ML17202U808
| ML17202U808 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 08/24/1990 |
| From: | Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17202U806 | List: |
| References | |
| 50-237-90-17, 50-249-90-17, NUDOCS 9009040009 | |
| Download: ML17202U808 (22) | |
See also: IR 05000237/1990017
Text
- . *
U. S.
~UCLEAR REGULATORY COMMISSION.
REGION III
.
--~
Reports No. 50-237/90017(DRP); 50~249/90d17(DRP).
Docket Nos. 50-237; 50-249
License Nos~ DPR~19~ DPR~25 .
Licensee:
Commo*nwe'alth Edison. C.oinpany
P~ 0. Box 767.
Chicago,
I~ 60690
Facility Name:
Dresden Nuclear Power Station, Units 2 and 3
Inspection At:. Dresden Site, Morris~-
I~.
Inspection Conducted:'.
June.13 through. July31, 1990
Ins~ettors:
S. G. Du Pont
D. E. Hills .
M. S. Peck**
Appr.oved By:
1B
Date
Inspection Summary
Inspecti6n dudng the per1od of June 13 throu*r July 31, 1990 (Reports
Nos. 50-237/90017(DRP); No. 50-249/90017(DRP)
.
.
Areas Ins~ected: Routine unanryounce~ resident inspettion of previously *
identifie
inspection items,_ licensee event repqrts, plant' operations,
maintenance/surveillanc~s, e~girieerin~/technical support and report review.
Results:
- ,!
0
0
One violation was -identified. involving three'.examples of inadequate
equipment outage.checkli~ts. *Two '(Jf these .examples had similar root
causes although an adequate length of time to implement effective.
cpr~ective actions* h~d occur~ed between these twb. examples.
Therefor~,*
this* item was* determined. not to fi.t the criteria for exercise of
discretion u*nder* 10 CFR 2, Appendix C, Section*v.G.1. *Although. the
results of the individual examples were of minimal safety significance,
taken in aggr~gate the inspectors cbnsidered them to b~ indicative of
prob ~m in control of' this area and thus possible precursors to a more
serious event.
Three. unresolved items *were identified.
The issue involv.ing the drywel l
manifold sampling system as described in paragraph 6.b was awaitlng
.. li'censee completion of 10 CFR 50.59 safety evaluations to address.
specific pas.t practices" in the usage .bf thi_s system.
The issue involving
comp.onents from* .three system? no~ a_ppropd ate ly included .in the primary
o*
0
0
,*,
containment local leak rate testing program as described *in paragraph 6.t
was awaiting further review by NRC regional specialists.
The issue
involving the facility's compliance with 10 CFR 50.62, anticipated
- transient without scram rule, as described in paragraph 6.d was awaiting
further NRC
techni~al review of design calculations and post-modification
testing.
Two non-cited vio*lations were identified which both involved missed
fire watches occurring approximately ~ne month apart as described in
paragraphs 4 and 5.a.4.
However, root causes were sufficiently
dissimilar such that corrective actions from the first event could not
reasonably had been expected to prevent the second event.
Therefore~
these violations were not cited in accordance with 10 CFR 2, Appendix C,
Section. V.G.1.
A loss of condenser vacuum event which nearly resulted in a reactor
scram is described in paragraph 5.a.6. Although operator actions were
suffic.ient to*mitigate the event, it was noteworthy that this event,
was precipitated by balance of plant equipment failures.
The licensee
initiated actions to pievent similar failures in related equipment.
The inspectors are continuing to fol1ow the balance. of plant equipment
maintenance are~ to ~scertain the potential for significant events and
the affect upon safety-related equipment.
Oper~tions continued to be good as indicated by the operator response to
events exhibited during the loss of condenser vacuum event. Additional
concerns regarding the adequacy of equipment outage checklists was viewed
as a we*akness in the maintenance program.
Until resolution of the
uhresolved items in the en~ineering/technical support area, thi~ area is
considered indeterminate.
1.
- DETAILS
Persons Cont~cted
. Commonweal th Edi son Company
E. Eenigenburg, Stat~on Manager
~L. Gerner, Technical Superihtendent
E. Mantel, Services Director
D. Van Pelt, Assi~tant Superintendent - Maintenance
~J. Kotowski, Production Superintendent
...
J, Achterberg, Assistant Superintendent - Work Planning
- G. Smith, Assistant Superintendent - Operations
- K. Peterman, Regulatory Assurance Supervisor.
W. Pietryga, Operating Engineer
M. Korchynsky, Operating Engineer
B. Zank, Operating Engineer
J. Williams, Operating Engineer
R. Stobert, Operating.Engineer
M. Strait, Technical Staff Supervisor
L. Johnson, Quality Control Supervisor
J. Mayer, Station Security Administrator
D .' Morey, Chemistry Services Supervisor
D. -Saccomando, Health Physics Services Supervisor
- K. Kociuba, Quality Assurance Superintendent
- R. Falbo,.Regulatory Assurance Assistant
- D. Lowenstein, Regulatory Assurance Assistant
- L. Sebby, Station .Maintenance Supervision
- R~ Whalen, Assistant Technical Staff Supervisor
The inspectors ~lso talked with and i~tervieWed several other licensee
employees, including members of the technical and engineering staffs,
reactor and auxiliary operators, shift engineers and foremen, electrical,
mechani car and instrument personne 1, and contract security personne 1.
- Denotes those attending one or m*ore exit interviews* conducted informally
at various times. throughout the inspection period.
p
2.
Prevfously Identified Inspection Items (92701 and 92702)
(Closed) Unresolved Item (50-237/89018-03):
Licensee to resolve
~tmospheric containment atmosphere dilution/containment atmosphere
monitoring (ACAD/CAM) power supply design deficiency.
The ACAD/CAM
design is part of the larger hydrogen generation issue currently being
handled by the Office of Nuclear Reactor Regulation (NRR) under TAC
number 56579/56580. This item is considered closed since the issue is
being reviewed *and traded by other means.
(ClDsed) Unresolved Item (50-237/89005-03)~ Evaluate.effectiveness of
engineered safety features (ESF) actuation reduction program due to the
number of events involving undervoltage testing. During the December
1988 through February i990 Unit 2 refueling outage, a total of 12
3
.,-
unplanned ESF actuations o.ccurred.
Primarily* due to the efforts of the
scram/ESF reduction program, this number wa~ reduced to only thr~e during
the more recent December 1989 through February 1990 Unit 3 refueling
outage.
In particular, the licensee investigation of near misses,
including half scrams and half isolations, resulted in numerous acttons
t6 address this issue.
The *inspec~ors have no further concerns in this
area.
(Closed) Open Item (50-237/90003-01):
License~ to complete a.
.
- 10 CFR 50.59 safety* evaluation to determine whether an unreviewed safety
question exists in regard to the single failure analysis for a turbine.
pressure regulator failure. Section 11.2.3.2 of the Final Safety
A.nalysis Report (FSAR) indicated that a pressure*regulator failure i.n
the wide open direction would result in a 100 psi vess~l pressure drop
in the first ten seconds resulting in a Main Steam Isolation Valve (MSIV)
closure at less 'than 850* psi reactor pressure. A scram would result
from the MSIV closure and depressurization would be stopped due to the.
isolation.
