ML20150C076
| ML20150C076 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 02/22/1988 |
| From: | Butcher R, Dance H, Mathis J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20150C055 | List: |
| References | |
| 50-416-87-40, 50-417-87-04, 50-417-87-4, NUDOCS 8803170317 | |
| Download: ML20150C076 (13) | |
See also: IR 05000416/1987040
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET, N.W.
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ATLANTA, GEORGI A 30323 -
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Report No.:
50-416/87-40 and 50-417/87-04
Licensee:
System Energy Resources, Inc.
Jackson, MS 39205
Docket Nos.:
50-416 and 50-417
License Nos.:
NPF-29 and CPPR-119
Facility Name:
Grand Gulf
Inspection Condycted:
Decerr.ber 19, 1987 - January 15, 1988
>[p/fV
. Inspectors:
e
M
R. C. Butchec Senior Resident Inspector
Date Signed
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.Mathis[8esidentInspector
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Approved by:
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'H. C. Dance, Section Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine inspection was conducted by the resident inspectors at
,
the site in the areas of Licensee Action on Previous Enforcement Matters,
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Operational Safety Verification, Maintenance' Observation, Surveillance
Observation, ESF System Walkdown, Reportable Occurrences, Operating Reactor
Events, Inspector Followup and Unresolved Items, Compliance with the ATWS Rule,
10 CFR 50.62, Refueling Activities, Startup from Refueling, Fastener Testing
Per TI 5200/26, Design Changes and Modification, and Verification of
Containment Integrity.
Results:
One violation was identified:
Failure to determine normal indicated
delta pressure and set HPCS system, LPCS system, and LPCI subsystems
instrumentation as required by Technical Specifications.
8803170317 880222
ADOCK 05000416
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REPORT DETAILS
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1.
Licensee Employees Contacted
J. E. Cross, GGNS Site Director
C. R. Hutchinson, GGNS General Manager
R. F. Rogers, Manager, Special Projects
- A. S. McCurdy, Manager, Plant Operations
J. D. Bailey, Compliance Coordinator
M. J. Wright, Manager, Plant Support
L. F. Daughtery, Compliance Superintendent
- D. G. Cupstid, Start-up Supervisor
R. H. McAnuity, Electrical Superintendent
J. P. Dimmette, Manager, Plant Maintenance
W. P. Harris, Compliance Coordinator
- J. L. Robertson, Licensing Superintendent
L. G. Temple, I & C Superintendent
J. H. Mueller, Mechanical Superintendent
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L. B. Moulder, Operations Superintendent
J. V. Parrish, Chemistry / Radiation Control Superintendent
S. M. Feith, Director, Quality Programs
- S. F. Tanner, Manager, Quality Services
- D. L. Pace, Manager, Nuclear Design
Other licensee employees contacted included technicians, operators,
security force members, and office personnel.
- Attended exit interview
2.
Exit Interview (30703)
The inspection scope and findings were summarized on January 15, 1988,
with those persons indicated in paragraph 1 above.
The licensee did nc
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identify as proprietary any of the materials provided to or reviewed by
the it!spectors during this
inspection.
The licensee stated that more
review is required before they agree or disagree with the iinspection
findings:
416/87-40-1. Violation.
Failure to determine normal indicated delta
pressure and set HPCS system, LPCS system and LPCI subsystems instrumenta-
tion as required by TS 4.5.1.c.2 (b).
(paragraph 4 )
3.
Licensee Action on Previous Enforcement Matters (92702)
Not inspected this report period.
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4.
Operational Safety, Radiological Protection and Physical Security
)
Verification (71707, 71709 and 71881)
The inspectors kept themselves informed on a daily basis of the overall
plant status and any significant safety matters related to plant
operations.
Daily discussions were held with plant management and various
members of the plant operating staff.
The inspectors made frequent visits to the control room such that it was
R
visited at loast daily when an inspector was on site.
Observations
included instrument readings, setpoints and recordings, status of
operating systems, tags and clearances on equipment controls and switches,
annunciator alarms, adherence to limiting conditions for operation,
temporary alterations in effect, daily journals and data sheet entries,
control room manning, and access controls.
