ML18086B065
| ML18086B065 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/04/1981 |
| From: | Greenman E, Hill W, Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18086B062 | List: |
| References | |
| 50-272-81-25, 50-311-81-25, NUDOCS 8111250552 | |
| Download: ML18086B065 (19) | |
See also: IR 05000272/1981025
Text
U. S. NUCLEAR REGULATORY COMMISSION
OFFICE OF INSPECTION AND ENFORCEMENT
(DCS Numbers - see
attached sheet)
Report Nos.
Docket Nos.
License Nos.
Licensee:
REGION I
50-272/81-25
50-311/81-25
50-272
50-311
___
P_ub_l_i_c_S_e_r_v_ic_e_E_le_c_t_r_ic_a_n_d_G_a __
s_C_o_m~p_an~y.__ ___ ,
80 Park Plaza
Newark, New Jersey
07101
Faci 1 i ty Name: ___
s_a l_e_m_Nu_c_l_e_ar_G_e_ne_r_a_t_i n_.g.__.St_a_t;._i ....
o,;..;.n _-_...;..U.;..;.ni_* t_s_l _a_n_d_2_
Inspection At: ___
H_an_c_o __ c_ks::.-..-B-..r .... i d;;.;..g._e..._,-'N.-e;.,;.;w_J"'-e;;;.;;.r-.s'"""ey..._ _______ _
1981
Inspectors:
- Norrholm, Senior Resident Inspector
..
ff. m. ~,)-r.
W. M,)~11, Jr0~nspector
Approved By: __
C_cc:x._~
___
/0}___,.__*~___,..._
____________ _
E. G. Greenman, Chief, Reactor Projects Section No. 2A,
Projects Branch No. 2, DRPI
Inspection Summary:
.
OCT 2 8 1981
date
OCT 2 8 1981
date
JJ,/y:fi;
date
Inspections on September 15 -
October*19~ *1981 *ccombined Report.Numbers 50-272/81-25
and 50-311/81~25}
Unit 1 Areas Inspected: Routine inspections by the resident inspectors of plant
operations including tours of the facility; conformance with Technical Specifications
and operating parameters; log and record review; reviews of licensee events; and
followup on previous inspection items.
The inspection involved 67 inspector-hours
by the resident NRC inspectors.
Results:
One item of noncompliance was identified (Failure to post an airborne radio-
act1v1ty area - paragraph 10).
Unit 2 Areas Inspected: Routine inspections by the resident inspectors of plant
operations including tours of the facility; conformance with Technical Specifications
and operating parameters; log and record review; review of licensee events; and
followup on previous inspection items.
The inspection involved 73 inspector-hours
by the resident NRC inspectors.
Results:
No items of noncompliance were identified.
( 8111250.552 811105 \\j
1
PDR ADOCK 05000272
1. _ ~ _ _ _
. _ _ _ _
~ PP~
REPORT NOS.
50-272/81~25 and 50-311/81-25
DCS NUMBERS
050272-811017
050272-810703
050272-810708
050272-810720
050272-810813
050272-810722
050272-810826
050272-810809
050272-810902
050272-810903
050272-810824
050272-810827
050272-810903
050272-810915
050272-810918
050272-810827
050311-810921
050311-811007
050311-811012
050311-811016
050311-811018
050311-810702
050311-810716
050311-810708
050311-810709
050311-810713
050311-810714
050311-810806
050311-810720
050311-810721
050311-810723
050311-810724
050311-810725
050311-810722
050311-810727
050311-810729
050311-810803
050311-810807
050311-810810
050311-810901
050311-810903
050311-810812
050311-810814
050311-810817
050311-810913
050311-810817
050311-810823
050311-810825
050311-810918
050311-810828
050311-810829
DETAILS
1. Persons Contacted
J. Driscoll, Chief Engineer
L. Fry, Station Operating Engineer
J. Gallagher, Assistant Maintenance Engineer
S. LaBruna, Maintenance Engineer
H. Midura, Manager - Salem Generating Station
L. Miller, Station Performance Engineer
J. O'Connor, Radiation Protection Engineer
F. Schnarr, Reactor Engineer
R. Silverio, Assistant to the Manager
J. Stillman, Station QA Engineer
The inspector also interviewed other licensee personnel during the course
of the inspections including management, clerical, maintenance, operations,
performance and quality assurance personnel.