However, with reactor water level initially near the top of
the range allowed by th.e operating procedures*, the reactor water leve*l
.swell due to the single failure could cause a turbine trip on high
reactor water level prior t6 reaching 850 psi reactor pressure.
In the
condition wher.e reactor power was greater than 40 percent, the react.or
would *scram .. due to the turbine trip. The MSIV automatic closure was
bypassed when the mode switch was.not in the RUN position.
If the
.
control room operator immediately placed the mode switch to the shutdown
position *following the scram in ac*cordance with instructions. in the
abnormal operating procedures, the MSIV closure would not occur at
850 psi. The FSAR analysis did nrit account for the possible turbine
trip if reactor water level were *assumed to be near the top of the
allowed operating range.
- * *
- The licensee completed a safety evaluation dated May .10, 1990, regarding
the FSAR discrepancy. This evaluation concluded that the pressure
regulator failure at high* reactor water ievel was bounded by.existing
plant failure analyses.
Because of plant spetific design; the licensee
concluded.that vessel overfill was not a credible event and that vessel
cooldown *would not exceed the limitations addressed in the plant's
design basis~
The inspectors ~o longer have a concern as to whethei this failure at
high reactor water *.level constitutes an unreviewed safety question.
The *licensee planned to incorpor~te the results of the safety evaluation
into the next FSAR update.*
No violations or deviations we~e ~d~ntified i~ thi~ area.
3.
Licensee Event Reports (LER) Followup (90712 and 92700)
'
~
' . .
Through direct observations, discussions with licensee personnel, and
review Of records, the following*:even"t reports were reviewed to determine*
that reportability requirements* were fulfilled, immediate corrective
. action ~as. accomplished, and corrective action to prevent recurrence
- had been accomplished in accordance with Technical Spe_cifications.
(Closed) LER.50-237/90003': *Partial*Group II Primary Containment
Isolation and Standby Gas* Treatment Initiation Due to Personnel Error.
This event and corresponding cprr~ctive actions are discussed in
paragraph 5.a.1 of this -report.
,.
No violations 6~ devi~tidns were identifi~d in this area_ except as
identified in paragraph 5~a.1 of this report.
4.
Plant Operations (71707, 60710 and 93702)
The inspectors observed contro*1 room operations, reviewed applicable logs
and conducted discussions with control room ope~ators during this period.
The inspectors verified the operability of selected emergency systems,
- revi~wed tagout records and verjfied proper return to service of affected
components.
Tburs of Units 2*and_3 reactor buildings and turbine
buildings were conducted to observe plant equipment conditions, including
potential ffre,hazards, fluid leaks, and excessive vibrations and to
verify that maintenance requests had *.be*en initiated for equipment in need
.of maintenance.
Each week during ~outine activities 6~-tours, the inspector monitored the
licensee's security program to ensure that observed actions were being
implemented according to their approved securfty plan.
The inspector
noted that persons within the protected area displayed proper
photo-identification badges and those individuals requiring escorts were
properly escorted. The.inspector also verified that checked vital areas
w.ere locked and alarmed ..
Additionally., the inspector also verified that
observed personnel and packages entering the protected area were searched
.by appropriate equipment or by hand.
The -inspectors* \\'.erified that the licensee's radiological protection
program was implemented in accordance .with facility policies and programs
and was in .compliance with regulatory requirements.
The inspectors also observed new fuel. receipt and inspection for th~
upcoming Unit 2 refueling outage.
The inspectors reviewed new procedures and changes to procedure*s that
were implemented during the inspection period.
The review consisted of
a ver_ification for accuracy, GOrrectness, and compliance.with regulatory
requirements._
These reviews and observations were conducted to verify that faci 1 ity
operations wete in conformance with the requirements established under
technical specifications, 10 CFR, and administrative procedures.
In *addition, the following operatio.nal occurrence was**reviewed:
On May 14, 1990, the Unit 3 react6r building low pressure coolant
injection (LPCI) rooms/pressure suppression chamber fire alarm light
attuated on local fire panel 2223~114 and the device 34-29 (Unit 3
reactor building lower elevation protectowire) was shown in the alarm
condition on the control room -fire alarm typer.
The op.erators attempted
unsuccessfully ~o teset the alarm and performed an inspecticin of the
.5
.*
.,,,
area to ensure that no fire actually *existed.
When the alarm would not*
reset the operators assumed equipment failure was preventing the reset
and a work request was .submitted for repairs.
In actuality, the
operators did not understand how to reset this particular alarm and
the protectowire device could have functioned if it had been correctly
reset.
The alarm response portion of Dresden Fire P',rotection Procedure
(DFPP) 4185-1, "~L-3 Fire Detection System Operation" was referenced
for* required actions.
However, this procedure had not been. updated to
indicate the requiiements of the Dresden Admihistrative Te~hnical
Requirements (DATR).
The DATRs were developed and went into effect in
August 1989 to tontain the previous' fire prot~ction required actions
upon their removal from.Technical Specifications and ;other 10 CFR 50
Appen~dix R requirements.
These requirements were removed from Technical Specifications in accordance
with Generic Letters 86-10 and 88-12.
The DATRs were in many cases more
ext~nsive and stringent th~n the previous Technical Specification
requi'rements.
DFPP 4185-1 still contained the previous Technical
Specification requirements ~hich did not address this device. Therefore,
no further actions were taken. Approximately eight hours later an
equipment operator on the next .shift while performing* rounds noted the
local light in the *a.larm condition and notified the control room .. An
inspection of the area was performed and the alarm was correctly reset.
As such, a petiod of approximately eight hou~~ existed in which the al~r~ *
was not reset and would not have been able to provide notice of an actual
.fire if one occurred.
DATR Section .3.1.1.1.a required an hourly fire
watch to be established in the LPCI rooms anc! a once per shift fire watch
to b~ established in the pressure suppression area.within one ~our of
finding this device inoperabl~. This action was not accomplished during
the eight hours~
Further review indicated that DFPP 4185-1 was not among the fire protection
procedures that had been updated when the *DATRs were instituted. At that *
time, the fire protection procedures were reviewed to determine the effect
of the changed requirements and*24 procedures were revised as a result.
However,. it was determined.that the remaining fire prot~ction procedures
could be.revised at later dates in accordance with the procedure upgrade
program.
The majority of these procedures were survei l lan.ces with
references to the previous applicable Technical Specifications.
However,
DFPP 4185-1 also contained the alarm response procedures for the XL-3 fire
detection system, contrary to what the procedure title would seem to imply
as to scope limits of the procedure content. Therefora, this review did *
not identify that DFPP 4185-1 should also have been changed prior to
implementation of the DATRs.
In addition, *DFPP 4185-1 did not contain
specific directions on how to locally reset this particular alarm.
Since
the operators *could not reset the alarm, they incorrectly assumed that the
alarm was inoperable.
Failure to perform the required fire watches was
considered to be a viblation of Technical Specifi~ation 6.2.A.11 which.
required adherence to the fire protection program implementing procedures
However, the criteria of 10 CFR 2, Appendix C,
Section V.G.1 for -discretionary enforcement was determined to be applicable
and therefore no notice of violation is being issued.