This inspection activity
included numerous informal discussions with operators and their
supervisors.
,
Weekly, when the inspectors were onsite, selected Engineered Safety
Feature (ESF) systems were confirmed operable.
The confirmation is made
by verifying the following: Accessible valve flow path alignment, power
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supply breaker and fuse status, major component leakage, lubrication,
cooling and general condition, and instrumentation.
General plant tours were conducted on at least a biweekly basis.
Portions
of the control building, turbine building, auxiliary building and outside
areas were visited.
Observations included safety related tagout
verifications, shift turnover, sampling program, housekeeping and general
plant conditions, fire protection equipment, control of activities in
progress I problem identification systems, and containment isolation.
The
licensee s onsite emergency response facilities were toured to determine
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facility readiness.
The inspectors reviewed at least one Radiation Work Permit (RWP), observed
health physics management involvement and awareness of significant plant
activities, and observed plant radiation controls.
The inspectors
verified licensee compliance with physical security manning and access
control requirements.
Periodically the inspectors verified the adequacy
of physical security detection and assessment aids.
On January 9,
1988 the licensee initiated Material Nonconformance
Report (MNCR) 0015-88 documenting that the Low Pressure Core Spray
(LPCS)/ Residual Heat Removal (RHR) A line break annunciator alarmed at 80
percent power during startup from refueling outage number 2.
While
continuing up in power the reactor scrammed at about 93% power (see
writeup in paragraph 9).
Before the reactor scram, the MNCR describes
several things were being done to verify the actual differential pressure
was being measured.
The differential pressure being measured is from the
LPCS injection line to the RHR A line downstream of the injection valves
which should give close pressure readings unless thereais a line break in
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either line within the downcomer region.
Technical Specification 3.5.1,
which is applicable for Operational Conditions 1, 2 and 3, action
statement g requires that with an ECCS header delta P instrumentation
channel inoperable, restore the inoperable channel to operable status
within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or determine ECCS header delta P locally at least once per
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, otherwise declare the associated ECCS inoperable.
Technical Specification 4.5.1.c.2.(b) requires every 18 months performing a channel
calibration of the header delta P instrumentation and verifying the
setpoint of the HPCS system, LPCS system and LPCI subsystems to be 1.2 +
0.1 psid change from the normal indicated delta P.
Research by the
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licensee indicates that G.E. Service Information Letter (SIL) 300 issued
in September 1979 and IE Circular No. 79-24 dated November 26, 1979
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addressed the installation and testing of pipe break detection systems and
recognized that the systems would be calibrated to' read near zero delta P
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during cold shutdown and would possibly alarm during reactor startup.
The
alarm should clear when approaching rated power indicating that the
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instrumentation is working.
This would make the pipe break detection
system effective only near rated power.
This guidance does not appear to
be reflected in TSs.
The Final Safety Analysis Report has a brief
description of the HPCS and LPCS/RHR A line break detection systems only.
High Pressure Core Spray is described in paragraph 7.3.1.1.1.3.11.2 and
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LPCS/RHR A is described in paragraph 7.3.1.1.1.5.11.2.
The RHR B/RHR C
line break detection system is not mentioned.
The licensee has not
determined what is the normal delta P for the LPCS/RHR A lines.
The
instrumentation setpoint as specified in Surveillance Procedure
06-IC-1E31-R-0021, Revision 23, LPCS/RHR/HPCS Header Differential Pressure
Calibration, was based on original calculations.
Technical Specification 4.5.1.c.2 (b) requires that every 18 months a channel calibration of the
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header delta P (nstrumentation setpoints be verified for the HPCS system,
LPCS system and LPCI subsystems to be 1.2 + 0.1 psid from the normal
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indicated delta P.
Failure to determine the normal indicated delta P and
verify the HPCS system, LPCS system and LPCI subsystems setpoints to be
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within 1.2 + 0.1 psid of normal is a violation 416/87-40-01.
The NRC
Project Msniiger was requested to determine an interpretation of the
meaning of normal indicated delta pressure in TS 4.5.1.c.2(b).
