ML20245H968
| ML20245H968 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 02/21/1989 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20245H961 | List: |
| References | |
| 50-219-88-38, NUDOCS 8903060109 | |
| Download: ML20245H968 (27) | |
See also: IR 05000219/1988038
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U.S. NUCLEAR REGULATORY COMMISSION-
REGION I
Report No. 50-219/88-38-
.- Docket No.. 50-219 (
License No. DPR-16 Priority -- Category C
Licensee: GPU Nuclear Corporation
1_._ Upper pond Road
Parsippany, New Jersey 07054
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Facility Name: 0yster Creek Nuclear Generating Station
Inspection Conducted: December 4,1988' - January- ~14, 1989
Participating Inspectors: W. Baunack
E. Collins
D. Lew -
J. Wechselberger
Approved By: $ h
C. Cowgi41, Q , Reactor Projects Section 1A Date
Inspection Summary:
Areas Inspected: Routine inspections were conducted by the resident and one region-
based inspector (294 hours0.0034 days <br />0.0817 hours <br />4.861111e-4 weeks <br />1.11867e-4 months <br />) of activities in progress during the outage, including
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maintenance and surveillance activities, radiation control, and physical security.
In addition, inspectors reviewed two security events involving a potential un-
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authori2ed entry in a vital barrier and loss of security electrical loads, control
room loose wires, scram discharge volume foreign material and cleanliness flushing
practices, air accumulator testing, torus tiedown bolt material condition, CRD
return line piping wall thickness, and refueling operations. The inspectors also
conducted a review of the preliminary safety concern process and several particular
safety' concerns. Initial review of the operability status of the source range
monitors prior to refueling was also conducted. An LER review was conducted to
assess any identifiable trends or weaknesses.
Results: The inspectors identified five unresolved items. The unresolved items
included concerns regarding the single failure susceptibility of the standby gas
treatment system automatic initiation logics, vital area unauthorized entry, de-
letion of SDV flushing requirements and programmatic implementation of cleanliness
. standards for piping system, completeness of testing of air accumulators associated
with safety related valves, and the quality control process used to verify the
, adequacy of shop spare parts prior to installation. The inspectors developed con-
cerns regarding the proper and time'.y processing of preliminary safety concerns
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identified by employees. Valid safety concerns actually remain open when the
tracking system indicates their completed disposition. An error-free refueling
of the reactor was completed during the period.
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8903060109 890223
PDR ADOCK 05000219
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. TABLE OF CONTENTS-
'PAGE.. <
'1.0 D rywe l l En t ry ( 717 0 7 ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,. . . . . 1
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2.0 Control l Room Loo se Wi re s ( 93702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
I3.0 I_RM S p i ki n g . P ro b l e'm s . ( 9 3 7 0 2 ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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4.0 - Preliminary Safety Concern Review (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . " 4 -
' 5' 0 Standby. Gas Treatment (SGTS) Logi c (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . .
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5.1 ; Item..................................... ......... -............ 5-
5.2' Review.............. ........................................... 6'
,o 5.3 D i s c u s s i o n . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-
5.4 Integrated Plant Safety Assessment, Systematic Evaluation 4
Program-(SEP)................. ................................ 7
5.5 Conc 1usicn...................................................... 7-
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6.0 Rag Found in Scram.01schargeLVolume-(93702).......................... 8
6.1- Event......................... ................................. 8
' 6. 2 ' Revi ew of Li cen see Ac ti on s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
7.0 . Air Accumulator Testing (71707)...................................... 10
8.0 Monthly Maintenance Observation (62/03).............................. 12
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9.0 Monthly Surveillance Observation (61726).... ........................ 12
9.1 Source Range Monitor Front Panel Test, Procedure 620.4.004...... 12
9.2 Reactor Triple Low Water Level Test and Calibration Procedure
619.3.006..................................................... . 13
10.0 Backshift Inspection................................................. 13
11. 0 Reacto r Ve s sel Lo st Part s ( 71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
12. 0 To ru s T i edown Bol t s ( 71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
13. 0 Fuel Suppo rt Ca s ti ng s ( 71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
14 0 Control Rod Drive Return Line Piping (71707) . . . . . . . . . . . . . . . . . . . . . . . . . 15
15.0' Loss of Security Electrical Loads (81700) . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
16.0 Source Range Monitor Log Integrator Cards (71707) . . . . . . . . . . . . . . . . . . . lo
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, 17l.0 Review of Periodic and Special Reports'. (71707). . . . . . . . . . . . . . . . . . . . . . . >17
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,18.0 Meetings.............................................................. :18'
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18.1 GeneraliReview Board Meeting.................................... .18:
18. 2 . Qua l i ty Ma intena'nce Team Bri e fi ng. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ' 18 L
19.0 Radiation Protection (71707).......................................... 18
20.0 Observation'of Physica1' Security (71707).....'.....................l... '18
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21.0 Review of ' Licensee Event Reports (LERs)-(90712,L 92700)................ '18 -
22.0 Refueling-Activities................................................. '24
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123.0 Unresolved Items....................................................... 24-
24.0 Exit: Meeting.............................. ........................... 24:
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DETAILS-
- c ~1.0 Drywell Entry
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THIS PAGE CONTAINS SAFEGUARDS INFORMATION
AND IT NOT FOR PUBLIC DISCLOSURE.
IT IS INTENTIONALLY
LEFT BLANK.
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THIS PAGE CONTAINS SAFEGUARDS INFORMATION
AND IS NOT FOR PUBLIC DISCLOSURE.
IT IS INTENTIONALLY
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This item will remain an unresolved item pending further inspector review
(50-219/88-38-01).
2.0 Control Room Loose Wires
l . During the report period the licensee discovered loose wires behind control
i room panels 5F, 6F, and .11R and in panel ER-18 in the 480 volt room. The in-
!. spector discussed with the licensee their plans to verify electrical termina-
tions prior to plant restart as a result of the extensive maintenance activity
conducted in. safety related control panels'. The licensee elected to perform
an engineering evaluation to assess the proper method to verify control panel
electrical terminations. Inspection Report 50-219/87-04 discusses similar
loose connections discovered by the licensee and corrective action taken to
resolve the loose wires.
The loose wires found in the control room are normally terminated in a com-
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pression terminal strip. The wires are not lugged and landed, but simply-
placed under a spring steel clip with compression force supplied by a set
screw. In some cases, two different gauge wires are placed under the same
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compression clip which, with vibration or force exerted on the wire wrap
bundle may loosen or pull the wire free from"the terminal strip and break.the
electrical connection. The different gauge wire may promote loose termina-
tions by allowing the smaller gauge wire to pull free as the larger gauge wire
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absorbs the compression clip force. After the previous loose wires event,
the licensee implemented controls and performed extensive inspections to en-
sure loose wires would not be a problem during plant operation.
The loose wire in panel ER-18 resulted from an HFA relay replacement in the
panel when the electrical lead was not relanded following the relay replace-
ment.
After discovering the loose electrical connection in panel 11R the licensee
elected to reland the wire in the compression terminal strip. Prior to ac-
complishing this task the licensee performed an engineering evaluation to
determine what the plant response would be to relanding the loose wire. When
making the determination the plant response was not as expected. In reviewing
this event the licensee determined that the unexpected plant response resulted
from personnel error of the plant engineers who reviewed the electrical ter- i
mination drawings. The inspector examined microfiche electrical termination
drawings for panel 11R and found the prints to be of poor quality and diffi-
cult to read and were marked "best available". The inspector will review the
licensee critique on this event and plans for inspection of electrical ter-
minations prior to plant restart.