6 '
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- .. /
- -*' *
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~I
'
As a result of this event, the licensee instituted. a temporary change
.to DFPP 4185-1 to ensure proper reference to the DATR requirement~ and
appropriate local re~et methods.
A permanent revision was.planned. after
- the Operational Analy~is Division completed reviewing alarms on the XL-~
compute~ for id~ntification. * ~he licensee also reviewed the remaining
fire prot.ection procedures tq ensure that ~hey did not require immediate*
c;hanges.
Although tr*aining had:been given to the operators regarding the
.. DATRs ~hen they.~ere first instituted, the litensee determined t~at
further traipin~ was advisable in light of deficiencies i~ operator
knowledge exhibited.by this event .. Jher.efore, the licensee counseled the
involved individuals to ensure their awareness* of the requirements, wrote
daily orders to operations*~ersonnel to address this 1ssue and pl~nned to
include further *training in the operator requalification program. *The
licensee wa~ also reviewing possibl~ causes of the spurio~s linear he~t
detection a.larm and the system engineer.was monitoring the performance of
the .linear .heat detection equipment .. Due to a subsequent spurious alarm,*
a work request was written for maint~nan~e to troubleshoot the problem if
it should reoccur.* A temporary change was made to .DFPP. 4185-f to*
instruct the operators to c_ontact electrical maintenan*ce to perform thi.s
activity prior. to resetting the alarm~
- *
No v'iolations.or deviations were identified .in this area except for the
non-cited*violation described above.
-
,~.
Maintenance ahd Surveillances (~2703, 61726, and 9370l)
a.
Maintenanc~ Activities
- .* ..
.
.
Station maintenance activities of systems and components listed
below were observed or reviewed to ascertain that they were-
conduct'ed in accordance with- approved procedures, regulatory guides
and industry codes or standards and in conformance with Technical
Specifications.
The following items were considered_during this"review:
The Limiting Conditions for .Operation -(LCOs) were met while
components or systems were removed frc:im service; approvals were
obtained prior to initiating th~ work; activities were accomplished
usin~ *approved procedur~s-~nd were inspected as applicable;*
functional testing and/or calibrations were performed prior. to
returning components or*sy~tems to service; qua.lity control records
were maintained; activities were accomplished by qualified personnel;
parts and' materials used were properly certified;' radiological
controls were implemented; and, fire preventio.n controls were
implemented.
Work requests were r~viewed to determine status of
outstanding jobs and to.assure that priority is assigned to
safety-related e_quipment maintenance which may affect system
performance.
.
'
(1)
On February 4, 1990, while performing equipment outage number
iII-460, a Unit 3_ partial group Ii primary containment
iso.Tation unexpe~tedly *occurred *initiating a standby gas
treatment. system (SGTS) automatic start and reactor building
7.
J
(2)
ventilation (RBV) system isolation .. The fuse.removed during
the equipment outage was replaced and the isolation reset.
SGTS and the RBV system were returned to normal.
Further review indicated that the outage was *being performed
in accordance with work request 090128 to allow replacement
of a broken terminal point on control toom panel 903-4.
The
fuse was removed in. accordance with the outage checklist.
The equipment outage checklist for outage number III-460 was
inappropriate in that it described removing a fuse which caused
- the event.
The review of the outage by maintenance and
operations personnel (intluding two Senior Reactor Operators)
was* inadequate in that it failed to identify all effects of
removing the fuse.
The incorrect equipment outage checklist
is considered to be an example of a violation (50-237/90017-02A
(DRP)) regarding inappropriate *instructions. *safety significance
of the .resulting action was minimal since the system failed in*
the* safe directi.on. A review of the drawings and interviews with
involved personnel indicated that although the electrical drawings
were correct and were reviewed, these individuals did not
- identify the detailed information on the drawings regarding the.
pur.pose of the relays which caused the event.
Individuals
clearly u~derstood how to ~ead the drawings.
As a result, all SROs received additional training in the
continuing training program on the importance of reviewing
the detailed information supplied on drawings for individual
components.
This was accomplished during the 6 week Cycle 4
training which was completed on June 15, 1990.
This event
was also reviewed with the work analysts as part of a reading
package completed on May 30, 1990, to stress the importance
of reading all information. supplied on drawings with respect
to individual components and allowing an adequate amount of
time to review the drawings.
In addition, the licensee planned
on providing additional training to licensed operators stressing
the importance of taking adequate time to revlew the drawings.
The licensee also planned to review the SGTS initiation logic
to determine possible improvements to circuits with single fuse
- initiation capability. These last two actions had .not been
completed prior to the two events involving inadequate equipment
outage checklists discussed below.
In retrospect, these actions
were not adequate or timely enough to prevent two other examples
of inadequate equipment outage checklists approximately four
mo~ths later as described in the following paragraphs.
Only one
of these other examples, however, was related to the same root
cause as this event.
On June 11, 1990, Uriit 2 recirculation pump A tripped while
performing outage number II-412 for the recirculation pump B
motor-generator (MG) oil cooler temperature control valve
(TCV.) 2-3905-B.
This was caused by an MG set trip on high
coupling te~perature when recirculation pump A MG oil cooler
TCV 2-3905-A was mistakenly taken out of service instead.
The throttling of the TCV bypass in preparation for removing
8
,
.;
-..:......._
(2)
yentil~tion (RBV) system isolation.
The fuse re~oved during
the equipment outage was ~eplaced and th~ isolation reset.
- .sGTS arid th.e RBV system were returned to normal ..
Further feview indicated that the 6utage was being performed
in accordance.with work request 090128.to allow replacement
of a broken* terminal point on control room panel *903-4.
The
fuse was removed ih acccirdance with the outage checklist:
, Th~ equipment outage* checklist. for outage number I II-460 was
inappropriate in that it described removi~g a fuse which caused
the event.
The review of the outage by maintenance and
operations personnel .(including two S.enior Reactor Operators)
was inadequate in that *1t failed to ideritify all effects of
removing the fuse.
The incorrect equipment outage checklist
is considered to be an*example of a violation.{50-237/90017-02A
(DRP)) regarding inappropriate instructions. Safety significance
of the 'resulting action was minimal since the *system failed in
the safe direction. A review of the drawings and interviews with
involved personnel indicated *that although the electrical drawings
w~re correct and were reviewed, these individuals did not
identify the detailed information on the drawings regarding the
purpose of the relays which caused the event.
Individuals
clearly understood how to read the drawings.
As a result, a11*sRos*received additional training in the
continuing training program on the 'importance of reviewing
the detailed information supplied on drawings for 'individu~l
components.
Th.is was accomplished during the. 6 week Cycle 4
training which was completed on June 15, 1990.
This event
was also reviewed with the'.work analysts as part of a reading
packa9e completed on May 30, 1990, to' stress the importance
of. reading .all information supplied *on drawings with respect
to individual components and allowing an adequate amount of
time.to review the drawings.
In addition~ the licensee planned
on providing. additional training to licensed. operators stressing
the importance of taking adetjuate time to revi~w the drawings.