2. Status of Previous Inspection Items
(Closed} Unresolved Item (272/77-23-11} Calculation of RCS leak rate using
containment air particulate and gaseous measurement.
The inspector
reviewed Operating Instruction (OI} II.1.3.5, Reactor Coolant Leak
Detection, Revision 4, dated August 6, 1981. The procedure ade-
quately describes available techniques for quantifying leak rate.
With respect to the use of containment activity monitors, no attempt
is made to quantify.
Instead, an action level is defined at which
further investigation is initiated to determine the source and rate.
The inspector had no further questions on this item.
(Open}
Unresolved Item (272/81-01-06} Status of fire doors.
During tours
of the facility, the inspector noted that a number of doors which
were part of fire zone boundaries and which would not be effective
in mitigating the spread of fire due to fouling or standing open.
In each case, the degraded condition of the boundary had apparently
persisted for some time, and had not been compensated for by a fire
watch or patrol. Based on most recent surveillance data and the
fire alarm status panel, fire detectors in the areas were operable.
The following situations were noted. Applicable fire boundaries
were identified from the referenced drawings.
Unit
Date/time
Door/condition
DWG. No.
1
October 2, 1981/0900
Relay Room - Penetration Area
240868
elevation 100 1 door tied open
and clocked
1
October 8, 1981/1445
Relay Room - Penetration Area
240868
elevation 100 1 door blocked open
by pipe cap
Unit
2
Date/time
October 8, 1981/1445
3
Door/condition
DWG. No.
Relay Room - Penetration Area
240868
elevation 100' door blocked open by
ladder
-
2
October 15, 1981 /1500
Service Building - Auxiliary
240867
lOpenl
(Open)
Building elevation 88 1 flood door
standing open.
In addition, the
Unit 2 stairwell-14-line corridor
door was standing open.
The above boundaries are also described in the licensee's August
24, 1977 document entitled,
11Fire Protection Program Review For
Salem Nuclear Generating Station Unit 2 In Response To Branch
Technical Position 9.5-1.
11
The above situations were brought to station management attention
immediately. Since the inspector could not determine how long the
doors had been open, compliance with Technical Specification 3.7.11
could not be ascertained based on these observations. This item
remains unresolved pending further review *
Unresolved Item (272/80-32-01) Termination criteria for charging
pump following a steamline break (reference IE Bulletin 80-18).
By correspondence dated July 14, 1981 the licensee has supplemented
the original Bulletin response and has committed to modification
of mini-flow valve control logic such that the valves will not shut
automatically on safety injection. Changes, including procedures
and training, will be completed during the next refueling outage
for Unit 1 and the next sufficiently long outage on Unit 2. This
item remains open pending completion of these actions.
Unresolved Item (311/80-12-02) Controls over instrument isolation
valves in line between cabinet and root valves. To effect permanent
corrective action for this item, the licensee has initiated design
changes 1 SC-574 and 2 SC-570 to install system valve identifications
on these valves. The valves will then be included in system valve
lineups to preclude instrument isolation. Interim administrative
measures have been effective in preventing recurrence of inadvertent
instrument isolation. This item remains open pending completion of
the above design changes and inclusion of the valves in operating
lineups *
4
SITE
3. Shift Logs and Operating Records
a.
The inspector reviewed the following plant procedures to determine the
licensee established requirements in this area in preparation for a
review of selected logs and records.
AP-5, Operating Practices, Revision 10, May 21, 1980;
AP-6, Operational Incidents, Revision 7, October 13, 1981;
AP-13, Control of Lifted Leads and Jumpers, Revision 4, February
11, 1980;
Operations Directive Manual; and,
AP-15, Safety Tagging Program, Revision 1, November 21, 1980.
b. Shift logs and operating records were reviewed to verify that:
Control room log sheet entries are filled out and initialled;
Auxiliary log sheets are filled out and initialled;
Log entries involving abnormal conditions provide sufficient detail
to communicate equipment status, lockout status, correction and
restoration;
Log book reviews are being conducted by the staff;
Operating orders do not conflict with Technical Specification
requirements;
Incident reports detail no violation of Technical Specification LCO
or reporting requirement; and,
Logs and records were maintained in accordance with Technical
Specifications and the procedures in 3.a above.