He stated
the normal indicated delta pressure should be determined while at normal
,
rated power.
This supports the previously discussed SIL and IE Circular.
5.
Maintenance Observation (62703)
During the report period, the inspectors observed portions of the
maintenance activities listed below.
The observations included a review
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of the Maintenance Work Orders (MW0s) and other related documents for
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adequacy, adherence to procedure, proper tagouts, adherence to technical
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specifications, radiological controls, observation of all or part of the
actual work and/or retesting in progress, specified retest requirements,
and adherence to the appropriate quality controls.
MWO # I80322 Rework loop controls; replace potentiometer module and
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pushbutton switch modules on P680 panel.
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MWO # M80346 Open condenser, perform a leakage inspection and plug tubes
that are leaking.
No violations or deviations were identified.
6.
Surveillance Observation (61726)
The inspectors' observed the performance of portions of the surveillances
listed below.
The observation included a review of the procedure for
technical adequacy, conformance to technical specifications, verification
of test instrument calibration, observation of all or part of the actual
surveillances, removal from service and return to service of the system or
components affected, and review of the. data for acceptability based upon ,
the acceptance criteria.
06-0P-1P41-Q-0004, Revision 24, Standby Service Water Loop A Valve & Pump
Operability Test.
06-RE-SC11-V-0402, Revision 26, Control Rod Scram Testing.
06-0P-1E51-R-0005, Revision 26, RCIC Pump Low Pressure Flow Verification
Test-
06-IC-1821-M-0014, Revision 21, Safety Relief Valve -Tail Pipe- Pressure
Switch Function Test.
06-ME-1M10-R-0003, Revision 25, Drywell Bypass Leakage Rate.
06-0P-1E51-Q-0002, Revision 28, RCIC System Valve Operability Test.
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06-IC-1C71-R-0013, Revision 25, Reactor Mode Switch Interlocks Functional
Test.
06-0P-1821-R-0002, Revision 26, ADS /SRV Valve Operability.
06-ME-1M23-V-0001, Revision 28, Containment and Drywell Airlock Seal Leak
Te~s t.
No violations or deviations were identified.
7.
Engineered Safety Features System Walkdown (71710)
A con,plete walkdown was conducted on the accessible portions of the
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The walkdown consisted of an inspection and
verification, where possible, of the required system valve alignment,
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including valve power available and valve locking where required,
instrumentation valved in and functioning; electrical and instrumentation
cabinets free from debris, loose materials, jumpers and evidence of
rodents, and system free from other degrading conditions.
No violations or deviations were identified,
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8.
Reportable Occurrences (90712 & 92700)
The below listed event reports were reviewed to determine if the
information
provided
met. the
NRC
reporting
requirements.
The determination included adequacy of event description and corrective
action.taken or planned, existence of potential generic problems and the
relative safety significance of each event. Additional inplant reviews and
discussions with plant-personnel as appropriate were conducted for the
reports indicated by an asterisk. The event reports were reviewed using
the guidance of the general policy and procedure for NRC enforcement
actions, regarding licensee identified violations.
The following License Event Reports (LERs) are closed.
LER No.
Event Date
Event
- 87-019
November 17, 1987
Heavy Load Transported Over New
Fuel In The Upper Containment Fuel
Pool.
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- 87-005
April 15, 1987
Three Main Steam Line Radiation
Monitors
Exceed
Technical
Specification Trip Limit.
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- 87-020
November 19, 1987
Shutdown Cooling Isolation Due To
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a Blown Fuse.87-022
December 7, 1987
RWCU Isolation Due To a Blown
Fuse.
The event of LER 87-019 was discussed in Inspection Report 416/87-35.
The even't of LER 87-005 is discussed in paragraph 13 of this report.
The event of LER 87-020 was discussed in Inspection Report 416/87-35.
No violations or deviations were identified.
9.
Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed
reactor events.
The review included determination of cause, safety
significance, performance of personnel and systems, and corrective action.
The inspectors examined instrument recordings, computer printouts,
operations journal entries, scram reports and had discussions with
operations, maintenance and engineering support personnel as appropriate.
