
The inspector performed a walkdown of accessible system components and
reviewed applicable drawings and procedures. This is described in
section 3.b of this report.
Followup on a Part 21 Report - On March 13, 1986, the Philadelphia
Electric Company submitted a 10 CFR Part 21 report concerning a failure
of a Clow Corporation butterfly valve due to galvanic corrosion between
the valve's carbon bushings and stainless steel shaft. The inspector
questioned BECo to see if they knew of this potential problem. The
licensee indicated that they were aware of the Part 21 report and that it
was currently being reviewed by engineering for applicability. The
licensee further stated that any corrective action required would be
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completed prior to the next reactor startup. The inspector will review
the results of the licensee's evaluation and corrective action during a
subsequent inspection (86-25-02).
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
operations (LCO's), instrumentation and recorder traces, control
room annunciators, safety equipment operability, control room logs
and other licensee documentation.
During a tour of the control room the inspector noted that several
control rod drive accumulator trouble lights were not in alarm with
accumulator charging water isolated. The inspector verified locally
that all accumulator pressures were below the alarm point. In
addition numerous alarm lights on the local accumulator trouble
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alarm panel were not lit. In response the licensee operations staff
replaced those alarm lights which had burned out, and wrote
maintenance requests for the remaining nonfunctional indications.
These indications should have been in an alarmed state for a period
of days prior to the inspector's observation. Operations personnel
were not sensitive to the indication status. This lack of
sensitivity was also noted in inspection report 86-01.
b. Systems Alignment Inspection
Operability confirmation was made of selected systems. Major motor
operated and manual valve positions were verified during routine
checks of the control room. Valve power supply, breaker alignment,
and safety equipment controller set points were also checked.
The inspector walked down accessible portions of the Primary
i Containment Hydrogen /0xygen (H202) Monitoring System. The accuracy
of system valve / breaker lineups and operating instructions was
reviewed. The adequacy of surveillance testing for the components
was evaluated.
During normal system operation the safety related Comsip post
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accident H202 monitors are in standby mode. A separate nonqualified
02 (C-41) monitor is used to continuously indicate containment
oxygen concentration. If 02 concentration increases to 3% a control
room alarm is received from the C-41 monitor. The Comsip H202
monitors are to be placed in service and alarm at 4% H202
concentrations.
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The inspector noted that alarm response procedure 2.3.2.20,
Revision 7 did not direct the operator to place the safety related
H202 analyzers in service upon receiving the containment Hi/ Low (3%)
02 alarm. Discussion with the control room staff indicated that the
need to place the H202 system in service if the alarm is received had
not been conveyed. The licensee informed the inspector that proce-
dure 2.3.2.20 would be changed to provide this guidance.
Nuclear Operations Procedure 2.2.133, Revision 3, H202 Analyzer and
C-19 system details system alignment and operating instructions.
The valve lineup in the procedure precludes operation of the C-41
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oxygen monitoring system. However, this equipment is normally in
service. The inaccurate procedure had neither been followed nor
corrected. This procedure also provided inaccurate instructions for
overriding a containment isolation signal and reopening the H202
sample valves post accident. The licensee is processing changes to
procedure 2.2.133 to correct the valve lineup and add steps to
recover from an isolation signal.
Technical specifications require measurement of containment oxygen
concentration at least twice weekly. The requirement is satisfied
by reading the C-41 02 analyzer. Periodic calibration of the 02
analyzer is accomplished by procedure 7.4.18. The inspector noted
that procedure 7.4.18 was not included on the Master Surveillance
Tracking Program (MSTP) to ensure its implementation.
Procedure 7.10.7, Calibration Checks of Comsip H202 Analyzers is
performed monthly as a functional test. As part of this test
chemistry department personnel verify that correct calibration gas
concentrations are posted in the main control room. The inspector
noted that no calibration gas concentrations had been posted and
that procedure 7.10.7 was not on the MSTP. The licensee, when
informed, posted the correct gas concentration and added procedures
7.4.18 and 7.10.7 to the MSTP.
c. Biweekly Inspections
During plant tours, the inspector observed shift turnovers, plant
conditions, valve and instrumentation lineup, radiological controls,
security, safety, and general adherence to regulatory requirements.
Plant housekeeping and cleanliness were evaluated. The inspeetor
had no further questions.
d. Plant Maintenance
The inspector observed and reviewed 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 l
reportability per Technical Specifications. I
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The licensee has begun disassembly and inspection of all four
residual heat removal system pumps. The primary reason for
disassembly is the examination of the pump wear rings for signs
of cracking. The project has been contracted to General
Electric with Boston Edison oversight. A regional inspector
arrived on site August 4,1986 to examine the ongoing work (NRC
Inspection Report 50-293/86-27). Resident inspectors will
continue to monitor work activities.
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The inspector reviewed a series of recent secondary containment
isolation damper problems. The dampers in question appear to
be deficient in design. Failure of the dampers was the subject
of special inspection 85-21. The licensee stated that
replacement of the dampers with a nuclear grade design would be
campleted during this outage. During the inspector's exit
meeting station management reiterated its commitment to replace
the dampers prior to startup.