c. The review included examination of the following plant shift logs and
operating records and discussions with licensee personnel:
Log No. 1 - Control Room Daily Log, September 15 - October 19, 1981
Log No. 6 - Primary Plant Log, September 15 - October 19, 1981
Log No. 7 - Secondary Plant Log, September 15 - October 19, 1981
5
Log No. 8 - Unavailable Equipment Status Log, September 15 - October
19, 1981
Night Orders, September 15 - October 16, 1981
Lifted Lead and Jumper Log - All active
Tagging Requests - All active (Unit 2)
Nonconformance Reports for August and September 1981
Incident Reports81-148, 179, 181, 183, 185, 189, 190, 193, 194, 196,
199-203, 205-207, 212-214, 216, 219, 221, 225-233, 235, 244, 245,
251, 253-254, 256-258, 260-262, 282, 283, 286, 296, 304.
The inspector had no questions relative to logs reviewed during this
inspection period.
4.
Plant Tour
a.
During the course of the inspections, the inspector made observations
and conducted multiple tours of plant areas, including the following;
(1)
Contra l Room (daily)
(2)
Relay Rooms
(3)
Auxiliary Building
(41
Vital Switchgear Rooms
(5)
Turbine Building
(6)
Yard Areas
(7)
Radwaste Building
(8)
Penetration Areas
(9)
Control Point
(10) Site Perimeter
(11)
Fuel Handling Building
(12) Containment
(13) Guard *House
6
b.
The following determinations were made:
Monitoring instrumentation. The inspector verified that selected
instruments were functional and demonstrated parameters within
Technical Specification limits.
Valve positions. The inspector verified that selected valves were
in the position or condition required by Technical Specifications
for the applicable plant mode. This verification included examination
of control board indication and field observation of selected valves
in safety related systems.
Radiation Controls. The inspector verified by observation that
control point procedures and posting requirements were being followed.
An item identified during the inspection is noted in paragraph 10.
Plant housekeeping conditions. The inspector observed that house-
keeping was generally acceptable.
Any cluttered or littered area\\'.\\(
for which maintenance was not in progress, was brought to the attention
of the plant management or operating staff.
Fluid leaks. The inspector confirmed that corrective action had been
initiated for any leaks identified by station personnel.
No leaks
were observed that had not previously been identified by station
personnel.
Piping vibration.
No excessive piping vibrations were observed and
no adverse conditions were noted.
Selected pipe hangers and seismic restraints were observed and no
adverse conditions were noted.
Equipment tagging. The inspector selected plant components for which
valid tagging requests were in effect and verified that the tags were
in place and the equipment in the condition specified.
'By frequent observation through the inspection, the inspector verified
that control room manning requirements of 10 CFR 50.54 (k) and the
Technical Specifications were being met.
In addition, the inspector
observed shift turnovers to verify that continuity of system status
was maintained. The inspector periodically questioned shift personnel
relative to plant conditions and their knowledge of emergency procedures.
Releases.
On a sampling basis, the inspector verified that appropriate
documentation, sampling, authorization, and monitoring instrumentation
were provided for effluent releases *
\\
7
Fire protection. The inspector verified that selected fire exting-
uishers were accessible and inspected on schedule, that fire alarm
stations were inspected on schedule, that fire alarm stations were
unobstructed and that cardox systems were operable.
Parag~aph 2
details observations relative to fire doors.
Technical Specifications. Through log review and direct observa-
tions during tours, the inspector verified compliance with Technical
Specifications including Limiting Conditions for Operation {LCO's).
The following parameters were sampled frequently:
RWST level, BAST
level and temperature, containment temperature, boration flow path,
shutdown margin, offsite power.
In addition, the inspector conducted
periodic visual checks of protective instrumentation and inspection
of electrical switchboards to confirm availability of safeguards
equipment.
Security. During the course of these inspections, observations
relative to protected and vital area security were made, including
access controls, boundary integrity, search, escort, and badging.
d.
The following acceptance criteria were used for the above items:
Technical Specifications
Operation Directives Manual
Inspector Judgement
e.
The inspector had no further questions relative to tours made during this
inspection.
5.
Review of Periodic and Special Reports
a.
Upon receipt, periodic and special reports submitted by the licensee
pursuant to Technical Specifications 6.9.1 and 6.9.2 were reviewed by the
inspector.