3.0 IRM Spiking problems
During this report period the facility experienced a number of IRM spikes.
On 12/31/88 and again on 1/2/89 full scram signals occurred with the plant
in a cold shutdown condition. The licensee could not detect any maintenance
or surveillance activities that could have caused the IRM spikes to produce
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l a full scram. On 1/6/89 the inspectors observed numerous half scrams occur-
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ring from IRM 12 spikes. The spiking problems have been observed on IRM's
11, 12, 13, 15, and 17. The IRM instrument problem has. historically been a
problem without resolution. The licensee plans to perform troubleshooting
efforts to ensure the IRM's are functional prior to restart from the outage.
. The inspector will follow licensee activities.
4.0 Preliminary Safety Concern Review
l During this report period, the inspectors visited the corporate office in
Parsippany, NJ to review preliminary safety concerns (PSC) and the PSC process.
As a result of this review the inspector expressed concern regarding the
length of time to address PSC's, in man,y cases this was greater than one year
and involved legitimate safety problems. The licensee committed in a letter
(dated 12/3/86) to Region I in response to Inspection Report 50-219/86-24 '
(dated 11/4/86), to resolve PSC's in a timely fashion. During the inspector's
review the new proposed revision to the preliminary safety concerns procedure
entitled, " Management of Potential Safety Concerns," 1000-ADM-7330.01 written
to incorporate the commitments reflected in the licensee's 12/3/86 letter was
examined. The proposed revision did not reflect the licensee's commitment
to incorporate time constraints in the processing of PSC's to ensure timely
resolution of safety concerns.
The second concern the inspectors expressed involved the closure of PSC's with
outstanding action items left unresolved. The licensee has in the past closed
PSC's on the basis of issuing other action items to be resolved such as Tech-
nical Function Work Requests (TFWR) or licensing action items (LAI), for ex-
ample. The inspectors discovered two examples of this concern in the limited
review they conducted of the PSC's. PSC 84-018, reported 10/10/84, addressed
a concern regarding a single failure susceptibility of a power supply dis-
abling the standby gas treatment system (SBGTS) logics and control power (see
paragraph 5.0) and that could render the automatic initiation of SBGTS in-
operable. (In addition, operation of the system in a manual mode may be
limited and warrants further review.) A TFWR was issued on 1/28/85 to resolve
this issue and closed in 10/87 based on the evaluation results of the PSC
which concluded that although it was a valid single failure susceptibility,
it was in accordance with the plant design basis and the SEP (see paragraph
5.4). It appears that no real evaluation of the safety concern was carried
out under the TFWR. The TFWR simply relied on the evaluation in the PSC which
in turn was closed and the action item turned into an apparently untracked
TFWR. Thus, the PSC transmitted the concern to a TFWR which was closed based
on th'e PSC evaluation. In addition, this item took three years to close and
may have overlooked a valid safety problem (see paragraph 5.0).
The second example of a safety concern that remained open and untracked with
the PSC considered closed was PSC 86-20 (reported 10/14/86). This PSC ex-
presses a safety concern regarding nonfunctioning of the containment spray
system automatic initiation logic after a single failure of the 125 VDC power
panel. LER 86-23 addresses this concern. The licensee issued TFWR No. A01692
and Topical Report 038 to justify eliminating the automatic initiation of the
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containment spray system. During this report period the inspector was unable
to determine. the status of the TFWR, but was later informed by the. licensee
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that elimination of the automatic initiation of containment spray system was
- being re-evaluated. In addition PSC-87-003 was written to address another
concern with containment ' spray system -logics. This concern is developed in
s. Inspection Report 50-219/87-04. The. concern involves containment spray system-
automatic initiation logics in the dynamic test mode.' In;this mode,' coupled
with a Lo-Lo reactor water level signal, the drywell- may be-inadvertently
sprayed. , Also, another concern involves the dynamic test mode used to
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facilitate torus pool cooling. In an accident situati.on, the ability.to. cool
the torus may be prevented until the ~ logics may be overridden.(see Inspection
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Report 50-219/87-04).
The licensee resolved this PSC based on the evaluation performed 'for PSC 86-20
above. Essentially, this item remains open. The licensee has^ initiated a
method to status open PSC's which is r good initiative and currently carries
only three open'PSC's. This does not include the PSC's mentioned above,
though. The status of PSC's receives wide distribution within the corporation
including the GORB, but' does not include those PSC's which may have open
issues as indicated above.
During this review the inspectors noted that some. individuals perceived that
PSCs would not be resolved in a timely manner nor were welcomed as a mechanism
for resolution of potential safety problems.. Further, some individuals who
could be expected to submit a PSC were not knowledgeable of.the process.
Based on the above review, the inspectors expressed concern that the process
is not working as described, in that concerns are sometimes not resolved in
'a timely manner, and that some PSCs were closed without appropriate reviews
being complete. Additionally, some site staff members appear to have lost
confidence in the process.
The inspectors plan further review of the PSC process and specific PSC'.s.
5.0 Standby Gas Treatment System (SGTS) Logic
5.1 Item
As.a result of the Preliminary Safety Concern (PSC) review discussed in
paragraph 4.0, inspectors identified one PSC initiated in 1984, #84-018,
which addressed, in part, the potential inability of the SGTS initiation
logic to meet single failure criteria. Tha specific concern was that
upon opening or loss of breaker #20 from Vital AC Panel (VACP)-1, the
automatic initiation logic of the SGTS would be disabled.
The PSC evaluation concluded that while the SGTS initiation logic does
not strictly meet single failure criteria, this configuration was in
accordance with original plant design. It also referred to the Inte-
grated Plant' Safety Assessment, Systematic Evaluation Program (SEP) re-
view for Oyster Creek, NUREG-0822, evaluation of the loss of VACP-1.
As a result of the PSC evaluation, a Technical Functions Work Request
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(TFWR) was initiated to review possible design changes. This was sub-
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sequently closed evaluating the changes as not required. No modifica-
tions were initiated to address this concern.
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.5.2 . Review
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Inspectors reviewed the electrical configuration of VACP-1. This 120-
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vac panel is supplied from either of two safety related 480 vac unit.
substations through an automatic transfer switch. Power then.goes
through a disconnect switch and a 480/120 v transformer to VACP-1. From
review of this configuration, it can be seen that there are several
single failures which.could interrupt power to VACP-1, and thus to the.
, SGTS automatic initiation logic.
Inspectors reviewed the electrical elementary drawing.to determine the
ef fects of'a loss of VACP-1-(breaker #20) on the SGTS. Since the SGTS
initiation' relays energize on an automatic initiation signal, and the
SGTS logic-is energized by VACP-1, the automatic initiation of the SGTS
is rendered inoperable without logic control. power. The fans could be
started manually, but the system would apparently operate in'a degraded,
mode since the preheater: automatic temperature controlswould also not
be operating.
In addition, VACP-1 breaker #20 supplies power to the reactor building y
(RB) damper controls, turbine building (TB) ventilation . control, main {
exhaust dampers, drywell and torus exhaust dampers, drywell vent and '
purge valves and control room ventilation controls for train "A". Th'e
exact extent of the impact of a loss of VACP-1 #20 on these components
is still under review.