On December 19, 1987 at approximately 8:48 p.m. during performance of I&C
Surveillance procedure 06-IC-1821-R-0004-1, Main Steam Line Isolation
Valve Closure Calibration, a full scram was received.
The reactor was in
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cold shutdown (refueling mode) with all rods in.
During the surveillance
upon closing Main Steam Isolation Valve (MSIV) F022A a full scram occurred
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instead of the expected 1/2 scram in Division 2.
Upon investigation by
the licensee it was found that the fuse (IC71-F11A) reinstalled in step
5.29 of data sheet III for MSIV F022A was signed off by one I&C technician
and verified by another I&C technician as to being installed.
The
licensee determined that fuse IC71-F11A ' popped out of its holder which
would give a 1/2 scram for Reactor Protection System (RPS) Division 1.
In
preparation for closing of MSIV F022A, fuse C71-F118 was pulled out in
step 5.30.
This set up conditions for a 1/2 scram in RPS. Division 2 upon
the closing of MSIV F022A.
Therefore, when F022A was closed a full scram
occurred.
Incident Report (IR) Number 87-12-14 was written to document
this event.
On January 10,1988 at 3:08 p.m. the reactor scrammed from 93.5 percent
reactor power.
Investigation by the licensee determined that a phase
differential from the 8 main transformer initiated a turbine trip which
initiated a reactor scram.
No Emergency Core Cooling Systems (ECCSs)
injected and water level decreased to approximately -2.5 inches.
Reactor
pressure reached an indicated 1109 psig initiating an ATWS recirculation
pump trip.
No safety-relief valvas lif ted.
The phase differential fault
was caused by the failure of the 8 transformer.
Upon investigating the
transformer problem the licensee was forced to stay down for at least 4
days after scramming to replace the failed transformer and bring on line
the spare transformer.
This activity is covered by the following MWD
packages:
E80383, E80384, E80427, E62703, E72878, E80375, E74336, E80326,
and E80276.
The inspectors followed the replacement of the spare transformer. The
spare transformer was already installed adjacent to the normal 3 main
transformers and only required hardware type changes to tie into the
existing generator leads. The licensee plans to use one of the 3
transformers from unit 2 as a spare by removing the failed transformer and
installing the unit 2 transformer in its place. Limiting Condition for
Operation (LCO)88-035 was initiated on three low low set valves whose
proper operation was originally questioned.
It now appears that the low
low set logic for Channel A and Channel 8 trip units tripped but
corresponding channels E and F trip units did not trip so no safety relief
valves lifted.
This indicated proper relief valve operation and the LC0
was lifted. The reactor was taken critical on January 13,1988 at
5:45 p.m.
in preparation for connecting onto the grid. The reactor was
synchronized to the grid at 9:53 p.m. on January 15, 1988.
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On January 11,1988 at 7:15 a.m. a reactor scram occurred due to low water
level.
The reactor was in hot shutdown at 310 psig at the time of the
event.
Operators noticed the reactor vessel water level was increasing
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and the set pressure was decreasing causing the bypass valve to open.
Reactor pressure decreased to approximately 270 psig before the operators
could manually stop the set pressure decrease.
Reactor water level then
decreased to approximately 9 inches resulting in a reactor vessel low
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water level scram.
This incident was documented by the licensee in
Incident Report ' Number 88-1-6.
The licensee initiated Maintenance Work
Order (MWO) 1803322 to rework loop controls and to replace potentiometer
module and pushbutton switches on P680 panel.
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Ne violations or deviations were identified.
10.
Inspector Followup and Unresolved Items (92701)
(Closed) Inspector Followup Item 416/87-22-03.
The licensee issued
Licensee Event Report (LER) 87-009-01 clarifying the use of an existing
bypass switch which will allow bypassing the Reactor Water Cleanup (RWCU)
isolation logic.
System Operating Instruction (SDI) 04-1-01-G33-1 has
been revised to delete the reference to an anticipated group 8 isolation.
An engineering review is being performed to determine the amount of time
the present 45 second automatic bypass time delay can be extended and the
licensee will submit a change request when an allowable time limit is
determined.
11.