This review included the following considerations:
The report included the information required to be reported by NRC
requirements;
Test results and/or supporting information were consistent with design
predictions and performance specifications;
Planned corrective action was adequate for resolution of identified
proolems; and,
Determination whether any information in the report should be classi-
fied as an abnormal occurrence.
8
Within the scope of the above, the following periodic reports were re-
viewed by the inspector:
Unit 1 Monthly Operating-Reports - August - September 1981
Unit 2 Monthly Operating Reports - August - September 1981
b.
During the review of September operating reports, the inspector noted the
following discrepancies; the cover letter erroneously identified the
reports as October monthly operating reports, and the next refueling
date for unit 1 is listed as October 31, 1981 instead of the projected
date of November 28, 1981. These items were brought to the attention of
station management for correction.
To confirm the completed station design changes listed in these reports,
the inspector reviewed a computer status listing of outstanding design
modifications., To comply with 10 CFR 50.59, the licensee reports com-
pleted design changes to NRC in the monthly operating report when the
package has been signed off as complete.
The inspector identified
several packages which were complete but not signed off, and therefore
not reported.
Examples are:
lEC-0538, power to backup heaters; 1EC-0841A,
PSA snubbers and RHR pump struts; lEC-1009, tube lane blocking device.
These modifications had been made within the last year. The inspector
further noted that several additions to design change packages have,:been
made.
Some of these additions are comprised of
11minor
11 work and are
issued as revisions to the original package.
As an example, revisions to
design change 2EC-738 added additional hangers to the original package
after approval oy the Station Operations Review Committee (SORC).
Work
has oeen performed as described in these revisions, but the revisions have
not received SORC approval.
Completion of design change packages and approval of minor work require
further review by the inspector. These items are unresolved (272/81-25-01)
pending completion of this review.
6.
Licensee Events
a.
In Office Review of Licensee Event Reports
The inspector reviewed LERs submitted to the NRC:RI office to verify that
details of the event were clearly reported, including the 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 involved, and whether the event warranted
onsite followup.
The following LERs were reviewed:
UNIT 1
81-69/03L
81-70/03L
81-71/03L
81-72/0lT
81f 73/03L
81-74/0lT
8l-75/03L
81-76/0lT
81-77 /OlT
81-78/0lT
81-79/03L
81-80/03L
81-81/03L
81-82/03L
UNIT 2
8I-54/03L
81-55/03L
81-56/03L
81-57/03L
81-58/03L
9
Component Cooling Water Flow Control Valve Inoperable
Hydrogen Analyzer Inoperable
Loss of Containment Fan Coil Unit Service Water Flow
Indication due to Silt
Service Water Leak in No. 12 and No. 14 Containment Fan
Coil Units due to Cooler Failures
Containment Pressure Channel 1 Inoperable
Service Water Leak in Containment due to No. 11 CFCU
Cooler Failure
Loss of No. 13 Containment Fan Coil Unit Service Water
Flow Indication due to Silt
Service Water Leak in Containment due to No. 14 CFCU
Cooler Failure
Service Water Leak in Containment due to No. 11 CFCU
Cooler Failure
Service Water Leak in Containment due to No. 11 CFCU
Cooler Failure
Missed surveillance - Triaxial Time-History Accelerographs
No. 13 Containment Fan Coil Unit Inoperable due to Service
Water Leak in Penetration Area
Individual Rod Position Indicators Inoperable
Breached Penetration Fire Barrier
No. 21 Containment Fan Coil Unit Inoperable due to Low
Service Water Flow
No. 21 CFCU Service Water Flow Indication Low due to Silt
Reactor Coolant System Leak Detection System Inoperable
Auxiliary Feedwater Storage Tank Level Less Than 200,000
Gallons
Boric Acid Storage Tank Low Level During Cooldown
UNIT 2
81-59/03L
81-60/03L
81-61/U3L
81-62/03L
81-63/03L
81-64/0lT
81-65/U3L
81-66/03L
81-67/03L