5.3 Discussion
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The SGTS is a plant engineered safety feature (ESF) reactor building
atmosphere cleanup system which functions as a barrier between the radi-
ation source and the environs during emergency conditions. Upon initi- '!
ation~ and secondary containment isolation, the system establishes a j
negative pressure in the RB, thus preventing ground level leakage of i
untreated radioactive material from the RB to the environs; and the sys- )
tem treats the RB atmosphere prior to exhausting via the plant stack.
Section 6.5.1.2.1 of the plant updated Final Safety Analysis Report
(FSAR) describes the SGTS as consisting of two redundant, full capacity
parallel flow. trains. Section 6.5.1.2.4 of the FSAR describes the sys-
tem as automatically starting during the Design Basis Accident (DBA)
upon receipt of an initiation signal.
The instrumentation and controls section of the FSAR, 7.3, discusses the
instrumentation provided to initiate ESF systems, including the SGTS.
This system has both Reactor Protection System (RPS) and Non-RPS initi-
, ation signals. Sections 7.2.2.1 and 7.3.5.2 of the FSAR state that both ,
the RPS and Non-RPS systems will automatically perform their protective '
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functions whenever plant conditions exceed preset levels and that no-
single failure can prevent the initiating circuits from performing their
protective functions. In addition,10 CFR 50. Appendix A, General Design
Criteria 41, Containment Atmosphere. Cleanup, specifies that each ~ system
shall have suitable' redundancy to assure that its safety function can
m, be accomplished assuming a single failure.
- 5.4 Integrated plant Assessment Systematic Evaluation' Program (SEP)
Topic VII-3 of the SEP evaluated the effects of a loss of VACP-1 on the
ability to place the plant in a safe shutdown condition. A limited
' probabilistic risk analysis (PRA), discussed in Appendix D of the SEP,
dealt with the contribution to risk of the loss of VACP-1 powered control
room indications. The NRC concluded that the increased probability of
operator error due to lost indication did not contribute significantly
to top events in the fault trees, and thus, loss of VACP-1 was a low
importance to risk. 'In addition, SEP Topic VI-7.C.1 evaluated the con-
tribution to risk sof automatic bus transfers (ABT), specifically, their
contribution to loss of power to redundant unit sub-stations 1A2 and.182.'
Backfitting of redundant power supplies for control room indication was
not-recommended.
PSC 84-018 stated that the current design was acceptable based on the
'SEP review and acceptance of the design. It is significant to note that
the SEP analysis only evaluated VACP-1 from a perspective of providing
control room indication and impacting loss of the redundant unit sub-
stations'1A2 and 182. The loss of VACP-1 was not reviewed for a loss
of automatic ESF protective functions. For these reasons, the inspector
questioned the conclusion in PSC 84-018.
5,5 Conclusions
The inspector has concluded, based on a review of the regulations, FSAR,
and SEP that the safety function of the SGTS is to automatically initiate
during accident conditions to mitigate the consequences of these postu-
lated accidents. The licensing basis for this system, as presented in
the FSAR, is to automatict.lly initiate when plant conditions exceed pre-
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set levels and that no single failure (electrical) can prevent the in-
itiating circuits from performing their protective function. In addition,
10 CFR 50, Appendix A, GDC 41, states that suitable redundancy in com-
ponents and features shall be provided so that the system's safety func-
tion can be accomplished, assuming a single failure.
Although still under review, the current Oyster Creek design for the
automatic initiation of the SGTS is potentially susceptible to single
failures as it has only one power source, VACP-1 and one initiation logic
train downstream of VACP-1. The ability of the SGTS to automatically
initiate with a susceptibility of single failure will be carried as un-
resolved (50-219/88-38-02).
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- 6.0 Rag Found in Scram Discharge Volume
6'.1EEvent-
On'12/30/88, after a reactor scram,'the scram discharge volume (SDV) high
, water level scram signal was bypassed in; order to' resetL the. scram logic.
Upon reset of the scram logic, the SDV vent'and drain valves opened and
the '_'SDV Not Drained" annunciator cleared indicating that the SDV had
been drained. Shortly thereafter,.while the SDV vent and drain valves
remained open, the "SDV Not Drained" annunciator returned for the. south
SDV-. header. Eventually, the SOV instrument' volume "Hi" and "Hi-Hi"~an-
nunciators were also received for that- header.~ These indications,showed
' that even with the SDV vent and drain valves open, water was entering
the SDV. south header and was not being drained.
The licensee initiated a work request.to inve'stigate t'he inability to-
drain the south SDV. The inboard SDV drain valve ~was disassembled and
a rag.was found 'to be blocking-the line. The: inboard drain valve for
the north SDV was also disassembled, but no adverse conditions were
identified. The source of water was determined to be. leaking scram out-
let vr.1ves, which'were subsequently repaired.
As a result of finding foreign material in the SDV, the licensee initi-
ated an effort to fill and drain the SDV five consecutive times in order-
to verify the ability' to drain and to remove any other foreign material.
This was accomplished successfully. The amount of time to drain the'
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SDV's was measured with the following results:
1 5:06 4:28
2. 5:07 4:35
3. 5:07 4:35
4. 5:11 4:35
5. 5:08 4:34
Each filling of the SDV also functionally tested the instrument volume
level instrumentation.
The licensee conducted a critique of the event in order to determine the
source of the foreign material. Based on the deteriorated condition of
the rag, the licensee concluded that it was old and had probably been
introduced into the SDV in 1984, when the new SDV system was installed.
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6.2 Review of Licensee Actions !
Since the licensee's efforts to identify how and when the rag was intro- i
duced into the SDV were inconclusive, the licensee's approach was to
demonstrate the repeated and consistent ability to drain the SDV. The
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licensee al'so desi. red to perform a visual inspection of_'the SDV instru-
ment volume while the drain valves were disassembled, using a borescope,
~but the physical arrangement of the valves made.this impossible.
-The-inspector reviewed the' licensee corrective actions and. concluded'that
the five consecutive SDV fill / drains. demonstrated confidence in the
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ability.to drain..the SDV. They also demonstrated.the operability of the
l-#' instrument volume level instrumentation. The inspector also reviewed-
the times required to drain the SDV and concluded that a high degree of-
consistency was demonstrated. These' drain down times 'were compared to
those experienced during the most recent plant shutdown. No conclusions-
could be drawn though, because of the different events measured. The
sequence of alarm recorder (SAR) indicates the time of the resetting of .
the scram contacts,'while the five fills / drains were timed from the last
SDV. drain valve's opening.
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During this outage, a modification was performed on the: scram discharge
volume, installing. cleaning connections near the end of each of the six-
headers located above the hydraulic control units. The inspector.re--
viewed Short Forms #44841, #44842 and #44840 in order to assess the
cleanliness control measures implemented for this modification.
Installation specification, OC MM 328155-001 specified that all' material
be maintained in a Class C cleanliness state as defined by ANSI N45.2.1.
In addition, it specified that the internals' of pipe added by this: modi-
fication shall .be flushed. During the modification, a Field Change Re-
quest was submitted requesting deletion of the flushing requirement based
upon maintaining Class C cleanliness during erection. This request was
approved and no flush was performed on the new cleaning connections after
they were welded to the SDV.