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During a plant tour on July 8,1986 the inspector noted
deficiency identification (DI) tags hanging from the alternate
rod insertion valves. The maintenance requests had been
written, and the DI tags hung during 1984 to rebuild the ASCO
valves. General Electric Service Information Letter (SIL) 128
advises licensees that valve internal parts made nf Buna N
deteriorate with age, and recommends replacement of these
components at intervals of less than seven years. The licensee
policy has been to rebuild the valves listed in the SIL on a
five year interval. While SIL 128 does not expressly identify
the ARI valves, these valves also have internal components made
of Buna N. The two ARI valves were received January 10, 1980,
approximately six years and six months ago. In response to the
inspectors questions, the licensee scheduled the ARI valves
to be rebuilt prior to startup.
The inspector noted that the requirement to rebuild the
affected valves on a five year interval was not listed on the
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station preventive maintenance program. Because of the large
number of valves the rebuild effort is staggered over a number
of outages; completing a percentage of the valves each time.
In the past, individuals have informally tracked the work
progress. The licensee stated that a formal method of tracking
the valve rebuild program, including the ARI valves, would be
implemented.
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While reviewing the quality assurance records of
post-maintenance testing in the Document Control Center (DCC),
the inspector found that post-maintenance valve actuator
testing was neither maintained with the maintenance request
(MR) package nor filed under surveillance data sheet,
3.M.4-10C. .This was subsequently confirmed by the DCC staff.
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The inspector noted that post-maintenance test records, e.g.
local leak rate testing and motor operator testing, were not
always available in the licensee's document control center.
Although the records could ultimately be produced, the
inspector questioned whether the maintenance test results are
maintained as a quality assurance record (i.e., storage,
preservation, and safekeeping) and are processed into the
Nuclear Records Management System in a timely manner, as
required by the Boston Edison Company Quality Assurance Manual
(BQAM), Chapter 17. At the exit meeting, the licensee agreed
to review these concerns.
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Feedwater Check Valves - All four feedwater check valves were
removed for maintenance to correct excessive back leakage. It
was found while inspecting the valves for repair, that 17 of 32
wrist pin bushing tack welds may have been cracked. However,
none of the bushings, which permits rotation of the check valve
disk on the wris- pins, were able to be moved by hand. A
design change to eliminate the bushing tack welds for the Anchor
Darling feedwater check valves is planned prior to the valve
installation. At the exit meeting, the inspector questioned
the potential reporting requirement for this problem under 10
CFR 21. The acceptability of licensee actions is unresolved
(8C-25-03).
e. Surveillance Testing
The inspector observed tests to assess performance in accordance
with approved procedures and LCO's, test results, removal and
restoration of equipment, and deficiency review and resolution.
During followup of recent containment damper failures, described in
section 3.d of this report, the inspector reviewed the results of
several secondary containment isolation surveillance tests. Proce-
dure 8.M.2-1.5.8.4, Revision 12, Logic System Functional Test of
System B Standby Gas Treatment Initiation, Reactor Building Isolation,
and Outboard Drywell Isolation Valves, was performed on June 26, 1986.
During the test a secondary containment damper failed to fully close.
At that point the test was stopped. Neither restoration of the system
to normal nor independent verification of restoration were documented.
In addition, previous procedure verification steps were not completed
and the operating supervisor and watch engineer review of the test
results were not completed with abnormal test results properly docu-
mented. Failure to verify completed procedure steps and independently
verify restoration of the system following the test is a violation of
procedure 8.M.2-1.5.8.4.
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On July 10, 1986, the inspector observed during the performance of
PNPS Procedure 8.M.2-1.4.1, Revision 12 that the "K2s" and "K7s"
relays were not independently verified, as specified in the
procedure, in the restored energized position. These relays
provided input to the alarm and main steam isolation valve (MSIV)
closure logic, respectively. Upon questioning, the technician was
not aware of the necessity of independently verifying these relays.
Upon further investigation, the same surveillance procedure was
performed on April 5, 1986, and on May 7, 1986 without independent
verification'of the "K2s" and "K7s" relay restoration.
The inspector informed the licensee that failure to adequately
follow procedures as noted in the above examples, constitutes a
violation (86-25-04).
The inspector reviewed surveillance procedures associated with the
H202 analyzer system as described in section 3.b. Other surveillance
testing witnessed by the inspector during this reported period were
HPCI Condensate Storage Tank Level Channel Check, 8.M.2-2.5.6,
Revision 7, Strong Motion Accelerograph Functional Test, 8.M.3-10,
Revision 7, and Reactor Water Level Functional Test, 8.M.1-19. No
discrepancy was observed for these surveillances.
4.0 Review of Plant Events
a. Loss of 480 VAC Bus B-23 and Resulting Half Scrams
The power for Reactor Protection System (RPS) Motar Generator (MG)
set "A" is supplied from Motor Control Center (MCC) B-23. MCC B-23
is in turn supplied through 480 VAC load center breaker B306.
