ML20246C877
| ML20246C877 | |
| Person / Time | |
|---|---|
| Site: | 05000000, Susquehanna |
| Issue date: | 02/14/1984 |
| From: | Starostecki R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | Eisenhut D Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20246C819 | List: |
| References | |
| FOIA-89-226 NUDOCS 8908250163 | |
| Download: ML20246C877 (17) | |
Text
i ENCLOStmE 8 Docket Nos. 50-387; 50-388 FEB 141984 MEMORANDUM FOR: Darrell G. Eisenhut, Director, Division of Licensing, NRR FROM:
Richard W. Starostecki, Director, Division of Project and Resident Programs, Region I
SUBJECT:
SUSQUEHANNA TECHNICAL SPECIFICATIONS PROBLEM The purpose of this memo is to bring to your attention the need for NRR manage-ment assistance in developing common technical specifications for both units.
As you are aware, the control room complex for Susquehanna is common to both units, and licensed operators are being cross-trained for both units.
Conse-quently, improvements or changes made to Unit 2 technical specifications should also be considered for Unit 1.
A specific problem of concern is with TS 3.8.1.1 which requires two indepen-dent offsite power sources and four independent diesel generators to be oper-able to serve the onsite class IE distribution system during operational conditions 1, 2, and 3.
Copies of the associated one-line diagram and tech-nical specification are enclosed.
In this case, the licensee disabled, for maintenance, an alternate offsite power supply breaker (N.O.) to one of the four 4.16 kv busses. That made one offsite puwer source inoperable because of loss of independence.
(The 13.8 kv crosstie would auto-close if needed, but the supply path through the normal offsite power supply breaker [N.C.) is a common path which makes both power sources susceptible to the same failure.)
Because of the 13.8 kv crosstie feature, the licensee erroneously concluded that he had two independent power sources, detected the error after the fact, and notified the NRC. NRR, through the LPM, confirmed that the alternate power source was inoperable and that the plant was in a LCO action statement (which ts e>ceeded) during this e,olution.
As a cor seque.ce, this esciution requires quick cold start of all four diesel generators, one at a time, within four hours and at least every eight hours thereaf ter (per T.S. 3.8.1.1 action statement "a").
The following considerations are relevant.
Quick starts of diesels represent a substantive stress which should be t
avoided when practicable.
,o 5 --
Quick starts of the three diesels for the three 4.16 kv busses, which are E'
not affected by this breaker maintenance do not appear to be a needed
@,o verification.
The T.S. bases (also attached) refer to GDC-17 and RG 1.93-1974'.
Neither f
g$
reference specifically covers this situation. FSAR Sections 8.1.5.1 and i
dM 8.3 do, however, specifically state a design basis of any three of the gg four busses being capable of operating ESF on one unit plus systems required for concurrent safe shutdown on the second unit.
This specific oma
$@3 case has three power sources available to each of three of the four IE busses and two sources fully available to the fourth. A third source is partially available to the fourth IE bus (i.e., the fourth bus is M 09.2f4/fo3
}
- *t 1
$Da'rren G. Eisenhut, Director,:
2
-~ Division of 1.*ccasing, NRR l
backed up for loss of its power source but not for a fault on-the bus).
I Even though the second offsite source cannot be considered fully avail '
l able, the full two source availability is.a substantive safeguard against
{
bus power fai_ lure. - And, even if one of the four busses shculd fail, the 4
s worst case design event is acceptably responded to. -(In many cases, other redundancies and design margins would result in acceptable core cooling with two of the four busses inoperable.)
Resolution.of the above concern is complicated by the different mechanisms for modification of the technical specifications for the operating and the as yet unlicensed unit, Based upon our discussion, the licensee has found NRR' recep-tive to constructive change on the Unit 2 TS's to be issued, but is concerned about different TS's being a problem for similar units, and seems reluctant to simultaneously pursue different paths to change the TS's on the two plants.
'For the.Susquehanna TS's,'we request that NRR require the licensee to coordi-nate TS differences between units and require that changed requirements be'made l
applicable to both units, unless a difference in the plants makes a di.stinction In the case of IE bus power sources,-we recommend that the licensee necessary.
be. require.1 to submit TS's suitable for both plants, and allowing breaker /
component maintenance with safety. impact similar to that indicated herein to be accomplished without deleterious testing of unaffected EDG's.