The inspector reviewed the work packages and quality assurance-inspec-
tions and verified that Class C cleanliness was documented until the
piping assembly was welded to the SDV header, at which time no more in-
ternal visual inspections were possible.
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NRC Regulatory Guide 1.37, " Quality Assurance Requirements for Cleaning
Fluids Systems and Associated Components of Water Cooled Nuclear Power
Plants," essentially incorporates for operating nuclear power plants,
the provisions of ANSI N45.2.1-1973, " Cleaning of Fluid _ Systems and As-
sociated Components During Construction Phase of Nuclear Power Plants,"
both of which are committed to by the licensee in the Operational Quality
Assurance Plan.
ANSI N45.2.1-1973 states that it is its intent to maintain the specified
level of cleanliness during erection so that only water flushing will
be required for final cleaning. This indicates that the maintenance of
cleanliness during erection does not provide justification for deletion
of the requirement to perform a water flush. Based on these requirements,
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as stated in ANSI N45.'.1-1973, the inspector concluded that the change
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to the installation specification to waive the flushing requirement was
not proper, and that SDV Class C cleanliness has not~been demonstrated
by examination of flushing filters.
_
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. The inspector also reviewed licensee Procedures A100-SMM-3900.07, " Main-
taining Class C Cleanliness," and A100-GMM-3900.06.." Maintaining Class-
C Cleanliness," for implementation of the cleaning requirements of ANSI
N45.2.1-1973. These procedures incorrectly reference the 1980 edition
of ANSI N45.2.1, which has substantially different flushing requirements
from the 1973 edition. Since.the licensee's QA plan delineates Regula-
- tory Guide 1.37, which endorses the 1973 edition of ANSI N45.2.1, the
i
licensee is committed to the 1973 requirements (as inodified by the OQA).
Discussions with QA personnel indicated that it is not unusual for the
flushing. requirements to be waived based on maintenance of cleanliness
_
during erection. .The inspector concluced that the licensee's procedures
were not adequate'in_that they do not implement the cleaning requirements
The licensee't deletion of the system flushing. requirement from'the SDV-
modification and the licensee's programmatic implementation of the
cleaning requirements of ANSI N45.2.1-1973 will be an unresolved item
(50-219/88-38-03).
7.0 Air Accumulator Testing
The licensee conducted :esting on the air accumulators to various safety re-
lated air operated valves during this report period. This testing was con-
ducted in response to concerns identified by the Oyster Creek Emergency
Operating Procedure (EOP) Inspection (IR 50-219/88-200) and Generic Letter 88-14, Instrument Air Supply Problems Affecting Safety Related Equipment.
The E0P Inspection had identified deficiencies in the method by which the
containment ventilation exhaust valves, V-27-1 and V-27-2, and intake valves,
V-27-3 and V-27-4, were tested. -The testing method as identified by the E0P-
inspection does not verify that the accumulator check valve would seat and
be leak tight upon loss of instrument air nor verify that the accumulator had
a ' sufficient free air volume available to stroke the valve under design con-
ditions. The Oyster Creek instrument air system is not a safety related
system.
In the original scope of the accumulator testing, the licensee identified
eighteen accumulators which they intend to test during this outage. These
accumulators affect containment isolation, the Standby Gas Treatment System
(SGTS) and condensate makeup to the isolation condensers. The inspectors have
closely followed licensee testing activities. An additional 22 accumulators
which are associated with SGTS valves were planned to be accomplished by the
end of the next refueling cycle. >
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Presently, the licensee has tested sixteen of the eighteen accumulators. Of
the sixteen accumulators tested, eight accumulators required corrective main-
tenance. Four of the accumulators which required work provide an air supply
to the main. steam isolation _ valves'(MSIV), and the other four accumulators
which required work provide an air supply to the SGTS trains' inlet and outlet
. valves.
The. accumulators and associated piping to the MSIVs provide an air supply to
assist in seating the valves upon a loss of instrument air. Previous local
leak rate tests have shown that if no air is supplied to the MSIVs in the shut"
direction, .the valves will not pass the local leak rate test acceptance cri-
teria. This fact' was identified in Preliminary Safety Concern 88-07 which
was written in January 1988 but is not yet resolved. The accumulator piping
to'the MSIVs consists of brass pipes and fittings. While attempting to per-
form the test on these accumulators, the licensee discovered that there was
excessive leakage from these fittings. The procedure had specified that all
fittings were required to be snooped and the leakage corrected; however, due
to the large number of fittings which were leaking air, the procedure could '
not be completed.- The' licensee subsequently performed an air pressure drop
test on' the accumulator and associated piping to quantify the leakage. The
air pressure in the accumulator had dropped from 100 psig to 40 psig in a half
hour period. The licensee evaluated the brass piping design to be inadequate
and is presently modifying the piping by replacing the brass piping with steel
piping and welding the steel piping together instead of utilizing fittings.
The licensee has also concluded that this piping must meet seismic require-
ments and is presently installing seismic supports to the piping.
The accumulators to the SGTS train inlet and outlet valves provide the motive
force to-shut the valves upon a loss of instrument air. The absence of ac-
cumulators upon a loss of instrument air would result in the standby SGTS
train's inlet and outlet valves failing open. Since the SGTS trains share
a common header downstream of the outlet valves of each train and upstream
of the inlet valves of each train, the operating SGTS flow will recirculate
backwards though the standby SGTS train, thereby rendering the operating SGTS
ineffective. During the testing of these accumulators, the licensee deter-
mined the pressure drop in the accumulators and associated piping to be ex-
cessive. In an attempt to reduce the air leakage rate, the licensee replaced
the isolation check valves to the the accumulators. The replacement of the
check valves reduced the air leakage to a 1.5 psig to 3.0 psig pressure drop
from 100 psig over a 30 minute period. The licensee, however, has evaluated
this reduced leakage still to be unacceptable to ensure that the accumulators
can perform their design function. As a result, the licensee is presently
replacing the valve operators on the valves to further reduce the air leakage
rate. The licensee is continuing their evaluation of the test result and
considering changes to their SGTS procedures to ensure that the SGTS will
l perform its design function. l
,
The licensee has not completed their evaluation of the test results. Plans, i
however, are underway to review all forty accumulators for seismic require-
ments. The licensee has not decided whether further accumulator testing on
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other accumulators are necessary. The inspector asked based upon the high'
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percentage of maintenance work required as a result of accumulator testing
to date and the questions concerning the ability of the valves to perform
I,
their design function, if the remaining accumulators should be. tested prior
to restart from the outage. The inspectors will continue to follow the lic-
. ensee's actions. This item is unresolved (50-219/88-38-04).
l
l 8.0 Monthly Maintenance Observation
u,s
Portions of the fellowing maintenance activities were observed.
I
--
Accumulator testing on Containment Ventilation Exhaust Valves, V-27-1
and V-27-2. s
--
Troubleshooting of Main Steam Isolation Valve, NS03A, to determine cause
for local leak rate testing failure.
--
Repair of Feedwater Check Valve, V-2-72.
Items. inspected included a review of pertinent work packages, observation of
valve tagouts, verification that technical specification requirements for
secondary containment were satisfied, appropriate radiological precautions
were taken in accordance with the Radiation Work Permit, required administra-
tive approval was obtained prior to the start of work and quality assurance
hold points were observed.