Several times during the report period breaker B-306 tripped,
resulting in loss of powar to RPS MG set "A" and a nalf scram.
Initial performance testing of breaker B306 did not reveal any
performance abnormalities. Supplementary testing at lower current
values identified erratic performance of the breaker overcurrent
trip devices. Preliminary indication is that a missing lock nut on
the "C" phase long time delay trip mechanism may be the cause. The
licensee has shipped all three breaker overcurrent trip devices to
the vendor for root cause analysis and will evaluate the generic
implications of any test results obtained. 1
b. Low Level Contamination of Onsite Sewage Tanks
On July 16, 1986, the reactor building auxiliary bay sewage ejector
pump tank was found to be slightly contaminated. This was
considered by the licensee as a potential unmonitored radioactive
material release path and the system was tagged out for repairs.
Also on July 16, 1986, the licensee initially determined that an
onsite septic tank contained radioactive Cobalt-60 at 1.1E-06
microcuries per milliliter. However, a second sample from this tank
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did not detect any radioactive contamination. Prior to the backup
sample the licensee performed a review which identified possible
sources of contamination into this tank.
The licensee samples the sewage tanks regularly, prior to removing
waste for shipment offsite. Licensee plans are in place for
decontamination of all onsite sewage tanks. Previous traces of
contamination had been detected in onsite sewage tanks and were
reviewed during NRC inspection 50-293/85-22. Sewage pumping trucks
are routinely checked for contamination prior to leaving site. No
activity has been detected in these trucks.
The inspectors aise noted that the licensee is performing a re-review
of IE Bulletin No. 80-10, " Contamination of Nonradioactive System and
Resulting Potential For Unmonitored, Uncontrolled Release to Environ-
ment". The inspectors will review the results of the licensee's
evaluation and any corrective actions during subsequent inspections.
c. ATWS Monthly Functional Test
On July 15, 1986, the licensee notified the NRC via the ENS
telephone line that functional tests for the ATWS (anticipated
transient without scram) system were not conducted in the manner
required by the technical specifications. Specifically, the
licensee's functional test, procedure 8.M.1-29, did not activate the
system primary sensors during the test. Instead, the test injected
test signals directly into the ATWS trip units. The technical
specification definition of instrument functional test requires that
,
the primary sensors be activated.
The technical specification test definition may not be appropriate
for the ATWS instruments because they are Rosement transmitters and
analog trip units. Because of the reliability of these instruments,
- the licensee believes that it is common practice to initiate monthly
functional tests at the trip units instead of the primary sensors.
The sensors are normally tested less frequently, i.e., every eighteen
'
months. This minimizes the chances of causing inadvertent reactor
scrams. The licensee is planning to modify the technical specifica-
tions to allow testing in this manner.
The inspector reviewed the QA deficiency report that identified the
'
problem, OR 1559, and the plant's response. The inspector also
verified that the ATWS functional tests were properly scheduled on
the stations Master Surveillance Tracking Program (MSTP). The
inspector discussed the testing problem with licensee personnel and
noted that a similar problem exists for the other analog-trip
devices currently installed, i.e., the scram discharge volume level
, -instruments. The licensee subsequently notified the NRC of the
discharge volume test inadequacy. The inspector had no further
i questions. This item is licensee-identified and will be reviewed
i
during future routine inspections.
I , ,_. - ,- _ _ .- - - - , .
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3
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d. Reactor Building Ventilation Sample Pump Failures
On July 17, 1986 the "A" reactor building sample pump tripped due to
pump motor failure. This pump and similar sample pumps are rebuilt
every 3 months because of a history of failures. The other reactor
building sample pump was started when the alarm for the pump trip
was received.
While reviewing the history of this tyoe of sample pump, it was
found that either the wrong number or no equipment number was used
to specify the reactor building sample pump on Maintenance Requests
(MRs) 85-4-68 and 85-628. The correct equipment numbers for the
reactor building sample pumps were P236A and P-2368 according to
1
drawing number M-287. This matter was discussed with the licensee
maintenance personnel.
e. 4160 VAC Safety Bus Undervoltage Relay Calibration Failures
On June 21, 1986 the licensee discovered that surveillance testing
of safety related emergency bus undervoltage relays was overdue. A
discussion of the circumstances leading to the problem is contained
in inspection report 35-21, section 7.0. Followup of the item will
be conducted under unresolved item 85-21-08 as stated in that
report.
,
On July 23, 1986 calibration of the subject relays identified that
eleven of the total population of twenty were outside the calibration
limit. The inspector questioned the acceptability of the current
calibration interval, given the high failure rate. An NRC special
team inspection 86-24, (generic letter 83-28 followup), is evaluating
the adequacy of the licensee's undervoltage protection and
surveillance.
During the review of undervoltage relays at Pilgrim, the inspector
noted that the Low Pressure Coolant Injection (LPCI) valves for both
LPCI loops are pnwered through the same 480 VAC lead center, B6.