The licensee also planned to review the SGTS initiation logic
to determine possible* improvements* to circuits with single fuse
initiation capaqility *. These last two actions had not been
completed prior to the t~o ev~nts i~volving inadequate equipment
butage.c~ecklist~ discussed below.
In retrospect, these attions
were no~ adequate or timely ~nough to prevent two other exa~ples
? of inadequate equipment o~tage checklists approximately four
~onths later- as described fn the following paragraphs.
Only one .
of these.cither exam~les~ howeijer, was related to the same root
cause as th~s event.
On J'une 11, *1990, Unit* 2* recirculation pump A tripped while
- performing outage number II-412 for the recirculation pump B
mbtor-generator (MG1 otl ~ooler temperature ~ontrbl valve
(TCV) 2-3905-B .. This was caused by an MG set trip on high
cou~ling temperature when reciiculation pump A MG oil cooler
TCV 2~3905-A was mistakenly'.*taken"out of* service instead.
a:
Th~ throttling of the.TCY bypass in preparation for removing
TCV 2-3905-B had bee.n accompliShed prior to this* activity.
Further review indicated that the equipment outage checklist
for outage number II-412 was incorrect in that it listed. the
.isolatjbn valve numbers (2-3909-501 and 500) for the
_
recirculation pump B. MG set"TCV instead of the isolation valve
numbers (2-3~40;..501.and500).for the intended recirculation
. pump A ~G s~t TCV.
The incorrect equipment outage checklist is
_
ton~idered to be an example of a violation (50-237/90017-02B(DRP))
regarding .inappropriate instructions .. * Safety significance of the
resulting action was minimal since the system_ failed in the safe
direction.
The.~pplicable critical drawing_ (~-22) in the control
room, indicating the correc_t configuration fourid in the-plant, -
had been corrected to ~eflect drawing change req~est (OCR) 89-l06.
The change request was s.ubmitted on August 29, 1989, and was
still ou.tstanding. The critical drawing.in the shift *engineer's
office, which was n6t updat~d to OCR 89-106, wa~ used in
-prep~ratirin .of the outage.
This drawing incorrectly showed the
TCV for the recircuiation pump B MG set oil toolers to be TCV
2-3905-A. . Dresden Admi n i st rat ive Procedure (OAP) 2-9, "As-Built
Cr.i ti ca 1 Drawings,
11
- covered .only the hard. copy. up;..to-date
.
as-built drawing-s in the control room.
These were provided for,
operating shift and maintenance personnel for shift decisions,.
outage management and trouble-shooting.
The critical drawings in
the shift.engineer's office were not "as-built" critical drawings
and, as such,. should not have. -been* used to prepare or review the
outage without reference to the co~trol room drawings.
Control
room drawings were updated'by .hand when drawing change requests
were receiyed by the statjon. _The revised drawings for the shift
engin~er's office were issued.through engineering arid could take
up to six moriths or more afte~ the chang~ .r~quest was issued.
OAP 3-5, "Out-of'.'"Servi ce arid Perso'nne 1. Protect i o*n Cards
11
,
prescribed 'that'"only' the controlled critical plant pipi.ng and
instrumentation diagrams,. electrical prints card f.ile or Central
-File shall be utilized.for reference'to accurately identify the
points of isolation." This was' misleading since although the
drawings in the shift engineers satellite file were controlled,
they did not in fact, 'directly reflect pending drawing change *
requests.
OAP 2-~ "Operation and Control of the. Ce.ntra 1. and
Sa'tel.lite Files," required the.appropriate satellite file
aperture card to be marked "Revisiori Pending."
This would
signify that additiona.l information *was neede*d which cou.ld be
obtained 6n the "as-built" control room c.opy or in Central. *
File.
In this case, the outage was prepared from a set of
drawings whi~h were not up~to-date and the additional
information was not obtained*from the Control Room or Central
File.
Interviews with operating per~onnel indicated that there
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- .,.I
was confusion as to which set of drawings could be used for
. each type of drawing.
In additi6n, the equipment attenda~t (EA) knew that TCV 2-3905-B
was to be taken out-of-service but did not question the isolation
valves listed on the equipment outage checklist.
Upon noticing
- that the* isolation valves listed on the outage matched the "A"
TCV instead of the
118
11 TCV; the EA hung the outage on the "A"
i~olation valves.
The NSO observed the rapidly increasing
temperatures on the computer display and the Shift Supervisor
and EA returned to the MG sets. *There was insufficient time
for these individuals to take action since only ten minutes
- elapsed from the beginnin_g o'f the increasing temperatures to
the pump trip .
. As a result of this event, Operations Department memorandum
No. 18 was.issued on June 26, 1990, which described this event.
Specific guidance was included to assist in performing the
self check process. * It also st~essed that if a question or
uncertainty exists that the Shift Supervisor should be
contacted for assi$tance.
Final~y, it gave specific guidance
. as to whi~h set of drawings to use for outage preparation.
{3)
On June 13, .1990, a half group II isolation signal was received
on Unit 2 while performing outage. number II-421 for wor.k
request 089780.
This work *request involved replacement of
non-environmentally ~ualified terminal blocks with environ-
ment~lly qualified splices ~n junction boxes which provided
e lectrica 1 continuity for .. torus w*ide range leve 1 transmitter
2-1641~58~ The half g~oup II isolation signal ias *caus~d by
a Joss of power to drywell high radiation monitor B on the
m*ain control room ACAD/CAM panel*when a breaker was opened
during the performance of the out-of-service.
The equipment
att~ndant was contacted, the breaker was reclosed and the
half grou~ II isolation signal was reset. *
Further. review indicated that the equipment outage checklist
for outage number II-421 was. inappropriate in that it
prescribed opening 480 volt.motor control center 29-3 120
volt distribution panel circuit number* 6.
Review of the
outage by maintenance and oper~tions personnel was inadequate
in that 'it failed to identify ali effects of opening this.
breaker.
The incorrect equipment outage checklist is
- considered to be an example of a violation (50-237/90017-02C
(DRP)) regarding inappropriate instructions. Safety
significance -Of the res~lting actions was minimal since the
system failed .in the safe direction. A review of the drawings
and interviews with irtvolve*d p.ersonnel indicated that although
the electrical drawingi were correct and reviewed, these
individuals did not identify.the detailed information on the
drawings dealing with this function .. (The function of an
- additional wire leading frofil this breaker on electrical
_ dfawing 12~2679A wa~ not determined.)
Individuals clearly
understood how to read the drawings.
Therefore, the root
'_,
caus~ of this event involvirig inattention to.detail, was the
same as that of the February 4, 1990 event described* in
paragraph 5.a.1.
As a result of this.event and its similarity to the previous
event, the licensee planned to develop a self-check program
conststing of a committee to promote attention to detail and
- self-checking while performing the task.
This committee was to
includ~ individuals who Were directly involv~d in these events.
(4)
On June 17, 1990, the Unit 3 reactor building LPCI
~corns/pressure
sup~ression chamber fire alarm light actuat~d on local fire panel
2223-114 and device 34-29 (Unit 3 reactor building lower
elevation protectowire) was shown in the ~larm condition on the
control room fire alarm typer.