The accumulator test on valves V-27-1 and V-27-2 involved the disassembly of
the accumulator from its associated piping and seismic supports to verify that
there was no water accumulation. It was noted during the reinstallation of
the accumulator that the work package did not specify any-torque specifica-
tions for the strap bolts which held the accumulator to its seismic support.
The inspector reviewed the original installation specification for the modi-
fication and noted that the installation specification listed torque values
for these bolts. The inspector identified this fact to the licensee. The .
'
licensee subsequently changed the work package to torque these bolts in ac-
cordance with the installation specification.
Although further discussion with the Technical Functions personnel raised
)
questions on whether or not torque values were in fact required for these
bolts, it was evident that the requirement for torque values for the rein-
.
stallation of these bolts was not considered. The inspector had no further :
questions on this matter. i
I
9.0 Monthly Surveillance Observations '
9.1 Source Range Monitor Front Panel Test, Procedure 620.4.004.
As a result of the frequent short periods which were observed on the
source range monitors (SRM), the inspector observed the performance on
the SRM Front Panel Test. The short period alarm was jumpered out of
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Lm'*~ . service.during this period of-time. A reitew'of the licensee's eval'-- u
L ation to refuel without this alarm function was performed. It" was al so'. _
m note'd on the' surveillance that this alarm was* tagged out:of serviceLand
that the Rod Block alarm was lockedDin as 'a result. off the Refueling -
m .' Bridge being: tagged out of service. l The test- dataiwere observed'to be
c:. -
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within thel Technical Specification ~ acceptance criteria. Proper approval
from the Group Shift: Supervisor was obtained prior to the start of.the'
, surveillance. _No' unacceptable conditions were identified.
9.2 Reactor Triple L'ow Water Level Tes't and Calibration, procedure 619.-31006;
V -
Portions of.the ReactoF Triple Low Water Level Test and'Calib' ration. sur- ,
.veillance'were-observed from the control room and at RK02. Review of .
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this' surveillance included theLverification of tes't instrument calibra-
tion', test' values 'were within the acceptance _ criteria, appropriate ad-
~
ministrative approval recei.ved and proper. documentation. performed. No
unacceptable conditions were' identified.
.
' 10.0 Backshift Inspection-
'
e
NRC inspection of-' licenses activities during deep backshift hours were con ' >w
ducted on the'following dates:
--
Saturday, December 31, 1988-
--
. Thursday, Janua'ry 5, 1989-
--
' Friday, January 6, 1989
--
Saturday,. January 14,.1989 '
Areas:of inspection included the observation of fuel loading in the reactor
vessel,- fuel. pool gate gasket replacement, Source Range Monitor Front Panel
Testing, control room activities and performance of plant tours.
-
11.0 Reactor Vessel = Lost Parts
Dur.ing this outage, a large number of items had inadvertently fallen 1n' to the
reactor vessel. These items include two bullet lights', a Hansen air fitting, .
a magic marker cap,'a metallic band, a metallic ring, a " screen-like" material,
an acorn. nut, a lens cap, a lens to a pair of s'afety glasses, three pieces
of tie wrap:and a few short pieces of duct tape. Although a majority of these i
items have been removed from the reactor vessel, the licensee intends to
leave some of these items in the reactor vessel during the upcoming operating
cycle. These items include a few short pieces of duct. tape, a lens to a pair
of safety glasses and a lens cap. A General Electric analysis was presented
to show that the items would disintegrate upon heatup and that chemistry
changes were acceptable. I
The inspector reviewed portions of the licensee's Reactor Vessel Lost Parts"
Analysis. This analysis includes a reference to the General Electric Lost
Part Analysis which was performed for the licensee during the 10R Outage.
No concerns were identified by the inspector in the review of General Elec-
tric's evaluation. In light of the large number of items which have fallen
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in the reactor. vessel during this outage and the fact that many 1tems in.the
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reactor vessel were identified by.use of an underwater camera device the per-
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sons who may have inadvertently and unknowingly dropped the ' items, improvement
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in the observation of cleanliness during maintenance and operational activi-
^
- ties is needed. Licensee staff members acknowledged the need- for improvement
, and agreed to review their ' practices.
12.0 Torus Tiedown Bolts
Independent visual examinations were conducted by the licensee and the in-
-
spector on the torus anchor bolts. This examination was conducted in response
to anchor bol_t anomalies identified in the Hatch Nuclear Plant.'s Mark I con-
tainment. The majority- of the anchor bolts at. the Hatch , plant"were deformed
with a maximum deflections between 1/4 inch and onelinch.
The visual examination.of the anchor bolts at Oyster Creek included checking
for deformation in the saddles, bearing plates, base plates, anchor bolts and
grouting. Positions of ,the bolts in?the slotted holes were also noted. The
licensee examined 90% of the anchor bolts and identified no deformation or
anomalies. The inspector examined 20% of the anchor bolts with similar find-
ings. .The inspector had no further questions regarding this matter.
13.0 Fuel Support Castings
During the replacement of fuel support castings '(pieces) in the contrel rod
drive tubes, the licensee experienced difficulty in properly setting the
castings. The licensee had removed 26 castings earlier 4 the outage to sup-
port the exchange of control rod blades. Most of these 26 castings were not
properly' seated. Additionally, the licensee believed that three peripheral
castings were not f ully seated.
After unsuccessful ati.empts to seat the castings, the licensee contracted
General Electric to' assist in the seating of the castings. With General
Electric assistance, the licensee was able to seat all castings. ' One of the
castings, however, required minor filing to allow the guide pin on the lower
core support plate to fit into the casting. Further evaluation of i.he three
peripheral castings indicated that two of the castings were fully seated.
"-
The third casting was easily seated after it was slightly touched. The lic-
ensee determined that this casting may have lifted off its seat when its fuel
bundle was removed from the core.
The licensee believes that a potential contributor to the difficulty in seat-
ing the castings was the fact that some castings were not returned to their
original positions. Although these castings are supposedly identical, the
licensee hypothesized that they may have become form fitted in their positions
in the core plate. In previous outages, the entings were returned to their
original positien as a result of the method of exchanging control rod blades,
and thus no fit problems existed. The licensee was able to obtain an original
plant drawing showing the uniquely numbered castings in their original core
position. Utilizing the serial numbers enscribed in the castings, the cast-
ings were returned to their original positions.
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It was observed, however, that some of the castings which the licensee had-
difficulty ~ seating were already.in the original' position. -It, appeared to the
inspector that operator _ technique.was also a potential contributor to the
difficulties in seating the castings. - General Electric personnel _ had experi-
enced a easier effort in seating the castings. .Another potential contributor
.. to the' seating difficulty was the weight of the tool utilized to seat the
castings. The licensee. believed that use 'of a heavier tool would have as-
sisted.in properly seating the castings.
After seating the. castings, the licenser verified that all castings which were
moved during the outage were properly seated. Additionally, more.than sixty-
other castings which were not moved were verified:to be fully seated. The
inspector had no further questions regarding this matter.