Bus B6 can be supplied from either diesel generator through their
associated distribution systems. Two undervoltage relays are
installed on each of these two B6 power supplies. The undervoltage
relays will, if loss of the normal supply is sensed, transfer B6 to
its alternate supply. In order to complete this transfer 125 VDC
control power from bus D6 is required. Bus D6 can be supplied from
either 125 VDC battery "A" or "B". Like 480 VAC bus B6, an auto
transfer from the normal to alternate battery source on loss of
.
voltage is provided for 125 VDC bus D6. These two auto transfer
I functions are critical in supporting the licensees assumptions
regarding available ECCS in the accident analysis. The inspector
noted that these undervoltage relays / functions are not addressed by
technical specifications. Initial indications are that no station
calibration / test procedures are in place. The inspector was informed
_-__ . -, _
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4
that setpoints and testing of these components may be controlled by
the corporate relay test group. This group is not part of the
nuclear organization. The inspector will continue to evaluate the
acceptability of the technical specifications, control, calibrations
and testing of those components during the next inspection period
(86-25-05),
f. HPCI Area Unit Cooler Breaker Fire
On July 28, 1986 smoke was observed coming from breaker 52-1822 in
the reactor building. This breaker supplies power to a High
Pressure Coolant Injection (HPCI) pump compartment unit cooler.
Investigation determined that a circuit lead disengaged from its
terminal block and touched ground. A solid link had been installed
3
rather than a protective fuse in the control power circuit. Because ,
no fuse had been installed the fault was not cleared, and the
- control power transformer located in the breaker compartment burned
up. Control of the application of solid links and fuses is the
subject of an ongoing licensee engineering evaluation and is being
reviewed under unresolved item 86-01-03. Previous licensee
- indications were that installation of solid links was conservative
because loss of equipment due to spurious fuse failure was
'
i eliminated. In response to this incident the inspector pointed out
that a resulting electrical bus fire may not be conservative.
4
The loose lead which caused the fire became disengaged because the
terminal block to which it was secured was cracked. The licensee
'
stated that an examination of similar terminal blocks and an
evaluation of the cause of the cracking were being conducted. The
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inspector will review the licensees evaluation of this matter during
l a future inspection.
g. Protective Instrumentation Rack 2205 Upscale Drift
On July 31, 1986 the licensee noted that all reactor vessel level
instrumentation on instrurint rack 2205 was indicating high. This
instrumentation provides input to the reactor protection system,
emergency core cooling system initiation and primary containment
!
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isolation system. Indicated level discrepancy between the
instruments on rack 2205 and similar instruments on rack 2206 was
approximately 10 inches. Investigation by the licensee identified
that the reference leg common to all the affected instruments had
partially drained. Daily log information plotted by the inspector
indicates an increasing trend over a number of days for the
instruments in question. Pertinent valve lineups were checked, the
reference leg was backfilled and all indication returned to normal.
The licensee is currently monitoring instrument performance to
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detect any additional problems. The inspector had no further
questions.
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h. Hydrogen Recombiner Safety Evaluation
During the inspection period, the licensee noted that the NRC safety
evaluation dated April 30, 1986, which supports an exemption from
the hydrogen recombiner requirements of 10 CFR 50.44 (c)(3)(ii)
contained statements that did not accurately reflect the condition
of the plant. Specifically, the licensee noted that items 2.b.1 and
2.b.2 in the evaluation might not reflect actual practices at the
plant. These items involve (1) a requirement to shut the plant down
i within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if the nitrogen supply system (or an alternate
nitrogen system) is not operable and (2) the isolation of the
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instrument air system from the nitrogen supply system by a locked
closed valve.
The inspector discussed the safety evaluation with the licensee and
with the NRR Project Manager. At the end of the inspection period,
the licensee had not completed its review of this issue. This
review will determine which statements are inaccurate and the source
i (licensee or NRC) of any misinformation. The acceptability of the
licensee's actions are unresolved pending the completion of the
licensee's review (86-25-06)).
i 1. Intermediate Range Neutron Monitors
Based on a General Electric (GE) Rapid Information Communication
Services Information Letter (RICSIL) Number 007, the licensee
investigated and found an undetected failure mode of the neutron
intermediate range monitors (IRMs) that may not provide the reactor
protection system scram during startup. Specifically, loss of the
IRM negative power supply voltage will not cause an inoperable IRM
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trip card light, but will cause a signal output from the amplifier.
This causes the IRM to lock above the downscale trip and below the
upscale trip regardless of the actual core neutron flux.
'
, GE is examining a relay / contact modification, which would monitor
!
the IRM negative power supply and would initiate an inoperable trip
light if a loss of power occurs. The results of GE's final
recommendation will be in a GE Services Information Letter.
i The unit is currently in an outage and reactor power operations are
!
not anticipt.ted until the first quarter of 1987. The resolution of.
this problem will be reviewed during a future routine inspection
(86-25-07).