Original signed Btt; Richard W. Starostecki, Director Division of Project and Resident Programs CC:
l T. Murley H. Denton kkartin i
S. Ebneter L. Plisco heA
4 RI:(CRF)se
)
RI:DPRP RI:DPRP McCabe/dag Greenman Staro#ec ki 2/7/84 VM OFFICIAL RECORD COPY l
l i
gy
> ; s, L
I ENCLOSURE 9 INDEPENDENT PROJECT EVALUATIONS
'SUSQUEHANNA UNIT 2 CONSTRUCTION & DESIGN (Using INPO Performance Objectives and Criteria)
Genera 1 From Oct'ber 18 - 29, 1982, an' evaluation of design and construction activities,.
o initiated by Pennsylvania Power & Light Company, was conducted by a team' of L
senior technical and management personnel from PP&L, G11bert Associates, and-
'R. K. Associates.
Conclusion This evaluation indicated that the Susquehanna Steam Electric Station is being u
- designed and built in'a controlled manner.
The team found very few significant.
= discrepancies.
Strengths The team concluded.that'the project was well-run' by Bechtel and closely supervised by PP&L.
Some specific strong points were:
1.
.PP&L and Dechtel managemen.t, at all levels,.was directly involved in daily project management and in the resolution of problems'.
2.
A strong Quality Control Inspection Program implemented by well-trained, competent personnel is being operated by Bechtel and closely monitored by PP&L.
3.
A strong commitment to industrial safety existed. There have been no accidental deaths and the milestone of one million manhours without a
-lost time accident has been passed twice.
Weaknesses Several weaknesses were noted and subsequently corrected:
1.
The installed length of electrical control cables was consistently about 40% greater than the scheduled (design) length.
Verification calculations have not been performed to ensure that the as-installed cables will meet the design voltage limits. A Deficiency Report was submitted by PP&L directing Bechtel to correct this situation.
(This issue was also being followed by the NRC.)
l l
4 1
t
.x 2
2<
The methodology for documenting and analyzing nonconforming conditions found during pipe support final.QC inspections may not have fully satis-
.fied 10 CFR 50 Appendix B.
Finding review by Bechtel and PP&L management concluded that the program met Appendix B.
3.
An excessive percentage of-pipe supports was being rejected by Quality
)
Control. Bechtel implemented a' program to upgrade the quality of-in-l process inspections of pipe hangers.
PP&L Project Construction then
{
closely monitored the progress of the hanger installations.
4.
No formal _ project-wide program had existed to ensure that changes to Unit One were evaluated for applicability to Unit Two and_vice versa. No comprehensive set of records showed the precise disposition of each i
Unit One change with respect to' Unit Two or each Unit Two change with regard to Unit One.
PP&L considered this finding technically correct.
However, PP&L had a high degree of confidence that~the functional config-uration of the two units is the same. This was based upon an extensive review of all change authorizing ~ documents conducted over the previous year, and upon the results of spot checks such as the one made during this evaluation. 'In 'the judgement of PP&L, it would not be cost effective to launch a comprehensive change tracking system at this stage of the project. However, PP&L upgraded the NPE Engineering Procedures Manual.
Specific provisions were included to ensure that all modifications are evaluated for unit applicability. The mechanics of tracking the modifi-cations vis-a-vis both units for the long term are being developed. They will be in place by the time that design responsibility for Unit Two is accepted by NPE.
l I
l 1
i
3
[s 1
J
~ ENCLOSURE 10 i
SUMMARY
i AS-BUILT CONSTRUCTION TEAM.
l INSPECTION 83-19 (DRAFT) j l
Scope The principle objective of this inspection was to confirm comple. tion of construction of Susquehanna Unit 2 in accordance with applicable codes standards, regulations and licensee commitments.
This was accomplished by examining por-tions of several safety-related systems in detail, reviewing the pre-service j
inspection program and data and independently performing confirmatory ultrasonic j
measurements. The ' detailed examination of systems involved comparison of physi-i cal layout with drawings, schematics and Final Safety Analysis Report (FSAR) description, including piping, supports and restraints, instrument tubing, in-struments and controls.