8l-68/U3L
81-69/03L
81-70/03L
81-71/03L
81-72/03L
81-73/03L
81-74/03L
81-75/03L
81-76/03L
81-77/03L
81-78/03L
81-iZ9/03L
81-80/03L
10
Pressurizer Overpressure Protection System Channel 2
Inoperable Due to Leaking Valves
No. 21 Reactor Coolant Loop Flow Channel 1 Inoperable
Individual Rod Position Indicators Inoperable
Reactor Coolant.System Leak Detection System Inoperable
No. 22 Steam Generator Feed Flow Channel 2 and No. 24
Steam Generator Steam Flow Channel 2 Inoperable
Service Water Leaks in Containment due to No. 22 CFCU Valve
and Motor Cooler Leaks
No. 23 Steam Generator Feed Flow Channel 2 Inoperable
Failure of Two Vital Heat Trace Channels
No. 21 Diesel Fuel Transfer Pump Inoperable
Individual Rod Position Indication Inoperable
No. 24 Steam Generator Steam Flow Channel 1 Inoperable
No. 2B Diesel Generator Inoperable due to Ground on
Annunciator Panel
Unidentified Trips of No. 22 CSD Breaker
Solid State Protection System Train B Inoperable
2Cl Battery Charger Inoperable
Tave Less Than 541 Degrees During Operational Transient for
6 Minutes
Radiation Monitor 2R11A Inoperable
No. 24 Reactor Coolant Flow Channel 2 Inoperable
No. 22 Reactor Coolant Flow Channel 2 Inoperable
Individual Rod Position Indication Inoperable
Unidentified Trip of No. 22 CSD Breaker
Individual Rod Position Indication Inoperable
-~
UNIT 2
81-81/03L
81-82/99X
81-83/03L
81-84/03L
81-85/0lT
81-86/0lT
81-87/03L
81-88/03L
8l-89/03L
81-90/0lT
81-91/03L
81-92/03L
81-93/03L
81-94/0lT
81-95/03L
81-96/03L
11
2A Diesel Generator Start Time Failures
Inadvertent Safety Injections Following Reactor Trips
Containment Air Lock Elevation 100 1 Inoperable
Reactor Coolant System Leakage in Excess of 10 GPM Due To
Valve Packing Leakage
Failure to Wrap Cable as Required by Interaction Study and
Facility Operating License DPR-75
No. 21 Steam Flow Channels 1 and 2 Inoperable
2Bl 28-Volt DC Battery Charger Inoperable
2C Diesel Generator Inoperable
No. 23 Auxiliary Feedwater Pump Inoperable
Service Water Leak in Containment due to No. 22 CFCU Cooler
Failure
Missed Surveillance - Turbine Overspeed Protection System
Pressurizer Level Channel 1 Inoperable
Reactor Coolant System Leak Detection System Inoperable
Service Water Leak in Containment due to No. 23 CFCU
Pressurizer Pressure Channel 1 Inoperable
No. 21 Steam Generator Steam Flow Channel 2 Inoperable
b.
Onsite Licensee Event Followup
(1) For those LERs selected for onsite followup (denoted by asterisks in
detail paragraph 6a), the inspector verified the reporting requirements
of Technical Specifications and Regulatory Guide 1.16 had been met, that
appropriate corrective action had been taken, that the event was reviewed
by the licensee as required by AP-4, 6, and 7, and that continued operation
of the facility was conducted in accordance with Technical Specification
limits. The following findings relate to the LERs reviewed on site:
UNIT 1
--
81-69/03L
--
81-73/03L
81-71/03L
8l-75/U3L
81-72/0lT
81-74/0lT
81-76/0lT
81-77/0lT
81-78/0lT
12
Flow control valve 12SW127, a hollow ball sea.ling against
an open-ended tube bundle, was repaired by cutting back
the damaged tube bundle surface. Further evaluation by
the valve vendor is underway, and the results will be sub-
mitted in a supplemental report. This item is unresolved
pending review of the supplement (272/81-25-02).
Containment pressure channel 1 spiking was attributed to
a nearpy steam leak. Once the leak was contained and
diverted from the transmitter, output monitoring by brush
recorders confirmed that the channel spiking had stopped.
During the course of the review, the inspector identified
no confirmation of transmitter operabil i.tY. This item
remains unresolved pending further inspectio~ and review
of channel calibration data and procedures (~72/81-25-03).
Loss of Containment Fan Coil Service Water flow indication
has been attributed to silt deposition in sensing lines.
The licensee has established a regular program of blowing
down lines which is triggered by the Inspection Order
system.
The frequency has been increased to weekly, and
the licensee is evaluating further resolution of this
recurring problem.