, 5.0 Observation of Physical Security
,
On July 23, 1986 the inspector received an anonymous allegation concerning
excessive security force overtime. On July 24, 1986 the inspector reviewed
security force time sheets for the period June 16, 1986 through July 20,
1986. This period began after the end of the Boston Edison labor union
, 4 m - - -m-+ < - - . - - , - -s.- e-*a - .- ,p
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15
strike. In order to focus on the routine schedules maintained by the
normal security guard force, time immediately before, during and after
the security force labor action of June 30, 1986 was not considered. A
summary of individual cases of excessive overtime identified is included
as Attachment II to this rerort.
The inspector noted during the review that security per:onnel routinely
work up to twenty-e'qht hours in a forty-eight hour period. Instances of
up to thirty-si. . cues in a forty-eight hour period were also identified.
One individual tm ked twenty-three of twenty-seven hours. The time
onsite for individuals in twenty-four and forty-eight hour periods is not
monitored by the licensee.
Cases of up to eighty-eight hours worked in a seven day period, with
individuals on duty as many as ten consecutive twelve hour days, were
identified. While the licenses does monitor time worked in a seven-day
period, only the seven-day periods starting Monday and ending Sunday are
reviewed.
The excessive number of security force overtime hours raises concern
regarding the ability of individuals to perform their function. The
inspector discussed these observations with licensee corporate and
station management. The licensee immediately reviewed the overtime
status for onshift security personnel and took steps to reduce or
eliminate the overtime problem. Security overtime was subsequently
discussed during an NRC Management meeting (50-293/86-26) and also
reviewed during a security specialist inspection (50-293/86-26). The
corrective actions will be reviewed during a future inspection
(86-25-08).
6.0 Radiation Protection and Chemistry
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.
,
7.0 Station Fire Barrier Deficiencies
During 1985 a series of fire barrier walkdowns were conducted to verify
that the required Appendix R barriers provide a minimum 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire
resistance. Nineteen specific deficiencies were identified. On July 2,
1986 a memorandum summarizing these deficiencies was transmitted from the ;
nuclear engineering department to the station. This memorandum '
recommended that compensatory fire watches be implemented. The results
of the walkdowns were received at the site on July 2,1986. On July 8,
1986 a Failure and Malfunction Report was initiated to officially ,
identify the problem and initiate corrective actions. The licensee is i
reviewing its records to determine whether compensatory fire watches were
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established in 1985. The inspector will review the individual discrepancies,
and any compensatory measures taken, to determine compliance with the
technical specifications during a future inspection (85-25-09).
Boston Edison Quality Assurance Manual (BEQAM) Section 16 establishes the
corrective action program, and requires that deficiencies be identified
and processed in accordance with Section 15 of the BEQAM. Section 15
states that nonconforning components are documented and reported via a
Failure and Malfunction Report (F&MR). PNPS procedure 1.3.24, Revision
12, Failure and Malfunction Reports states that an F&MR shall be
initiated whenever any abnormal plant condition has the potential to
adversely affect safe operations.
1
Timely and effective processing of an F&MR is important in establishing
operations staff awareness of potential or actual problems. Technical
specifications require establishment of a fire watch within one hour of
finding an inoperable fire barrier. Failure to effectively use the
corrective action program both as the individual discrepancies were
identified, and after the summary of discrepancies was compiled on
July 2, 1986, demonstrates a programmatic weakness. The inspector
informed the licensee that the above constitutes a violation of 10 CFR 50
Appendiv B (86-25-09).
8.0 Local Leak Rate Testing Status
During this reporting period, I type "B" as-found local leak rate test
(LLRT) failure was found. The outboard flange of the inboard drywell
purge exhaust valva had leakage greater than 20 sim. This leakage
will be quantified prior to its repair work. Also 3 type "C" as found
LLRT failures were found, i.e., the outboard drywell purge exhaust valve,
the inboard post accident sample system (PASS) return valve, and the
inboard drywell equipment drain valve. Between August 4,1986 and
April 11, 1986, 87 of approximately 101 type "B" components have been
tested with 2 failures, and 123 of approximately 133 type "C" components
have been tested with 15 failures.
During conduct of leak rate testing on the containment floor drain sump
isolation valves the inspector noted that while two LLRTs had been
performed on that day, no test cart bypass valve leak test had been
performed as required by procedure. This concern had been previously
identified by the inspector and discussed with licensee personnel. While
the significance of the incidents is minor, the licensees failure to
correct them raises concern. The inspector discussed this problem at the
exit meeting.
9.0 Independent Verification of Operating Activities
The inspector reviewed fifty eight administrative, operations,
maintenance, and surveillance procedures to determine if the licensee
established an acceptable system of verifying the correct performance of
.