14.0 Control-~ Rod Drive Return Line Piping
On December 28, 1988, while performing weld inspections on the control rod
~
drive return-line, the licensee identified that a section of piping was sig-
nificantly' thinner than called for in Revision 6 of the General Physics In-
service Inspection Program Schedule (15IPS). The ISIPS had called for a
schedule 80 piping which has a nominal thickness of 300 mils. The portion
of piping,.however. had readings between 200 mils and 220 mils.
This portion of piping is located between the CRD return line manual isolation
valve, V-15-29, and weld NC-4-20 and forms part of the reactor pressure
boundary. The piping is a 3 inch pipe six inches in-legth. The licensee's
t evaluation of this piping' determined that .it was not thinned from erosion.
This evaluation was based opon the uniform thickness of the piping and the
abrupt change in wall thickness at tna location of weld NC-4-20. The evalu-
ation further._ postulated that the piping was probably installed schedule 40
piping during original plant construction, althwgh no installation documen-
tation can ce locatec: The licensee performed a stress. analysis on the'
schedule 40 piping m htermined thn it was acceptable in accordance with
ANSI B31.1. The inspet. tor reviewec m licensee's evaluation of pipe stresses
and identified no unacceptable cono m ons.
15.0 Loss of Security Electrical Loads
On December 10, the licensee was preparing to perform maintenance to replace
a breaker which supplies safeguards loads. Upon deenergizing the safeguards
loads, security personnel realized that compensatory actions could not be
maintained because of the unanticipated loss of certain safeguards functions.
As a result, the security loads were reenergized almost immediately and the
maintenance activities deferred.
The inspector interviewed operations and security personnel concerning the j
circumstances surrounding this event. Operations personnel had believed that
security personnel maintained a set of safeguards electrical diagrams and that ]
1
they were cognizant of the loads which would be lost upon performance of this l
maintenance. On the contrary, security personnel did not have such diagrams j
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in-their-possession and stated that even if they did have.them they.did not
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memorytto determine what safeguards equipment they wouldLlose.
It wasl evident that the miscommunication resulted in an' inadequate review of
g , . the impact of the maintenance activity. The safeguards engineer at the plant
w'as not informed nor consulted in the performance this work. It was also
i noted from interviews with personnel that this practice had occurred many-
L times in the past, however, appropriate compensatory measures were taken.
l
'The inspector brought this problem to the attention of the licensee. Although
a formal critique' was not performed the licensee held ~a meeting with the dif-
'feront departments involved. The licensee intends to' generate a list of
saf eguards loads and their associated power supplies for use after this~ outage.
It the interim, an increased awareness of the problem and the utilization of
the safeguards engineer should prevent similar occurrences and not jeopardize
plant security.
The inspector had no further questions regarding this matter.
16.0 Source Range Monitor Log Integrator Cards
During pre-refueling checks the licensee found defective log integrator cards
in the source range monitors (SRM). These log integrator cards were replaced
prior to refueling, but af ter the card replacement the SRM!s exhibited fre-
quent large spikes coupled with short period alarms. Prior to refueling, the
4 inspectors discussed a concern regarding SRM operability with the Plant Engi-
neering director.. The licensee explained that they had delayed refueling for
approximately five hours to trouble shoot the SRM's and found no problems.
The inspector reiterated his concern regarding SRM operability and the large
number of short periods. The licensee stated that with regard to refueling,
the SRM's were operable to accurately measure neutron level. The inspector
agreed to review SRM behavior after some fuel assemblies had been loaded in
the core around the SRM's. After this had occurred, the SRM still exhibited
the same behavior. In addition, when one source was moved adjacent to SRM
21, a normal source range response was observed and did not display the ab-
normal spiking prevalent with SRM's 22, 23 and 24. Again the licensee deter-
mined that the source range instrumentation was adequate to measure source
level neutrons during. refueling.
Subsequent to refueling the licensee performed troubleshooting of the SRM's
to include response time testing of the log integrator cards. The licensee
conducted bench testing of the log integrator cards removed from the SRM's
after completing refueling operations. The licensee determined that the 390
microfarad capacitors used in the log integrator dampening circuit were de-
fective.
These log integrator replacement cards with the defective 390 microfarad
capacitors were obtained from shop spares and bench tested prior to plant
installation. Inspection Report 50-219/88-33 identified a violation regarding
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- ANSI /ASME N45.2.2, storage of QA spare parts onsite outside.the warehouse and
-
raised a concern regarding reliability of these spare-parts due .to the inade-
quate storage. During the 88-33 inspection the licensee assured the inspector
that before any shop spares would be used in the plant sufficient bench test-
ing would be conducted to . verify the acceptability of the spare part. Thisi
, event raises the question of the acceptability of the QA process used to
verify shop spare part adequacy for plant installation and also raises.the
question of previous shop spare part installation'in the plant.
Another concern results from the guidance provided by the technical manual
with regard to the, correct replacement module number. Apparently the tech- I
nical manual provided different module numbers on the functional block diagram,
the SRM applicability table and the manual secti.on on operation and trouble-
shooting of the log integrator. In addition, the one module number indicated'
-
is for a process radiation monitor with a difference in the card capacitance
.which explains the large spikes and short period alarms exhibited by the SRM's.
The inspector questioned whether the technical manual could provide sufficient
guidance to the technician to repair safety instrumentation and control cir-
cuitry. The licensee critiqued this event. This item is unresolved 'pending
further NRC review (50-219/88-38-05).
'
17.0 Review of Periodic and Special Reports
-
Upon receipt, periodic and special reports-submitted by the licensee pursuant
to Technical Specification requirements were examined by the inspecters. This
_
review included the following considerations: the report includes the infor-
mation required to be reported to the NRC; planned corrective actions are
adequate for resolution of identified problems; and the reported information
is valid.
The following reports were reviewed:
--
Monthly Operating Report for November 1988
--
Special Report 88-01, Fire Diesel Pump 1-2
1
This report identified nonfunctional fire diesel . pump 1-2 due to debris
in the suction bell, which degraded pump performance. A rag was found
in the suction bell, but the licensee was unable to determine how it was
i
'
introduced into the system. The licensee offers that a potential intro-
duction point is through inspection ports on the relief valve. The in-
spector was unable to understand how a rag introduced in the system at
j a relief point could happen to partially block the pump suction. System
L material cleanliness requirements during maintenance should be reviewed
j by the licensee. The inspector had no concerns.
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.18.0 Meetings-
'
, 18.1 Ge'neral' Review Board Meeting
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The inspectors attended portions of the General Office Review Board
, meeting / conducted at Oyster Creek on January 10 and 11,1989. The meet-
_ ing appeared to be a very worthwhile effort.to improve plant and' company
' performance.'
18.2 Quality Maintenance Team Briefing-
On 12/21/88, resident inspectors met with a maintenance manager and were , , ,
briefed on the licensee'r, plans to enhance maintenance performance. The
plans include the initiation of a pilot program using ~ the Quality Main-
tenance Team (QMT) concept with eventual full implementation of the QMT '
. concept; s
19.0 Radiation Protection
During entry to and exit from the RCA, the inspectors verified that proper-
. warning signs were posted, personnel entering were wearing proper dosimetry,
personnel and materials -leaving were properly monitored for radioactive con-
tamination and monitoring instruments were functional and in calibration.
,
Posted extended Radiation Work permits (RWPs) and survey status boards were
reviewed to verify that they were current and accurate. The inspector ob-
served activities'in the RCA to verify that personnel. complied with the re -
quirements of applicable RWPs and that workers were aware of the radiological-
conditions in the area.