Each of these reports details a minor, typically less than
1 gpm, service water leak in containment due to pin-hole
perforation in a cooler tube. The leaks are usua~:ly iden-
tified through sump pump operation monitoring. Corrective
action in each of these instances consisted of blanking
the cooler bundle on the service water side and returning
the unit to service. The licensee has corrunitted to re-
placing tube material during the next outage (reference
unresolved item 272/81-05~06).
The inspector also reviewed the acceptability of blanking
tube bundles and the impact on operability of CFCU's.
Each CFCU is equipped with 6 primary and 6 secondary cooling
coils.
FSAR Section 6.3.1.8 states that each6fan coil unit
has a design heat removal capacity of 81 x 10 BTU/hr.
The
design basis therefore requires tnat the three wors~ fan
coil units have a heat removal capacity of 243 x 10 BTU/hr.
PSE&G Engineering Memorandum SGS/M-SE-031 dated November 17,
1978,provides an analysis of the acceptable cooling coil
loss to support operability of the system. A maximum of 3
coils per unit can be blanked and no more than 2 in a bank
(primary or secondaryJ. This6configuration yields a heat
removal capacit~ of 79.4 x 10 BTU/hr.
Two blanked coils
yield 86.1 x 10 BTU/hr.
--
81-79/03L
--
81-81/03L
UNIT 2
81-55/03L
81-59/03L
13
When reviewed on October 13, 1981 the following status was
detennined:
- 11 CFCU
- 12 CFCU
- 13 CFCU
- 14 CFCU
- 15 CFCU
- 21 CFCU
- 22 CFCU
- 23 CFCU
1t24 CFCU
- 25 CFCU
2 Secondary 1 Primary coil blanked
1 Primary coil blanked
No coils blanked
2 Secondary coils blanked
No coils blanked
No coils blanked
1 Primary coil blanked
1 Primary coil blanked
No coils blanked
No coils blanked
The worst three combination(:'.: (#11, 12, and 1~) yields an
acceptable heat rejection rate of 257.1 x 10 BTU/hr.
The
inspector had no further questions on this item at this time.
The issue of missed Technical Specification Surveillance
tests is addressed in NRC Inspection Report 50-272/81-23 as
an item of noncompliance.
The licensee's response was not
yet received at the conclusion of this inspection period.
The inspector reviewed the licensee's practices with regard
to calibration of individual rod position indication. For
each control rod, a unique curve of secondary voltage as a
function of rod position has been developed. For subsequent
recalibration of panel meters, full stroke calibration of
the rod is not conducted unless secondary voltage has changed.
Panel meter calibration over the entire range can theni:be
accomplished by applying corresponding secondary test voltages
to the signal conditioning module.
As required by Technical
Specifications and as a confinnation of actual position, flux
maps are taken at the specified frequency.
These actions
were also confirmed on a sample of the events listed.
Refer to discussion of Unit 1 LER 81-71/03L above.
Valve 2PR7 (PORV block valve) was closed due to a leak
through 2PR2 (PORV), rendering POPS channel 2 inoperable.
All subsequent actions were consistent with Technical Speci-
fications. The leaking valve will be repaired during the
next refueling outage and a supplemental report submitted.
This item is unresolved pending review of the supplemental
report (311/81-25-01).
- -
UNIT 2
81-61/03L
81-68/03L
81-78/03L
81-80/03L
81-64/0lT
--
81-66/03L
81-71/03L
81-79/03L
81-76/03L
81-77/03L
--
81-81/03L
14
Refer to discussion of Unit 1 LER 81-81/03L above
These service water leaks on No. 22 CFCU were repaired
within the time frame allowed by Technical Specifications
and did not involve blanking of coils as described for
Unit 1 LER 81-72/0lT above.
The inspector verified that procedure SP(O) 4.5.4.2(a)
had been changed as described in the LER by pennanent
on-the-spot change P-4 dated August 14, 1981.
The licensee
is continuing to evaluate minimum acceptable current read-
ings for short tapes. This item is unresolved pending
review of the supplemental report (311/81-25-02).
These trips of vital bus 4KV breakers are attributed to
SEC voltage sensitivity problems previously identified
(reference unresolved item 311/81-19-04). Recent investi-
gation has identified probable causes related to SEC power
supply design and induced interactions from pure water
transfer pump starts. A design modification has been pro-
posed by the vendor. Supplemental reports will be submitted
for these LER's.