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17
operating activities. The procedures were reviewed against Section
5.2.6, " Equipment Control", of ANSI N18.7, 1976 as supplemented by NUREG
0737 item I.C.6, " Guidance on procedures for verifying correct
performance of operating activities". The inspector determined that,
with the exception of the tagging procedure, the licensee had revised the
procedures to provide for independent verification. The inspector found
that precedure no. 1.4.5, "PNPS Tagging Procedure", Revision 16, was
inadequate in that it did not require independent verification when
hanging tags or during tag removal / equipment restoration. Similar
problems were also noted in inspections 50-293/85-03 and 86-06. The
licensee informed the inspector that a revision to the tagging procedure
was being prepared which would include independent verification of
tagging activities and the inspector was shown the proposed tag record
which would implement it. The inspector found the propcsed revision
acceptable and will review the revised tagging procedure in a subsequent
inspection.
The inspector also had a concern regarding the implementation of the
independent verification program. As noted in paragraph 3.e of this
report, a violation for failing to perform an independent verification
when required was identified. During discussions with licencee
personnel, the inspector also noted some confusion as to which systems
required independent verification. The inspector noted that procedure
no. 2.1.11, " System Lineup File", is the only procedure which identifies
systems requiring independent verification. However, this procedure is
used for valve lineups after refueling outages and is not used by other
than operations department personnel. The licensee acknowledged the
inspector's concern and indicated that the controlling administrative
procedure (procedure no.1.3.34 " Conduct of Operations") would be revised
to reference procedure 2.1.11. The licensee also indicated that
procedure no. 1.3.34 would be revised to include the management
objectives as stated in memorandum M85-137, Control and Verification of
Operating Actions, as additional guidance on implementation of the
independent verification program.
The inspector informed the licensee that the revised 1.3.34 and 1.4.5
procedures would be reviewed during a subsequent inspection and would be
necessary to complete the licensing action review for NUREG 0737, item
I.C.6.
10.0 Review of LER's
LER's submitted to NRC:RI were reviewed to verify that the details were
clearly rerorted, 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
86-13 5/30/86 6/30/86 Use of non-seismic CFD
relays for D/G
differential protection
1
86-14 6/10/86 7/9/86 Insufficient once per
cycle RCIC surveillance ,
procedure '
86-15 6/13/86 7/14/86 Primary containment
local leak rate test i
frequency
86-16 6/21/86 7/21/86 Bus AS, Bus A6, and
Startup degraded >
' voltage relay
calibrations overdue'
The following deficiencies in LER 86-13, "Use of Non-Seismic General
Electric Type CFD Relays", were noted:
--
The LER indicates that operator action will be initiated by
non-seismically qualified annunciators after a seismic event.
--
The LER did not clearly indicate that a General Electric evaluation
of a short-term station blackout was not completed until 1986, two
years after the relay problem was identified.
--
The LER indicated that no failure (presumably spurious activation)
of the CFD relays had occurred in thirteen years. However, this
statement may be inaccurate because spurious activations of the
relays would probtbly not have been logged.
This event was also reviewed during NRC inspection 86-14. l
The event described in LER 86-14, " Primary Containment Local Leak Rate
Test Frequency", was discussed in NRC inspection 50-293/86-21. The
adequacy of licensee surveillance test scheduling methods is currently l
unresolved and will be tracked under open item 86-21-08. The inspector l
noted two deficiencies with the LER:
--
The LER stated that containment local leakage tests were previously ,
scheduled on a " program basis". However, the scheduling method '
(i.e., " program basis") was neither explained nor justified in the
'
LER. This description is needed to explain why there was an
apparent conflict between the licensee's scheduling method,10 CFR
50 Appendix J scheduling requirements, and technical specification
scheduling requirements.
. .
____
. - .- -
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--
The technical specifications have two definitions of ope : ting
cycle. The LER only mentions the less restrictive defin. Lion
(definition "0"). The leakage tests in question were not overdue
using this definitior.. However, if the more restrictive definition
(definition "U") is used, the tests would have been overdue. The
LER should justify using the less restrictive case.
The licensee stated at the exit meeting that the deficiencies identified
by the inspector would be reviewed and the LER's appropriately updated.
]
! The events described in LER 86-16, " Bus A5, Bus A6, and Startup Degraded
Voltage Relay Calibrations Overdue", were initially reviewed during NRC
inspection 50-293/86-21. A followup review is descr9,ed in Section 4.e
,
of this inspection report. No problems were identified. An LER update
will be required if the as-found calibrations of the relays are outside
the plant design bases.
11.0 Confirmatory Action Letter 86-10 Update
Attachment III lists followup NRC questions concerning issues in
Confirmatory Action Letter (CAL) 86-10. These questions were discussed
'
between the licensee and the inspector. The preliminary licensee
response was also discussed during a telephone call on July 31, 1986
between the licensee, the inspector, and Region I management. At that
time, the licensee agreed to submit a written response to the questions
to Region I within 30 days of the telephone call. The response will be
reviewed during future followup of CAL 86-10.
O
12.0 Congressional Staff and NRC Commissioner Visits to Pilgrim
1
Members of the congressional staffs of Un,ited States Senator Kennedy,
Senator Kerry, and Congressman Studds toured the Pilgrim site on July 10,
1986. They met with Boston Edison representatives and the Pilgrim
.
resident inspectors during the afternoon. A congressional heering
!
concerning problems at Pilgrim and selected other U.S. power reactors was
held the following week.