20.0 Observation of Physical Security
During daily tours, the inspectors verified that access controls were in
accordance with the Security Plan, security posts were properly manned, pro-
tected area gates were locked or guarded and that isolation zones were free
of obstructions. The inspectors examined vital area access points to verify
that they were properly locked or guarded and that access control'was in
accordance with the security plan.
21.0 Review of Licensee Event Reports (LERs)
21.1 In-Office Review of LERs
A review was conducted of LERs submitted to the NRC to verify the details
were clearly reported, the cause appears accurate and is supported by
report details, corrective actions appear' to be appropriate, and that
no further information is required. The following LERs were reviewed:
87-34: Inadequate emergency lighting was identified to exist in several
areas. Additional lighting to correct the condition has been installed.
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87-35: Reactor scram with the reactor shut down during. the performance
of a surveillance test. The cause was attributed to a degraded cable
-
' connection due to normal wear. The cable will.be repaired and similar
conditions inspected.
.
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^ *' '87-36: Improper control of a' high radiation area due to personnel error
- and procedural' noncompliance. Several workers were terminated and-
-
stricter guidance was , issued. .
? 87-37: Failure to perform two monthly ' gaseous' effluent dose calculations.
Subsequent calculations showed releases--to be~
~
due to personnel error.
well below the limit. Corrective action consisted of training additional
~
as personnel to perform the calculations.
87-39: Discovery of a failure to meet 10 CFR 50, Appendix R criteria in
an emergency diesel generator lockout relay circuit. Corrective action
was taken to modify the circuitry to comply with 10 CFR 50, Appendix R
cruaria.
. 87-42. ~orus oxygen sample line isolation valves were identified as not
meeting single failure criteria. Modifications will be made to isolation
. valve ci,rcuitry to meet single failure criteria.
87-41': '(Voluntary Report) Fuel pool cooling system piping . radiation
shielding' inadvertently removed creating a highl radiation area. . Properly
labelled permanent shielding was installed and personnel training was
conducted.
m
87-42: This event was discussed in Inspection ReportL50-219/87-33.
- 87-46: (Voluntary Report) This event was discussed in Inspection Report
50-219/87-33.
..
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88-01: This event was discussed in Special Inspection. Report 50-219/88-02.
88-02: Containment high range radiation monitors failed to meet accept-
ance criteria during calibration due to incorrect post installation
testing. The monitor was repaired, tested and returned to service, a ;
vendor document control program established, and personnel training con-
ducted.
88-03: Containment particulate monitor sample line isolation valves con-
trol circuitry found not to meet single failure criteria since installa-
tion in 1976. Standing orders have been issued until the deficiency is
corrected in accordance with the Integrated Living Schedule.
88-04: Isolation condenser automatic actuation pressure sensors tripped
at valves greater than those specified in Technical Specifications. The !
sensors were adjusted to trip within setpoint limits. Long term correc- ;
tive action is to replace the instruments with an analog trip system. I
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88-05: A tagging error caused components of both standby gas' treatment-
systems to be inoperable. Corrective action consisted.of additional
!: m personnel. training. This event was reviewed.in Inspection. Report 50-
..
219/88-09.~
y '88-06: 'During surveillance testing,. four 'of eight ' isolation condenser
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pipe break sensors tripped at a differential pressure greater than
specified in the Technical-Specifications. The sensors were adjusted
,
to trip within units. Four sensors will be. replaced during theccurrent-
outage with newer design switches and their performance evaluated.
88-09: During surveillance testing, two isolation condenser-automatic
actuation pressure sensors tripped at' valves greater than specified in . .
the. Technical Specifications. Corrective action is the same as described
in LER 88-06.
~
88-11: This event was reviewed in detail in Inspection Report 50-219/
88-21.
88-14: Testing showed Main Steam Isolation Valve NSO4A leaked excessively.
The valve was repaired, a new valve stem was installed, and a' successful
r leak rate test' performed. The valve inspection and repair procedure will'
also be revised. .
88-15: A main steam isolation valve closure occurred during surveillance
testing, while the plant was in cold shutdown. The valve closure oc-
curred with a required jumper fell offland shorted to ground. A project
has been initiated to eliminate the need for. installing jumpers during
surveillance testing.
88-16: During surveillance testing, four isolation condenser automatic
actuation pressure sensors tripped at values greater than those specified
by the Technical Specifications. The corrective action is the same as
that specified in LERs 88-04 and 88-05'.
88-17: (Voluntary Report) Three control rod accumulators low pressure
alarms were present for greater than one hour in violation of plant pro-
cedures. The event was discussed with all operating shift personnel.
88-18: Inadvertent actuation of the "B" isolation condenser due to opera-
tor error. The operator immediately realized his error and took correc-
tive action. The actuation lasted for less than seven seconds. This
report was made required reading for operators.
88-19: This report described the circumstances associated with both
isolation condensers being inoperable. An enforcement conference was
held relative to this matter. The enforcement conference is dist.ussed
in Inspection Report 50-219/88-33.
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88-21: ,This report described the circumstances associated with both
' isolation condensers being in an unanalyzed' condition. A_special review-
of.this' event was conducted by an Augmented Inspection Team. Resultsl
of the team review are documented in Inspection Report 50-219/88-80.
. .88-22: This . report described the loss of an emergency bus due to a' ground :
fault. -This-event was reviewed in Inspection Report 50-219/88-80.
88-23: Drywell airlock not . leak rate tested in accordance with Appendix
J. The review of this event is discussed in Inspection Report 50-219/-
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88-28.
88-24: Main steam isolation valve closure signal occurred during sur -
veillance testing due 'to procedural deficiency. The surveillance proce-
dure will be revised.
88-26: A reactor scram signal was received with the plant shutdown-due
to an error in a newly revised procedure. The procedure will be revised
and this LER made required reading for qualified reviewers.
G
88-27: Several fire watch tours were missed due to inadequate guidance
>
and direction being provided to temporary contractor employees. Correc .
~
tive action consisted of establishing a log which requir'es hourly signa-
tures. Also, 'a procedure will be developed which will define fire watch
responsibilities and the log requirements.
88-29: Six containment isolation valves were identified which do not meet
NUREG-0737 criteria which requires deliberate operator' action to open
an isolation valve after the isolation signal is reset. A modification
will be performed on these valves so they will meet requirements in ac-
cordance with GPUN's Integrated Living Schedule.
21.2 Onsite Review of Licensee Event Reports (LERs)
The following LERs were reviewed to determine the report was adequate
in assessing the event, the cause appeared accurate, corrective actions
appeared appropriate, generic applicability was considered, and that the
licensee review and evaluation were complete and accurate.
87-33: Safety limit violation caused by personnel error while removing
reactor recirculation pumps from service. This event was discussed in
detail in Inspection Report 50-219/87-29. During the event, it was noted
the fuel zone level monitor (F2LM) did not activate when all five recir-
culation pumps were trfpped. Corrective actions specified in this LER
.
!'
and also discussed in a September 20, 1987 letter, Clark to Murley, were:
"GPUN will evaluate the fuel zone water level instrumentation s tem for
the appropriateness of the recirculation pump trip signal and the pos-
i sible addition of an alarm." During this inspection, the licensee's i
l committed-to evaluation of this matter was reviewed. A Licensing Action !