The Center Desk Nuclear Station
Operator (NSO) acknowledged the' alarm and noted work request
sticker 82074 on the typer p lex ig lass for this a la.rm.
Incorrectly assuming, due to the wor~ request sticker, that the
device was known to be inoperable and therefore already handled,
the NSO took no other actions. Approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> later,
another fire protection device alarmed_in the trouble condition.
While resetting this other device, the NSO
n~ticed that device
34-29 was in the alarm condition.
An. inspection of the affected
area was performed to ensure that an actual fire did not exist.
Appropriate fire watches were established in accordance with
DATR 3;1.1.1.a and the fire marshal was contacted for instructions
on how to reset the local alarm.
Although a temporary procedure
change to OFPP 4185-1 had .been instituted, as a result of the
previous event discussed in paragraph 4, to provide these
instructions, operating personnel were sti*ll unsure of which
button to depress in the local fire protection panel.
The local
panel 'alarm was reset which allowed the alarm condition to be
cleared on the XL-3 computer.
At that time, the fire watch was
terminated.
The crew that discovered this problem and took
appropriate action was the same crew that missed the fire watch
described in paragraph 4.
Therefore, these individuals, in
particular, had heightened interest to ensure compliance with
fire protect~on requirements.
As such, a period of approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> existed in which
the alarm was not reset and thus would not have been able to
provide notice of an actual fire if' one occurred.* DATR
3.1.1.1.a required an hourly fire watch* to be established in
the LPCI rooms and a* once per shift fire watch to be
establi_shed in the pressure-suppression area within one hour
of finding this device inoperable. This action was not
accomplished. during those 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> .. Failure to perform the
required fire watches was considered ta be a violation of
Technical Sp~cifica~ion 6.2.A.11 which required adherence to
the fire protection program implementing procedures
(50-235/90017-03(DRP)).
However, the criteria of 10 CFR 2,
Appendix C,Section V.G.1 for discretionary enforcement was
determined to be applicable and therefore no notice of
violation is being issued. This determination recognized that
11
. .
.
~
the root cause of this*evefit as discussed below and t~e ~vent
discussed in paragraph 4 we~e sufficiently dissimilar such that
correttive actions from the
0 fir~t event could not rea~onably
had been expected to prevent the second event.
Further.review of this event indicated that the root cause was
- due to inadequate administrati~e controls regarding work
request processing.
The wor.k request sticker for this device .
had been*written during the May 14, 1990 event described in
paragraph 4.
Once the device was determined to be operable and
the alarm. was. reset during the previous event~ the work request
was cancelled.
However; the *corresponding work request sticker
was never removed.
This incorrectly led the NSO to believe*
that there was an outstanding work request against the device.
Dresden Administrative Procedure (OAP) 15-1, "Initiating and
Processing a Work Request," placed responsibility for removal
of work request stickers with the originator of the work
r*equest. *However, no dependable method existed to ensure that
the originator was informed of this need in a timely manner.
In fact, the licensee found that seven of the 18 work request
stickers o.n* the typer plexiglass were no longer valid. These
were removed.
In addition, OAP 15-5, "Supplemental Maintenance
Request" did not address cancellation of work requests and
removal of stickers at all. Supplemental work requests were
written for equipment maintained on a routine or repetitive_
basis which already had outstanding base work requests.
As a
result, the lice~see planned to revise OAP 15-1 and OAP 15-5 to
require that the work group which requested cancellation of a
work request remove the corresponding work request sticker.
In-addition~ a ~set of daily orders was issued between June 19
and July 2, 1990, to emphasis the importance of DATR compliance
and that any new alarm or trouble alarm on the XL-3 fire system
was to be treated as~ valid alar~ (regardJess of work request
stickers): It also contained ~ lis~ of the fire detection
devices requiring a fire watch if only th~ one device were
As described in paragraph 4, a temporary.procedure
change to DFPP 4185-1 was issued. to ensure electrical maintenance
performed troubleshooting of this alarm upon recurrence.prior
to resetting.
The- licensee al$O planned to conduct a tailgate
session covering this event with the operators to ~tress that
there were eight devices l{sted in the DATRs*whi.ch alone would
re~uire fire* watches if inoperable.
The establishment of a log
for the XL-3 fire system, similar to the degraded equipment log
~as.planned. This would provid~ more information than that
available on the work re~uest stickers; The log is expected to
be established by the encl of September 1990 .. Finally, the
licensee was*in the process of setting up a _committee to assess
~ ~arious problems* encountered with the XL-3 fire detection
system.
This .committee was to. specifi ca 1 ly address concerns.
of the operators who had been critical of the system.
- (~). On June 30~ l990, U~it 3 was sh~tdown for a maintenance outage.
The
shutdo~n was initiated due to high temperatures between 230
12
. .
j
and 240 degrees F on the main turbine thrust bearing plate.
On
Ju~e 28, 1990, the licensee reduced power to about 40 percent
in an attempt to reduce the thru~t bearing plate temperature.
The vendor (General Electric) recommended a shutdown on
temperatures above 250 degrees F.
Since the temperatures could
not be reduced with load reduction, the licensee initiated a
maintenance outage. Other major activities completed during
the o~tage include replacement of one control rod drive,
replacement of a main transformer bushing, and repairs to
recirculation pump seal leakoff line flow instrumentation.
Approximately 70 items on the .unscheduled outage list were
also addressed.
Upon investigation of the main
turbin~ thrust
bearing high temperatures~ the litensee found damage to the
thrust bearing plate. This was replaced.
The licensee did not
conclusively determine the, root cause of the damage but suspected
an improperly placed thermocouple. *Jhe unit was restarted on*
July 4, 1990.
(6)
On July 1, 1990, while attempting to reverse circulating water
flow on Unit 2 in accordance with Dre~den Operating Procedure
(DOP) 4400-8 "Circulating Wat.er System Flow Reversal,
11
.
circulating water flow reversal valv~s 2-4402A and 2~44038
breakers'tripped and the offgas east suction valve 2-54018
failed to open.
As a result, condenser vacuum decreased to
about 24 inches and a half scram on 'reactor protection system
channel 8 was received.
The scram setpoint was 23 inches .
The operator noted the vacuum decrease and immediately reduced
recirculation flow to try to maintain condenser vacuum in
accordance with Dresden Operating Abnormal (DOA) Procedure
'3300-2 "Loss of Condenser Vacuum.
11
In addition, t.he flow
reversal was changed back to the original direction such
that condenser vacuum recovered.
The inspectors considered
the actions of the control room operators as exhibiting high
attentiveness and quick r~sponse to changing conditions to
prevent a reactor scram.
The ASCO solenoid valve* body for offgas east suction valve
.2-54018 was subsequently-changed out after it was determined
not to operate .. Testing of the molded case circuit breakers
for valves 2-4402A and 2-44038 determine,d that their trip
setpoints were too low.
The licensee had not*conclusively
determined the cause for the low trip *settings by the end of
.the inspection period.
The trip setting for the breaker for
valve 2-44038 could not be.adjusted to within acceptable
tolerances. and so it was replaced.