Compliance With the ATWS Rule, 10 CFR 50.62 (25020)
.
The inspection requirements of TI 2500/20 were addressed previously in
Inspection Reports 416/87-23 and 416/87-35.
During this inspection period
the inspectors witnessed the testing of the work performed by DCP 85/4053.
The testing of the modifications done to the Standby Liquid Control System
to meet 10 CFR 50.62 acceptance criteria was controlled by Modification
Special Test Instruction (MSTI) IC41-87-002-0-S.
The test was divided
into the following sections.
Section 7.1 of test MSTI 1C41-87-002-0-5 flushed the SLC system as
required to ensure only reactor grade water will be pumped to the reactor.
.
Section 7.2 stroked the valve IC41F008, in which modifications were made
during this outage, and compared remote indication with actual position.
Section 7.3 demonstrated the capability of the SLCS to deliver the Boron
solution to the reactor at the required two pump flow rate without
exceeding the calculated pump operating pressure. Both pumps was operated
inthenormalinjectionlineup.
Section 7.4 demonstrated that the required discharge pressure was
enveloped by the 1300 psig Technical Specification discharge pressure.
Pump discharge pressure of at least 1300 psig was achieved by throttling
pump discharge valves and flow was verified to be at least 82.4 gpm with
both SLCS pumps operating.
Section 7.5 verified that each pump produced a flowrate of at least 41.2
gpm with at least 1300 psig discharge pressure.
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The portions. of MSTI 1C41-87-002-0-S witnessed by the inspector consisted
of pump flow capacity test for SLC pump A and B, SLC pump A and B were
simultaneously started by closing both the installed test switches on
panel 1H22-P011.
Throttle valve 1C41-F221 was slowly closed to achieve a
stable pressure greater than or equal to 1300 psig.
Pump discharge relief
valves (1C41-F-029A & B) were then verified _ to have not lifted.
The
combine discharge flow of SLC pump A and B were measured to be 82.5 gpm.
In addition to the combined pump flow capacity test, the inspector
witnessed the single pump flow test for both the A and B pumps.
The
recorded pump discharge flows for pump A and B were 44 gpm and 46 gpm
respectively.
The remaining portions of MSTI 1C41-87-0002-0-5 were
reviewed for conformance to the acceptance criteria.
12.
Fastener Testing To Determine Conformance With Applicable Material
Specifications (25026) - Unit 2 Only
This inspection was conducted on Unit 2 per Temporary Instruction 2500/26
to ensure fasteners selected in response to NRC Bulletin 87-02 are
representative of installed fasteners and that suspect fasteners are
selected for testing.
Ten non--safety related studs, bolts and/or
cap /or capscrews and ten safety related nuts were to be selected fromscrews; te
and
stock for testing.
The inspector participated in the licensee's selection
of samples required by action item 2 of Bulletin 87-02 for Unit 2.
The sample selected was based, in part, from the types and grades of
fasteners utilized on Unit 2 to date and the test laboratory (Wyle)
requirements that the fasteners had to be 1/2 inch diameter or larger and
a minimum length of 3 x the diameter.
All fasteners were procured as
safety related except the non-safety related bolting as identified in the
sample was supplied as part of the non-safety related structural steel
purchased as part of the contract for erection of the turbine building.
From interviews with licensee personnel the following proportion of use of
fasteners was determined:
Type and Grade
Percent Use (approx)
Nuts:
SA-307, Gr. A
5
SA-194, Gr. 7
5
- SA-194, Gr. 2H
45
SA-307, Gr. B
15
- A -325
25
A -563, Gr. D
5
Bolts: SA-307, Gr. A
5
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SA-307, Gr. B
15
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Studs #A -325
30
- A -490
10
SA-193, Gr. B7
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- Also procured as non-safety related for turbine building
erection.
Based on the above figures, the following fastener sampling was agreed to:
SAFETY RELATED BOLTS / STUDS
SAMPLE I.D.