L Item (LAI) 87178.06 was written to initiate this evaluation. This LAI .
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was closed out on December 7, 1987, based on the performance of an
evaluation. The inspectors review of this evaluation showed that it
dealt'with a February 1987 event in which a recirculation pump M-G set
field relay failed and did not at all address the corrective actions
specified in the LER. The performance of an 1 propriate evaluation
, and its apparent acceptance was discussed with sne licensee. Subse-
quently, a supplemental response to the LAI, dated January 16, 1989, was
prepared to address the F2LM, and concluded the installed instrumentation
is adequate. Also, the evaluation of an alarm installation was stated
to have been completed and determined no alarm was necessary. The writ-
ten evaluation associated with the alarm determination was not available
on site. Additional management attention to the review of committed-to
evaluations appears to have been warranted in this instance to assure
that a correct evaluation was performed.
87-45, 88-08, and 88-10: These three LERs all reported standby gas
treatment system automatic initiations. The basic cause of all events
was water in the off gas inlet line and its associated drain to a sump
located at the base of the stack. In addition to procedure changes,
personnel counseling on the importance of strict performance compliance,
and the required reading of two of the reports by Radwaste Operations
personnel, a modification to the off gas drain was made and a new seal
pot was installed to increase the water level over the drain line. This
modification should eliminate this problem which had been experienced
for a long time.
87-48: This LER reports a reactor scram signal which occurred while
moving the reactor mode switch from shutdown to refuel during testing.
This apparent cause was attributed to mechanical wear of the mode switch.
Corrective action included an evaluation of a mode switch replacement
during a future refueling outage. This evaluation has been completed
and it was recommended not to install a new mode switch at this time.
The license'e has, however, committed to purchase a new improved mode
switch. One of the reasons for not installing a new mode switch is that
there is no clear evidence a problem exists with the installed switch.
The inspector had no further questions relative to this matter.
88-07: This report describes the discovery of a reactor coolant sample
line containment isolation valve being inadequately supported. It was
reported the valve was supported by rope and a pipe support upstream of
the valve was broken. In addition to correcting the physical deficien-
cies, corrective action consisted of making this LER required reading
to all plant en;.neering personnel. During this inspection, it was de-
termined additional corrective action was taken in that a critique of
the event was performed which identified root causes and specified addi-
tional corrective actions. The inspector had no further questions rela-
tive to this matter.
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!88-12: This, report describes.certain Appendix'R deficiencies identified
- in;elgetromatic relief valves and cleanup' system valves circuitry. , Part
, ,of'the: analysis and nfety assessment of the occurrence described the
use of-~ torus cooling'using the containment spray system. dynamic test mode
1 .and the emergency. service water system.- The use~of this method of torus
- , cooling is affected by a Preliminary Safety Concern.(87-003) which de-
s
-scribes certain elements of the containment spray systemLlogics during;
the dynamic test mode. The PSC. explains'that the capability'of the
dynamic test mode to cool the torus.from the control. room may not be
avai.lable due to logic circuit. considerations. Ther inspectors felt thise
consideration was:not addressed in the LER. The Preliminary Safety Con-
cern.(PSC) had been closed out but because of recent interest in:PSCs "
was stated by the licensee as be.ing reevaluated. The resolution;of this
matter is being tracked.by, Unresolved Item 50-219/87-04-02.
- :
'88-13i This-report describes a Main Steam, Isolation Valve (MSIV) stem
failure.: As part of the description of the event,'.the licensee described
a Technical Specification violation in that a half scram was not inserted
- for approximately 50 minutes while there was no steam flow in the "A"'
steam.line with.both.MSIVs indicating open. The decision-not to insert
-
the' half scram was made for safety concerns to permit a maintenance fore-
man to = inspect the' outboard MSIV. The LER states'when it was determined,
the foreman was clear of the outboard MSIV, the half scram.wasm inserted.
This statement is not entirely true for, based on discussions with per-
sonnel and an entry in the log book, the half scram was in fact inserted,.
-
,
based on information developed during the evaluation before the outboard.
MSIV.was inspected.
Since many options were available to the crew such as believing the out-
board valve position indication and not inspecting the valve to removing
'the' half. scram for only the two or three minutes the outboard valve was
being inspected. The failure to insert the required half scram was dis-
cussed in detail with members of the onshift crew during the event and
with licensee management. From these discussions, it was determined-
management above the 'shif t level made the ~ decision not to insert-the half
scram for personnel safety considerations. Certain levels of managerrent
and members of the shift crew, during the event immediately recognized
and expressed the view that a half scram must be inserted. The Group
Shif t Supervisor (GSS) was aware that someone had been dispatched to
inspect the outboard MSIV but it could not be determined who actually
required-the inspection be performed. After being dispatched, the fore-
man could not be contacted by radio or pager.
.
'
The inspectors discussed the failure to insert the half scram, and the ;
details associated with the decision with licensee management. During I
this discussion the need to minimize disagreement during shift operation
and to effectively control the dispatching of personnel which could have
an effect on decisions which have a potential to affect Technical Speci-
fication requirements was identified. It is realized that during an
event the time to make decisions is limited. However, events of this
.
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nature 'should be evaluated in order'to more effectively address poss'ible. '
future. events.- The licensee. indicated the event had been reviewed and
that~ the' GPUN letter. describing command responsibilities ha'd.been re-
emphasized with the GSSs. No enforcement action relative to the delayed
insertion of a half. scram when'.its insertion was indicated is. going to
, be taken'since'it was identified ~ by the licensee and met -the criteria.
of 10 CFR 2, Appendix C'(50-219/88-38-06).
'
88-20: This report describes .the discovery that the_. isolation condenser
steam vents and' the emergency service water discharge lines,from the
containment spray heat' exchangers radiation monitors would not ' fulfill
-
their design function of radiation' leak detection due to .high radiation
background following an accident. During this inspection the inspector
reviewed the four alarm response. procedures associa'ted with, these moni-
y tors, of the four procedures involved only one had a note included which
indicated the monitor was subject to high background radiation and may
alarm.without a ~ leak being present. The necessity of upgrading prece-
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dures to reflect discoveries made which could have an affect- on operator .
responses was discussed with licensee management. . Management immediately
took steps to insure that ' reviews are conducted of LERs to assure that
appropriate procedures are changed if necessary.
22.0 Refueling Activities
Ref ueling began on January-6,1989 and was completed on January 13. This
'
refueling'was conducted without any error. The only problems observed were
_
.those associated with Source Range Monitors (Sections 9.1 and.16.0). This
. smooth and error-free refueling is in contrast to the' earlier defueling. de-
scribed'in Inspection Report 50-219/88-33. The significant improvement is
the result of the application of lessons learned from refueling and.the. con-
siderable management attention paid to the refueling.
,
23.0 Unresolved Items
,
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Unresolved items are matters for which more information is required in order
to ascertain whether they are acceptable, violations, or deviations. Unre-
solved items are discussed in paragraphs 1.0, 5.0, 6.0, 7.0 and 16.0 of this
report.
24.0 Exit Interview
A summary of the results of the inspection activities performed during this
report period were made at meetings with senior licensee management at the
end of this inspection. The licensee stated that, of the subjects discussed
at the exit interview, no proprietary information was included.
t
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