No maintenance history was
found on these nonsafety-related breakers.
The trip settings
. on both breakers were reset and returned to service on
July 15, 1990.
Due to the failure of two of the ~ight flow
reversal. valves on Unit 2, the licensee wrote work requests on
the remaining flow reversal va~ves on both units and planned to
enter them into the surveillance tracking system for periodic
preventative maintenance.
Problem analysis data sheets were
also initiated to track root cause analysis of the breaker
failures.
13
J
\\ .*
b.
Surveillance Activities
The inspectors observed surveillance te~ting, including required
Technical Specification surveillance testing, and verified for
actual activities observed that testing was performed in accordance
with adequate procedures.
The inspectors also verified that test
instrumentation was calibrated,.that Limiting Conditions for
Operation were met, that removal and restoration of the affected
components were accomplished and that test results conformed with
lechnical Specification and p~ocedure requirements. Additionally,
the inspectors ensured that th~ test results were reviewed by
personnel other than the individual directing the test, and that
any deficiencies identified during the testing were properly
reviewed and resolved by appropriate management personnel.
The inspectors .witnessed or reviewed, portions of the following test
activities:
. Control Rod Drive Hydraui'ic Withdrawal Stall Flow Testing
Standby Liquid Control (SLC) System Pump Test
Quarterly SLC. System Pump Test for the Inservice Test Program
One violation as described above and no deviations were identified in
this area.
In addition, one non-cited violation was identified as.
described above.
6.*
Engineering/Technical Suppoit (93702)
a.
The inspectors reviewed concerns with control rod drives going to *
position "02" during scrams.
The subject was discussed in length
in inspection report 50-237/87007;50-249/87006, and in a letter to
Mr. A. Bert Davis from I .. M. Johnson (CECo Nuclear Licensing) dated
July 14, 1987.
The original initiator of the NRC concerns was the
August 11, 1986 Dresden Unit 2 scram which resulted i~ 56 control
rods stopping at position "02".
As noted in the licensee letter and
the inspection report, this phenomenon had occurred at Dresden since
1971 as well as other BWRs, although to a much lesser extent. This
phenomenon was also the object of an NRC safety evaluation issued
J~ne 15, 1981.
The NRC safety evaluation identified the apparent cause as leakage
past worn stop and drive piston seals internal to the drive which
allowed scram water to act as a buffer on the drive. This.was
described as a hydraulic *lock occurring because of worn seals and
the design of the drive.
The design of these drives, associated
with BWR classe~ 3 and 4, had a relative large buffer area and small
vent path to slow drives during a scram to prevent i.nterna l damage.
Later models did not have this ~pparent pro~lem because of increased*
vent paths and reduced buffer area size.
General Electric (GE) recommended a revised CRD venting procedure
to remove trapped air which could also. aid in developing the
phenomenon.
GE also recommended cleaning of the drives to prevent
build up of crud tnat could also result in drive seal deterioration.
14
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.j
b.
(.
.'
The safety significance. *o( the* phenomenon was nonexistent since both
the 1987. NRC *inspection and 1981 NRC safety e'valuation determined
that sufficient shutdown margin exist~ even with all rods inserted
'only to .the
1102
11 p.os it ion.
The licensee began *a series of correction acti6ns in 1987 to reduce
- or eliminate the
1102
11 phenomenon.
These included incorporating the
r~vised venting procedure, cleaning drive tubes du.ring refueling
outages, overhauling drives demonstrating_ the "02. phenomenon
(indication of seal deterioration) and, if needed, replacin~ drives
with newer models (BWR/6 drives) .
. As a result, Cycle 11 for b.oth* units demonstrated a significant
reduction.
The.licensee.had replaced or overhauled all of the "02"
drives during Cycle 10 and' initiated cleaning of guide tubes.
The
licensee also.replaced all 14 drives in Unit 3 ~uring the last
refueling outage.
Th~se drives h.ad the following history:
C-09~ C-12, H-14 and K-12 occurred once.
F-05, F-10, L-02 and L-05 occurred twice.
G-03 occurred on four occasions .
. The .following is a tab.I: of
11 02
11 occurrence on Unit 2 during Cycle 11. *
Date
7 /12/89
r 04/89
01/05/90
01/16/90
1102" Rods
C-8, 0~10 and K-10
C-6, D-10 and K-10
C-6, D-10, E-5, E-8 and F-5
C-6, D-10, E-5, E-8, E-10, F-5 and
F*ll
As noted in this tab 1e, the NRC safety evaluation and NRC inspection
report, when
1102
11 phenomenon once occurred, the phenomenon w w l d
more than likely repeat within a cycle.
These drives were scheduled
to be replaced*during the next scheduled refueling outage on Unit 2.
The licensee has also reviewed the status of all CRDs in Unit 3 and
determined that only i4* of the original 1971 CRDs remain installed
in Unit 3.
These were also scheduled to be replaced with overhauled
BWR/6 driyes during the next refueling outage in 1991. -
The licensee was continuing with their efforts to_ resolve the
1102
11
phenomenon.
Although a final resolution had not yet been found,
these efforts had significantly reduced the occurrence of the
- phenomenon.
Since the licensee was continuing to place efforts on
.reducing the occurrerice nf -the phenomenon and these .efforts did
appear to be effective, the inspector has no remaining concerns
in this area.
On June 28, 1990, the licensee informed the resident inspectors of
an alteration to the drywell manifold sample systems on both Units 2
and 3 which affected primary containment integrity.
The purpose of
th~ drywell manifold sample system was*to provide ai_: samples to
15
-
- '
i*dentify the location of reaCtor coolant pressure boundary leaks
inside of the. drywell.
The drywe-11 manifold sample system (one for
each ~nit) was designed td take a suction* from 22.sample points in
. the drywell with *each half inch sample line having its own two
manual primary_ containme.nt- isolation valves (both located outside
of primary containment) and a filter cartridge.
Flow then passed
through a common header lrom which the sample pump took a suction .
. _-,Return back to the drywell was ,provided' through a connection to the
'continuous oxygen monitoring system which discharged to the drywell
th~ough two automatic containment isol~tion valves which closed on
a Group II isolation signal. Thus, the' drywell man'-ifol_d sampling
system had automatic isolation only on its discharge.
Piping
downstream of the manual isolation va_lves was nonsafety-related
.~(A *portion of this passed through a braided flexible hose as opposed
to the rest of* the system \\~hi ch was hard piped.).
There were
--
also four additional lines which actually took a suction from the
con'tinuous oxygen monitoring system, as opposed to directly from
primary containment, and therefore had automatic isolation on both
the suction and discharge (The-continuous oxygen monitoring system
had automati~ isolation on its suction as well as its discharge.).
'The drywell manifold sample system had been in place since the plant
was built.
Technical Specification surveillance requirement 4.6.D.1 required
drywell air sampling to be performed once per day to detect reactor
coolant system leakage.
This sample was originally obtained through
a *continuous atmosphere mon.itoring system which was replaced by
another continuous atmosphere monitoring system in the early 1980s.
Automatic containment isolation was provided with .these systems.