The inspector will monitor resolution of
this item during the routine inspection program.
Due to the almost concurrent failure of these two flow trans-
mitters, the inspector questioned whether a common failure
mechanism existed. Discussions with I&C personnel revealed
that the specific failure modes were different and could not
be identified to a common cause. The inspector had no
further questions.
The inspector confirmed, through log review, that 2A Diesel
Generator was immediately declared inoperable at 5:05 a.m.
on August 14, 1981, when it failed to meet 10 S'ecor:rd start
requirements.
In accordance with Technical Specification 3.8.1.1.a, start times of 2B and 2C Diesel Generators were
confirmed within 5 minutes. Atb6:41 a.m., No. 2A Diesel
was successfully started following air system repairs, and
the Action Statement was cleared at 7:42 a.m.
The inspector
had no further questions.
,_,
--
81-82/99X
81-84/03L
81-85/0lT
81-86/0lT
81-88/03L
--
81-89/03L
81-90/0lT
81-94/0lT
81-91/03L
15
The inspector confirmed that the licensee had made stated
procedural changes to prevent recurrence of the safety
injections detailed in this report. Operating Instruction
(OI) III-10.3.1, Auxiliary Feedwater System Operation, has
been changed, in both units, to incorporate step 3.14 which
now requires cycling the sp~ed demand three times following
a shut down of No. 13/23 AFW Pump.
The inspector had no
further questions on this item.
These events are discussed in NRC Inspection Report 50-311/
81-21.
Inoperability of 2C Diesel Generator resulted from removal
of the prelube pump.
Subsequent vendor information revealed
that failure to provide prelubrication in excess of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
would probably result dn a slow diesel start. The inspector
noted that the operating shift did not have a detailed
listing of diesel support equipment which could cause in-
operability. The determination is left to the shift super-
visor based on experience and system knowledge. This item
is unresolved pending further review by the inspector
{311/81-25-03).
Through discussions with personnel and review of preventive
maintenance schedules, the inspector determined that the
loose linkage bolts were discovered during a scheduled annual
visual inspection of the pump and turbine. This inspection
is conducted for the specific purpose of identifying potential
wear and vibration problems.
The inspector had no further
questions on this item.
Refer to discussion of unit 1 LER 81-72/0lT above.
Refer to discussion of unit 1 LER 81-79/03L above
The inspector had no further questions with respect to LER
1s reviewed.
7. Operation Summary
Unit 1
At 2:00 p.m. on October 17, a reactor/turbine trip occurred due to a low level
in No. 11 Steam Generator following a .. loss of No. 11 Main Feed Pump (low suction
pressure).
Equipment troubleshooting did not identify any mechanical or elec-
trical faults.
16
Although improper operation of the Condensate Polishing System (CPS) can
cause low pressure at the suction of the feed pump, the licensee has not
specifically identified this as the cause for the trip. The licensee has
performed several tests involving the Condensate Polishing System (changing
resin beds) to determine if routine operation is contributing to the low
pressure at the feed pump suction. The tests indicate that the pressure is
affected and operation of the CPS may be a contributing factor. The licensee
has also installed strip recorders to monitor selected parameters in the
condensate and feed systems to further isolate the cause for low feed pump
suction pressure.
The inspector will monitor this item as part of the routine inspection
program.
The unit was returned to service at 6:26 a.m. on October 20.
Unit 2
At 11:46 p.m. on September 21, the unit was removed from service to effect
repair/modifications to the moisture separators in the steam generators.
At 4:23 p.m. on October 7, the unit was returned to service following a
maintenance outage for modification to the moisture separators.
On October 12, a moisture carryover test was performed and the results in-
dicated a maximum carryover of 0.25% from No. 21 Steam Generator. This
carryover was acceptable and indicated that the mqdifications improved the
quality of steam from the generators.
At 6:16 a.m. on October 16, the turbine was removed from service to repair
an oil leak in the hydraulic control system. At 8:20 p.m. the leak was
repaired, and the unit returned to service.
At 7:58 a.m. on October 18, a reactor/turbine trip from 100% power occurred
when loss of No. 22 Main Feed Pump caused a low level in No. 24 Steam
Generator. The feed pump tripped on low suction pressure. The conditions
which occurred during this trip are very similiar to the Unit 1 trip on
October 17, and the same comments apply. The unit was returned to service
at 9:36 p.m.