ITEM DESCRIPTION
HEAD MARKING
GGNS-U2-1
1 1/8" x 6 1/2" Stud Bolt SA193 87
87, T, FX65
GGNS-U2-2
7/8" x 5 1/2" Stud Bolt SA193 B7
B7, T, LA73
GGNS-U2-3
5/8" x4 3/4" Stud Bolt SA193 B7
B7, C, K2
GGNS U2-4
1/2" x 5 1/2" Stud Bolt SA193 87
87, C, C2
GGNS U2-5
1/2" x 4 1/4" HHH Bolt SA307-B
TB, 1Q39
GGNS U2-6
5/8" x 3 1/4" HHH Bolt SA307-B
TB, IF15
GGNS U2-7
1" x 4 1/2" HHH Bolt SA 307-B
TB, HD40
GGNS U2-8
1" x 4 1/4" HHH Bolt A325
RBW, A325
GGNS U2-9
1" x 8 1/2" HHH Bolt A325
TB, A325
GGNS U2-10
7/8" x 5" HHH Bolt A490
TB, A490
GGNS U2-11
1/2" x 3" HHH Bolt A307 GR-A
TB,IQ53
SAFETY RELATED NUTS
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SAMPLE I.D.
ITEM DESCRIPTION
HEAD MARKING
GGNS-U2-1A
1 1/8" HH Nut SA194 2H
2HT, 0211
GGNS-U2-2A
7/8" HH Nut SA194 2H
2HK, C4
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GGNS-U2-3A
5/8" HH Nut SA194-2H
2HU, K6
GGNS-U2-4A
1/2" HH Nut SA194-2H
2HT, 0253-
GGNS-U2-5A
1/2" HH Nut SA307-B
T, HD73
GGNS-U2-6A
5/8" HH Nut SA307-8
T, 1F18
GGNS-U2-7A
1" HH Nut SA307-8-
T, HD46
GGNS-U2-8A
A" HH Nut A325
Three Circ. Lines
,
GGNS-U2-9A
1" HH Nut A325
Three Circ. Lines
!
GGNS-U2-10A
7/6" HH Nut SA194-2H
2H, S, V,
GGNS-U2-11A
1/2" HH Nut A 307 GR-A
7,
IQ54
GGNS-U2-12A
1 1/8" HH Nut SA 194 GR-7
C, Y1, 01, 7
GGNS-U2-13A
2 3/4" HH Nut A563 GR-D
T, D
NON SAFETY RELATED BOLTS
SAMPLE I.D.
ITEM DESCRIPTION
HEAD MARKING
GGNS-U2-A (2)
3/4" x 3 1/4" HHH Bolts A490
A490,SBC
GGNS-U2-8 (2)
3/4" x 3 1/4" HHH Bolts A325
A325,SB 1
GGNS-U2-C (2)
1" x 5" HHH Bolt A325
A325,RBW
.
GGNS-U2-D
1" x 5" HHH Bolt A325
A325,RBW
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GGNS-U2-E
3/4" x 3 1/4" HHH Bolt A490
A490, SB
GGNS-U2-F (2)
3/4" x 3" HHH Bolt A490
A490, S8
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NON SAFETY RELATED NUTS
SAMPLE I.O.
ITEM DESCRIPTION
HEAD MARKING
GGNS-U2 A ~ (2)
3/4" HH Nuts A194-2H
P2H
GGNS-U2-B-1 (2)
3/4" HH Nuts A325
Three Cire. Lines
GGNS-U2-01 (2)
1" HH Nut A325
Three Circ. Lines
GGNS-U2-01
1" HH Nut A194-2H
Three Circ. Lines
GGNS-U2-El
3/4" HH Nuts A325-2H
2H, P
GGNS-U2-F1 (2)
3/4" HH Nut A194-2H
2H, P
The inspectors verified that each fastener was tagged with identifying
sample number, description, and heat code / material type.
In addition, the
inspector verified that each sample was put in a separate plastic bag
along with the NRC supplied Fastener Testing Data Sheets.
13.
Design, Design Changes and Modifications
(37700)
The inspectors reviewed the following design change for conformance with
the requirements of TS and 10 CFR 50.59.
Design Change Implementation
Package (DCIP) 84/0160, Revision 0, replaced the existing INMAC Main Steam
Line (MSL) log radiation monitors with NUMAC log radiation monitors.