As. a backup to these systems the drywel l manifold sample system
as describ~d above was used.
As a secondary backup (in case the
permanent pump was in.operab.le) a temporary sample pump was used as
far back in time as 1978 and possibly before.
The temporary sample
pump was readily available since it was already used to obtain
samples from the X-area (steam tunnel) at the same sample rack.
The second continuous atmosphere mo-nitoring system was abandoned
in 1987 due to problems with moisture intrusion, therefore the
drywell manifold sampling system and the temporary sample pump
became the primary and secondq.ry methods, respectively, of obtaining
the Technical Specification required sample.
Use of the temporary
sample pump involved breaking the closed loop on the drywell
- manifold .sample system below the sample filter on one of the sample
lines, attaching a rubber hose with a quick disconnect fitting,
running the hose to the temporary sample pump and discharging the
pump exhaust to the reactor building.
The setup was typically left
unattended while a sample was being taken although automatic
isolatio~,~as not provided.
Obtainfng a representative sample
required running the system *in this configuration for at least 50
minutes but in many cases *probab.ly went much longer than this (A
subsequen~* procedure specified a minimum of one hour.).
This
allowed an unattended and unmonitored path from the drywell
- (primary containment) through the sample line to the.reactor
building (secondary containment).
16
-.
.---...._*
This use of the temporary sample pump in that configuration was
contrary to Technical Specification 3.7.A.2 which required
maintaining of primary containment integrity when the reactor was
critical or the reactor water temperature was above 212 degre~s F.
(The definition of primary containment integrity required that *all
manual isolation valves on lines connecting to containment which
were not req~ired to be bpen during accident conditions be closed.)
Therefore, each time the licensee used the temporary sample pump to
sample the drywe.11, the applicable Technical Specification* a.ction
statement 3.0.A was unknowingly entered.
However, due to the length
. of time this condition would have existed, this action statement
would have been exited prior to any actual shutdown.
Calculations
performed by the licensee assuming *one open half inch sample 1.ine at
design accident containment pressure, Pa (48 psig), indicated that
the leak rate would ~e 4.73 percent per day.
When added to the
Technical Specificatjon 3.7.A.2a(3) allbwed le~kage of 1.6 percent
per day, a to.tal_ leaka*ge of 6.33 percent per day was obtained.
This
was compared to the design basis leakage of 2.0 percent per day
prescribed in the.bases of Tech~ical Specifications. A 10 CFR 50.59
. safety evaluation was never done on this alteration (use of the
temporary sample pump) since the original administrative requirements
only applied to lifted leads and jumpers.
When the administrative
requirements expanded to mechanical ~quipment, no thought was-giv~n
to an alteration that had been routinely used for years.
As such,
in recent years each time this temporary alteration was performed it
was done contrary to the licensee's administrative procedures.
A
procedure covering the* use. of the temporary sample pump did not
extst (until 1989 as described below) and thus the problem was not
caught early on through a procedure safety evaluation ..
Use of the temporary sample pump was frequent, especially in the
last couple of years due to recurring problems with the permanent
pumps.
(The permanent pumps were estimated by the licensee to have
been oper~ble only a few weeks over the last year or two and were
troublesome even before that.)
Due to a non-documented reviewer
comment concerning use of the temporary sample p*ump without a
procedure, Dresden Radiation Protect ion (DRP) procedure 1350-3,
"Sampling the Drywell Manifold System Using the Radeco Air Sampler"
was first issued in May 1989. 'Thi.s was a missed* chance to detect the
problem since a 10 CFR 50.59 *safety evaluation should have* been
performed; however a safety* evaluation was not performed.
The .
screening criteria in effect at the time allowed entire categories
of procedures (such as DRPs not related to effluent monitoring) to be
automatfrally ruled out for a safety evaluation as long as they were
not new or changed "procedures or administrative controls" described
in the FSAR or Technical Specifications.
In this particular case,
since it was a new procedure, the criteria required a *safety *
evaluation to be performed.
Ho~ever,. the reviewers mistakenly used
the wrong administrative path *as if .. i_t were a revision to this type of
p.rocedure i ristead of a new proced~re. Therefore, a safety
eval~ation was not performed due to a failure to follow
administrative requirements.
However,. the criteria themselves
were still inappropriate since the licensee could have instead
17
.
,
./
I,
\\
just made a revision' to DRP J350-7, "Operation of the Unit 2(3)
Drywell Air Sampling Manifold*System" to a.now usage Of the
temporary sampl~ pump. *rn that .case, the licensee's administrative
- requirements would not have *required a safety evaluation to be
performed and the same result would have'been the ~ame (usage of
- the temporary sample pump without a safety evaluation).
The
screening criteria had since been revised such that this was no
longer a cancer~ for recent procedures and revisi~n~ .
. "In addition to.'the.Technical Specificat.ion requ .. ired drywell air
sample, the drywell manifold sampling system had been used since
the plant was b~ilt to obtain weekly samples from all th~ sampling
points.
This consisted of using the permanent pump t6 obtain
samples from half the sampling points at one time.
(Thu~, sampling
was done with. half the sampling lines in sim~ltaneous use twice a
week~) This sampling was not done when the permanent sampling *pump
was inoperable.
The design of the drywell manifold sampling system
provided.for two manual isolation valyes' both of which were located
outside of primary*containment.
The portion of the.drywell manifold
system located outboard of the ~anual conta.inment isolation valves
.was nonsafety-related. Thus, eleven sample lines with no automatic
isolation were routinely and simultaneously opened and left
unattended for at least one hour twice a week, providing a path from
the drywell, through nonsafety-related piping, back to the drywell.
The ljcensee took the following actions re*garding this i*ssue:
0
0
0
'O
- An assiitant technical *~taff supervisdr .identified the original
problem while reviewing a revision to DRP *1350-3.
During this
review the individual felt it was confus~ng as to which valves
were being addressed and therefore discussed w.ith the author
the p6ssibility'of including a diagram in the procedure.
During this discussioti the individual became aware that the
temporary sample pump disch.arge was into the reactor building.
This was not entirely obvious from just reading the procedure.
Upon discoverihg the problemj the licensee performed a
preliminary analysis to quantify the amount of leakage through
a*one half inch penetration through primary containment at
design accident pressure. After finding that this greatly
ex.ceeded allowable limits the licensee informed the* NRC.
The licensee issued a temporary change to the procedure
regarding usage of the temporary sample pumps to require an
individual in continual attendance and in contact with the
control room by radio while the manual isolation valves are
open.
The licensee subsequently performed a temporary *
alteration that moved the sample point for the Technical
Specification r.equired daily sample to *a *line that had
automatic i~olation.
All incoming Radiation Protettion shift personnel were briefed
as to the ptoblem to preclude imp~oper usage of the system.
18'
.
- i
\\
0
0
The licensee 'initiated a deviation report to track the licensee
investigation of the problem.
T~e licensee also initiated a*
'potentially significant event .. report for corporate management:
The licensee informed Quad Cities of the problem~
In addition, the licensee ha5 initiated or planried the following
actions:
0
0
0
0
Due to questions regarding the origina 1 system design the .
licensee was reviewing the design basis and the need for any
system de~ign improvements.