The inspector had no further questions regarding the operations during
this period.
17
8. Surveillance Activities
The inspector observed the licensee's performance of the following sur-
veillance procedures:
a. 1 PD 2.6.067 Channel Functional Test DT 948 B Containment Pressure
Protection Channel III, revision 3, dated November 30, 1979
b.
1 PD 2.6.043,Channel Functional Test lLT ~ 527 No. 12 Steam Generator
Level Protection Channel IV, revision 3, dated December 7, 1979
c. 2 PD 2.6.005 Channel Functional Test 2TE - 421 A/B #22 Reactor Coolant
Loop Delta T/Tave Protect Channel II, revision 0, dated February 1979
The channel check verifies operability and accuracy of the instrument alarm
and trip functions. This requirement in the Technical Specifications demon-
strates "operability" for safety related instrumentation. The inspector con-
firmed the following: Testing was performed in accordance with adequate
p*rocedures; test instrumentation was calibrated; 1 imiting conditions for
operations were met; removal and restoration of the affected components were
properly accomplished; and, the test results conformed with Technical Specifi-
cations and procedural requirements and were reviewed by personnel other than
the individual performing the test. Any deficiencies noted were reviewed and
resolved by the personnel of the responsible department. The personnel per-
forming the surveillance activities were knowledgeable of the systems and
the test procedures. The inspector confirmed that these personnel were
qualified to perform the tests. The inspector had no further questions re-
garding the performance of these surveillance activities.
9. Maintenance Activities
The inspector observed maintenance activities on the following equipment:
a.
Rod Position Indicating Equipment for 201 lunit 2) - out of alignment
b.
Main Steam Stop 24 MS167 - failed to operate
c.
No. 23 Steam Generator - excessive moisture carryover
d.
No. 24 Steam Generator - excessive moisture carryover
These activities were observed to ascertain the following:
The work was
conducted in accordance with approved procedures, regulatory guides, Technical
Specifications, and industry codes or*standards. The following items were
considered during this review:
The limiting conditions for operation were
met while components or systems were removed from service; approvals were
obtained prior to initiating the work; activities were accomplished using
approved procedures and were inspected as applicable; functional testing was
performed prior to declaring that particular component as operable; activities
were accomplished by qualified personnel; radiological controls were implemented;
and fire prevention controls were implemented.
18
The inspector had no further questions regarding maintenance on the items
listed above.
10.
Radiation Protection
During-a routine tour on October 2, 1981, the inspector observed that
the airborne activity__in Unit l containment was above the al arm setpoint
as read on the instrumentation in Un1t l control room.
Revi~w of logs
and records indicated that several containment entries has*been-_ made -
during the preceding week.
The results of the most recent sample
Johnson Bomb (100 cc), No. 14756-81, at 1:26 a.m. on October 2, 1981,
indicated that Xe 133 (5.29 Day half-life) concentration was 1.42 E-3
uCi/cc and above the limit specified in 10 CFR 20, Appendix B, Table 1
(IE-5 uCi/ml).
The inspector examined the areas surrounding the contain-
ment Air Locks (access hatch) and determined that no- signs had been
posted to indicate airborne radioactivity. Failure to properly post
this area with a sign(s) £~Stitutes,_an item_ of non.complia~_c_e (272/~l'-*25-04).
11. System Operation and Review
The inspector conducted a walk down of selected portions of plant systems.
The following drawings were used to conduct this review:
a. Fire Protection System - 20522, revision 12, dated March 9, 1981
b.
Safety Injection System (Unit 1) - 205234, revision 11, dated
January 22, 1981
c. Component Cooling System (Unit 2) - 205331, revision 10, dated
May 13, 1981
The walk down was conducted to confirm system operability. Included in the
review was an examination of valve positions, seismic restraints and supports,
leaks (unidentified), local indicators and instrumentation, unusual noise or
vibrations, overheated equipment, and system conformance with
11as built"
drawings.
No unacceptable conditions were identified.
12. Unresolved Items
Areas for which more information is required to determine acceptability are
considered unresolved. Unresolved items are contained in Paragraphs 5 and 6.
13.
Exit Interview
At periodic intervals during the course of this inspection, meetings were
held with senior facility management to discuss inspection scope a~d findings.