L'
l' On July 14, 1986, NRC Commissioner J. Asselstine and the NRC Region I
Administrator, Dr. T. Murley, also toured the Pilgrim site. Prior to the
tour, they met with the Pilgrim resident inspectors, Boston Edison
officials and local public officials. Commissioner Asselstine held a
press conference at the end of the day. Among the topics discussed
during the tour were deficiency stickers located by the control rod
select panel in the control room, the status of preventative mainterance
for the onsite liquid nitrogen storage tank, and the status of
preoperational testing of the air filtration system for the Emergency
Offsite Facility (EOF). Licensee plans for completing required fire
protection modifications were also reviewed.
4
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The deficiency stickers in the control room indicated that maintenance
requests had been issued to repair control rod position indication probes
(PIPS). These problems were generally limited to one or two positions on
an individual control rod. The inspectors had previously verified that
the control rod position problems had not prevented the licensee from
conducting required control rod scram tests. The Pilgrim technical
specifications allow PIP's to be out of service as long as redundant
nuclear flux instrumentation is operable.
The licensee indicated that the PIP problems were scheduled to be fixed
during the next refueling outage, when all PIP connectors undervessel
would be changed out. At the time of the discussions, the next refueling
outage was scheduled to start in January 1987. The licensee justified
not fixing the PIPS during the current shutdown, because much of the work
would have to be duplicated during the subsequent PIP connector
changeout, causing over 10 person-rem of duplicated radiation exposure.
The inspector questioned whether some of the indication problems, e.g. ,
no full-in indication, could be caused by faulty light sockets in the
control room. These problems could be fixed immediately. The licensee
rev'ewed the work and stated that the sockets were functioning normally
indicating that the problems will require undervessel repairs. Based on
a review of the maintenance requests and discussions with the licensee
about the nature and scope of planned undervessel work, the inspector
agreed with the licensee's decision to defer the PIP maintenance until
the PIP connectors are changed out.
Subsequent to their announcement to extend the current outage into 1987
BECO decided to fix the PIP problems prior to restart.
13.0 Management Meetings and Meetings with Local Groups
At neriodic 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 July 30, 1986 a meeting between Region I and Boston Edison senior
management was conducted at Region I offices in King of Prussia. The
purpose of the meeting was to discuss licensee management program
improvements and plans for the upcoming plant outage. The meeting is
summarized in NRC Inspection Report 50-293/86-26.
The Pilgrim Senior Resident Inspector addressed a special meeting of the
Plymouth Area Chamber of Commerce on July 23, 1986. The meeting was held
at the request of the Board of Directors of the Chamber of Commerce to
discuss recent activities at Pilgrim. Representatives from Boston Edison
and a local public interest group, Plymouth County Nuclear Information
Committee, also participated in the meeting. The meettna was held in
Memorial Hall in Plymouth.
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j Attachment I to Inspection Report 50-293/86-25
Persons Contacted
L. Oxsen, Vice President, Nuclear Operations ,
j, *A. Pedersen, Nuclear Operations Manager
l P. Mastrangelo, Chief Operating Engineer
j D. Swanson, Nuclear Engineering Department Manager
i K. Roberts, Director Outage Management
.
N. Brosee, Maintenance Section Head
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
i B. Eldridge, Acting Chief Radiological Engineer
R. Sherry, Chief Maintenance Engineer
- J. McEachern, Resource Protection and Control Group Leader
i E. Graham, Compliance and Administrative Group Leader
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{ * Senior licensee representative present at the exit meeting.
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- - - .n , - - . a - - - - - , a-- u... , _ --
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, Attachment II to Inspection Report 50-293/86-25
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Security force overtime records were reviewed for the period of June 16 to
July 20, 1986. Overtime hours worked in connection with the security force
and Boston Edison union strikes were not included.
A. Seven Day Work Period
Work Period Hours Worked Comments
6/19 - 6/25 84 This individual worked 10
consecutive 12-hour days
6/20 - 6/26 84
6/20 - 6/26 84
6/20 - 6/26 88 This individual worked 8
twelve and one 16-hour days
consecutively
7/3 - 7/9 80
7/3 - 7/9 80 A single individual in two
-
7/10 - 7/16 80 consecutive weeks
,
7/5 - 7/11 78
7/5 - 7/11 88
7/5 - 7/11 88
<
7/6 - 7/12 76
7/11 - 7/17 80
B. Two Day Work Period
i
Work Period Hours Worked Comments
, 7/6 - 7/7 32
7/14 - 7/15 36 This individual worked 39
hours in a 51-hour period
7/18 - 7/19 32 This individuai worked 40
- hours in a 56-hour period ;
6/16 - 7/20 28 During the period specified 14
different individuals worked l
28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> in a 4,-iour period '
C. fwenty-four Hour Period
.