The licensee had not made a
decision whether the system would.be repaired and used or
whether it was to be abandoned, dismantled and the line~
capped.
The licensee was reviewing methods whereby a temporary return
line to the drywell could be established for use with the
temporary sample pump.
(Although automatic isolation was now
provided, the temporary sample pump sti 11 exhausted to the
reactor building which presented ALARA considerations.) .
Due to the problem.with the previous 10 CFR 50.59 safety
evaluation screening criteria, the licerisee was attempting to
determine the population of previous procedures and revisions
that would need to be rescreened under the current criteria.
The. licensee was performing a 10 CFR 50;59 safety evaluation
addressing two past practice~:
(1)
Vse of the temporary sample pump exhausting* to the reactor
building atmosphere with the manual isolation valves left
~pen and unattended.
(2)
Usage of the permanent as-designed system with eleven
sampling lines left simultaneously open and unattended.
These safety evaluations *were to include a 10 CFR 100 analysis
for offsite doses and a 10 CFR 50, Appendix A, General.Design
Criterion 19 analysis for control room doses.
This issue is co~sidered an unresolYed item (50-237/90017-04(DRP))
pending completion of. the licensee's safety eval~ations and NRC.
review of these documents.
c.
On July 20, 1990, a dual unit shutdown began from 92 percent and 99
percent rated thermal power on both Units 2 and 3, respectively, in
accordance.with Technical Spe~ification action statement 3.0.A
requiring hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the
following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
A co~responding Unusual Event was declared due
to inltiation of a shutdown required by Technical Specifications.
The shutdown was due* to the identification by the licensee of
specific components, appli~d to both units, which had not been local
leak rate tested (LLRTJ in.accordance with 10 CFR 50 Appendix J
19
"'
-
~*
d.
\\
requirements.
These included a check valve which had* not been
tested at all and two manual isolation valves whose testing *
methodology was in question in the reactor building closed cooling
water (RBCCW) system inlet to the drywell.
In additic)n, both the
inboard and outboard manual isolation val~e~ on ahcontrol rcid drive
line to the recirculation pump seals had not received LLRTs.
Finally, a flexitallic gasket on a torus water level transmitter had
not received an LLRT.
This last item was only a concern for Unit 2
si.nce the one on Unit 3 had been *subjected to Integrated Leak Rate
. Testing (IlRT) pressure within the past 24 months.
The problem with
RBCCW had been identified earlier at Quad Cities, but was not
initially corrected at Dresden.
This was because the problem at
Quad Cities involved total absence of LLRTs on the RBCCW system and
. the Dresden problem only i~volved partial LLRT of this system.
Thus, communication only involved whether LLRTs were done on RBCCW
and not the total extent of the LLRTs. 'The absence of these
components in these three systems from the LLRT program and the
licensee's corrective actions are considered an unresolved item
(50-237/90017-05(DRP)) pending further review by regional NRC *
specialists.
The shutdown was stopped and the Unusual Event terminated with the
units at 73 ,and 80 percent pow~r, respectively, later that same
evening upon receipt of a verbal waiver of compliance from the NRC.
The wai~er of compliance allowed 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to conduct appropriate
testing on' the control rod drive system and torus water level
transmitter. line components and unti) the next refueling outage for
each unit on the RBCCW line components .. The licensee submitted the
formal documentation to support this action on July 23, 1990 arid
also submitted an emergency Technical Specification (lmendment
request dn July 31, 1990, regarding the RBCCW line components.
All actions regarding the control rod drive system and torus water
level trans~itter line components including modifications needed
to conduct testing and the testing itself were completed on
Julj 22, 1990.
The licensee also issued an operating order
- describi~g actions to be taken regarding RBCCW in the* event of a
LOCA ..
During 1987, the licensee completed modificatioris to the Dresderi
Station Standby Liquid Control System (SLCS) suction piping to
facilitate dual pump operation.
The modification was performed in
pursuit of compliance with the Anticipated Transient Without Scram
(ATWS) rule (10 CFR 50.62).
At BWRs, the ATWS rule required the
SLCS negative reactivity injection rate be increased to the
equivalent of 86 gallons per minut~ of. 13 wt/%. sodium pentaborate
solution.
The rule further required the SLCS-system to be
"designed .to perform its function in a reliable manner.
11
The licensee's SLCS ATWS modification safety ev(lluation (10 CFR 50.59).
stated, in part,
11 the suction piping has been designed to assure two
pump net positive suction head (NPSH) and eliminate concerns of
mutually reinforcing pulsations.
11
The inspectors reviewed the SLCS
ATWS modification NPSH design calculation.* The review .. indicated the
calculation ~~d not include an analytical demonstration -0f adequate
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7.
NPSH but was buUt upon an assumed plant history of satisfactory
single SLCS pump operation.
The calculation incorporated the
philosophy that minimum available NPSH for two pump operation could
be maintained by the addition of a second section of piping, of
similar design to the original piping, connecting the SLCS storage
tank to the SLCS pump suction header.
The calculation 'indicated
- that a strict analytical approach to the computation of available
NPSH wruld. be overly conservative and placed a reliance on post
modification testing to demonstrate satisfactory p:rformance with
both pumps-in operation.
The inspectors also reviewed the Unit 2 SLCS ATWS post modification
test. The test consisted of the monthly single pump operational
surveillance test and the single pump .reactor vessel injection
surveillance.
In addition, both pumps *were run simultanerusly for a
64 second period to verify the dual pump flow rate. During the dual
pump test, NPSH was verified by "absence of large noises associated
with pump cavitation." The single SLCS pump in-service test program
required each SLCS "pump to be run (individually) at least five
minutes prior to obtaining data to allow each pump to reach
hydraulic stability."
In light of the design calculations' reliance
on the site testing to ensure SLCS NPSH, the post modification
testing was critical to the acceptance of the modifi'cation to.meet
10 CFR 50.62 criteria. This is considered an unresolved item
(50-237/90017-06(DRP)) pending ~urther NRC review to determine
adequacy of the design calculations and the post modification
testing.
No v.iolations or deviations were identified in this area.*
Report Review
During the inspection period, the inspector reviewed the licensee's
Monthly Operating Report for June 1990 .. The inspector. confirmed that
the information provided met the requirements of Technical
Specification 6.6.A.3 and Regu.latory Guide .1.16.
8.
Unresolved 1tems
An unresolved item is a matter about which more information is required
in order to ascertain whether it is a~ acceptable item, an. op~n item,
a deviation, or a violation.
Unresolved items disclosed during this
jnspection are discusse4 in Parag~aphs 6~b, 6.c and E.d.
9.
Ex~i Interview (307d3)
The inspectors met with licensee representatives (denoted in Paragraph 1*)
on July 31, 1990 and informally throughout the inspection period, and
summarized the ~cope and findings of the inspection activities.
The in~pectors also discussed the likely informational content of the
i~spection report ~ith ~egard to .. documents or processes reviewed by.the
inspedor during the ins*pection.* The licensee did not identify any such.
documents/processes ~s proprietary .. 'The 1 i censee acknowledged the
findings of the i~spectton~ *
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