Licensee Event Report 87-005-02 documented the problem the licensee was
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experiencing with an instrument drift problem with the existing equipment.
Technical Specification 3.3.2-2.2.b requires the MSL high radiation trip
setpoints to be set less than 3 times full power background with an
allowable value of 3.6 times full power background.
The instruments
provide a reactor scram signal, a mechanical vacuum pump trip signal and
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an MS' isolation signal if the high radiation sigiial is reached in a one
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two taken twice logic.
The inspectors verified the.
folic, . .ig:
a) The licensee reviewed and approved the design changes in
accordance with TS and approved procedures.
b) The design change had been
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properly documented and an approved evaluation per 10 CFR 50.59 was
perforrted,
c) Design change retests were accomplished within procedural
tiec requirements and results were satisfactory.
d) The operating
procedures were modified to reflect the design change,
e) The new MSL
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radiation monitors were fully operable and operators were familiar with
taking data for operating logs.
The following maintenance work packages were reviewed to determine if they
included applicable specifications, guides and coces covering the work;
identification of required inspections or retests and QA/QC requirements.
MWP 87/1239
REWORK PANEL H13-P669
MWP 87/1240
REWORK PANEL H13-P671
MWP 87/1241
REWORK PANEL H13-P670
MWP 87/1242
REWORK PANEL H13-P672
No violations or deviations were identified.
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14.
Verification of Containment Integrity (61715)
The inspectors verified that the licensee established primary containment
integrity following cold shutdown for the refueling outage.
Ten primary
containment penetrations were verified to be correctly aligned by local
observation where available and by remote indication.
The primary
containment upper and lower air lock seal leak tests were witnessed by the
inspectors and the Standby Gas Treatment System was walked down to verify
operability.
See paragraph 6 for the containment airlock seal leak test
and paragraph 7 for the Standby Gas Treatment System walkdown.
No violations or deviatt 's were identified.
15.
Refueling Activity (60710)
The refueling outage for cycle two was previously reported in Inspection
Reports 416/87-29 and 416/87-33.
Reactor vessel reassembly started on
,
December 20, 1987.
The reactor vessel head tensioning was completed on
December 22, 1987 in accordance with the procedure 06-CP-1813-V-0001.
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Following the head tensioning the reactor mode switch was placed in
shutdown.
The inspector verified that surveillances required to be
completed prior to entering shutdown mode of operation were completed.
On December 29, 1987, the inspectors witnessed portions of procedure
>
06-ME-1M10-R-0003, Revision 25, Drywell Bypass Leakage Rate, performed by
the licensee.
The test determines the drywell leakage with the drywell
pressurized to approximately 3 psid and verifies that the drywell bypass
leakage is less than or equal to 3500 scfm.
This tese is required to be
performed at least once pur 18 months in accordance with T.S. 4.6.2.2.
The test result for the drywell leakage was approximately 1500 scfm.
The
inspector calculated the leakage independent of the licensee and got the
same value.
There were no deficiencies associated with this test.
No violations or deviations were identified.
16.
Plant Startup From Refueling (71711)
Startup for Unit 1, Cycle 3 started on January 3,1988. The reactor mode
switch was placed to startup at 5:30 p.m.
on January 3,1988. The
controlling procedure for startup, Integrated Operating Instruction (I0I)
03-1-01-1, was reviewed by the inspectors to verify that startup was being
conducted in accordance with technically sound and approved procedures anc'
to assure that they had been revised to reflect changes made to the
facility and to the start-up testing program.
The following precritical
i
test were witnessed by the inspector:
a.
Control Rod Scram Testing (06-RE-SC11-V-0402)
b.
Reactor Mode Switch Interlocks Functional Test (06-IC-1071-R-0013)
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Criticality for cycle 3 was achieved on group 2, gang 6 position 26 at
3:54 a.m. on January 4,1988.
The reactor coolant temp;rature recorded
was 146.25 F.
The calculated Shutdown Margin was determined to be 1.586
(%$ K/K). The inspector verified that criticality was achieved in a
controlled manner.
No violations or deviations were identified.
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