Work Period Hours Worked Comments
'
7/14 - 7/15 20 In a 27 hour3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br /> period this
individual worked 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />'
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ATTACHMENT III
NRC QUESTIONS REGARDING THE SUPPLEMENTAL RESPONSE -
TO CAL 86-10
The following is a list of comments and questions from NRC Region i
about the BECo supplemental response letter, dated June 16, 1986, to
CAL 86-10. This list was given to the licensee on July 21, 1986.
1. Has BECo evaluated the merits of periodic checks of RHR
system pressure and temperature after (1) startups, (2)
any RHR system high pressure alarm, or (3) after the
leakoff system is initially placed in service? Also, has
BECo considered periodic checks of RHR system pressure
in the absence of high pressure alarms?
2. The first paragraph of BECo's response to NRC question
"e" describing the proposed leakoff method appears to
differ from the method in procedure TP 86-85 and should
be clarified. The paragraph infers that the bypass valve
will be opened during a measurement step, closed, and
reopened to establish the leakage path.
3. Will a reactor shutdown just be intitiated or will the
plant be shutdown (pending an engineering evaluation) if i
the 1.0 gpm limit is exceeded? Also, has BECo considered
evaluating leakage rates above 1.0 gpm now; rather than
waiting to conduct the evaluation until the leakage limit
is exceeded?
4. The BECo response and the associated safety evaluation
state that leakage into the RHR system will not be
allowed to exceed 1.0 gpm. This is not strictly true,
since the measured parameter will be leakage through the
bypass valve at 150 psig. Changes in RHR check valve
leakage (such as after a pump has been operated) could
make the leakoff measurements inaccurate and misleading.
Has this been considered? Has BECo considered tracking
the leakage rate into the torus over extended periods of
time as a method of verifying stable RHR system
inleakage?
The safety evaluation also states that all RHR pump flow
will go into the RHR system. However, some flow could be ,
diverted through the leakoff path if the "D" pump is idle
(LPCI only requires 3 pumps operate). BECo should
consider modifying the safety evaluation to address these
two Concerns.
5. The data sheet to procedure TP 85-A2 requires that an RHR
pump suction block valve (MO-1001-7D) be closed during
the initiation of a controlled leakage path but not
reopened (although the procedure does require this). Why
has the latter step been left off the data sheet?
6. The acceptance criteria for tests of the RHR injection
check valves are not included in the response, as
requested (NRC question "f"). The criteria should be
determined and submitted to Region I.
7. The RHR pressure guage calibration frequency was stated
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to be "once per refueling outage" in the response to
question "h." This frequency is not defined in the
technical specifications. How is it defined and what is
the justification for the frequency?
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8. The calibration histories of the RHR high system pressure
alarm switches (PS-1001-74A and B) should be submitted to
Region I. How is the proposed calibration frequency,"once
per cycle," defined and justified?
9. Will the 1001-28 or 29 valve on the "A" RHR loop be
maintained normally closed? Procedure TP 86-84 indicates
that the -28A valve will be left closed, but the licensee
has previously indicated that the 28A will be open and
the 29A closed.
10. What is the accuracy and reliability of the temperature
measuring markers? What specific change in temperature
will require that additional measurements be taken with a
portable measuring device? What are the accuracy and
reliability of the portable temperature measuring device?
11. Will the licensee verify seating of the RHR check valves
after operation? If not, why not?
12. Why will it take 9 months to submit a technical
specification change to reduce compensatory surveillance
testing in LCO's; considering that the issue was
identified mid-1985 in connection with the on-line EQ
modifications and also noted in the 1985 SALP report? Has
the licensee considered contacting other facilities of a
similar age to see if they have information that could be
used to speed the evaluation and submittal process?
13. What is the justification for limiting RHR pipe
temperature to no less than 15 degrees of saturation
temperature? Is this temperature margin adequate,
considering that pipe wall temperature (rather than
interior water temperature) is the measured parameter?
14. Calculation M-269 should be submitted to Region I for
review.
15. The following comments concern the draft procedure TP
86-81 which will control the test for spurious group I
primary containment isolations during the neFl reactor
startup.
-- Will reactor level instrument vibration be
monitored? If not, why not?
-- Step VI.A indicates that the reactor mode switch
will be placed in run for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Why?
-- Was a functional test be conducted of the PCIS
logic after the GETARS modification was installed?
What procedure was used for the functional test?
-- Can the spurious isolation test be conducted at a
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power below the stated 30%?
16. Does BECo plan to conduct a sampling review of other
systems, given the large number of drawing / loose wire
problems discovered during werk on the reactor mode
switch?
17. Why is local venting of the RHR system needed in addition
to the keep fill system?
18. Is the RHR system always filled and vented after the
1001-34 and -36 valves are opened to depressurize the
system?
19. Has BECo considered the personnel safety aspects of the
leakoff measu>ement process? At what location will system
pressure be measured and what will be the expected water
pressure at the measuring point? Will the measurement,
equipment withstand this water pressure?
20. Has BECo considered testing the leakage of injection
check valves in ECCS systems other than LPCI?
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