The systems examined were Standby Liquid Control Resi-dual Heat Removal (Loop B) and Control Rod Drive. Welder qualification, review j
of selected weld histories and the Induction Heating Stress Improvement (IHSI) program were also inspected.
Susquehanna Units 1 and 2 constitute two phases of a total construction project involving field fabrication and erection accomplished by using' essentially the same personnel and fabrication procedures. The quality assurance and quality control procedures and personnel were also largely the same. The primar3 re-sponsibility for field fabrication was delegated to the Bechtel Power Corpora-tion.
Inspections conducted by the NRC on Unit 1 in many cases represented review of fabrication activities for both units. A key aspect of this inspec-tion was to examine the selected systems for recurrence of problems noted in Unit 1; none were found.
Findings Three violations proposed; two strengths and three weaknesses were assessed in design, construction and engineering program controls; six unresolved items must be addressed.
Summary Conducted October 17 - 28, 1983; Nine region-based inspectors; 631 inspection-hours onsite, 70 hours8.101852e-4 days <br />0.0194 hours <br />1.157407e-4 weeks <br />2.6635e-5 months <br /> in-office. No significant discrepancies between engi-neering drawings and dimensional comparisons with, installed components.
The as-built plant conformed to drawings and the FSAR.
i
a.-
.3
. 0 2
' Proposed Violations.
(Draft of Inspection 83-19) 1.
('83-19-03, Severity. Level IV).
Complete ultrasonic preservice inspection of an RHR weld was precluded by weld edge contours which were inadequately prepared.
2.
(83-19-09, Severity Level V)
Small bore SLC pipe installation was not in accordance with the flex-leg design basis.in the engineering calculation.
3.
(83'-19-05, Severity Level V)
Cleanup Leak Detection System dual element temperature units were identified incorrectly on nameplates as single element units.
Strengths 1.
.Use of Induction Heating Stress Improvement to mitigate 'intergranular
. stress corrosion cracking prior to operation of the plant.
2.
The overall quality of welds observed and inspected was good.
~
-Weaknesses 1.
(83-19-02) y Control of plant configuration was less than adequate in that not all J
maintenance and calibrations involving equipment removal ~were well-tracked.
2.
(83-19-04)
Plant cleanliness had not reached an operational readiness level.
3.
(83-19-06)
Licensee staff involvement in developing and implementing the program for Preservice Inspection of welds and reviewing the data obtained from this program was minimal.
l i
___Y E-_ E. -_ - - -- -
l;
. 0 3
(Draft of Inspection 83-19)
DETAILS As-Built Conditions of Selected Safety-Related Systems Portions of three safety-related systems were examined.
The entire Standby Liyuid Control (SLC) system was examined except for an inaccessible portion between the biological shield wall and the reactor vessel. The "B" Loop of the Residual Heat Removal (RHR) system was examined from its penetration of the recirculation piping to the RHR pumps.
Selected sections of the Control Rod Drive system were also examined. Piping was compared to flow diagrams, selected dimensioned isometric drawings and FSAR descriptions.
Selected supports were compared with their detailed drawings.
Small bore piping and instrumentation tubing were compared to selected isometrics.
Electri, cal instrumentation and control wiring was checked against drawings, schematics and FSAR description.
Inspection of the piping, pipe supports and restraints, and instrumentation and controls for SLC showed that, with one minor dimensional discrepancy, the SLC system was built in conformance with designs and requirements. A violation for failing to correctly translate design information into con-struction was also identified in one instance.
Control Rod Drive (CRD):
Inspection of portions of the CRD piping including discharge headers, instrumented volume headers, valves, drain and vent lines resulted in the conclusion that corrective actions meet the FSAR and IE Bulletin 80-17.
A lack of configuration control for pipe supports for the CR0 scram system was identified: three pipe clamps on gang frames were loose or twisted.
This finding forms part of the basis for an assessment of weakness in control of as-built plant configwation.
An as-built walkdown inspection of twelve large bore RHR pipe segments was performed.
Specific system components such as pumps, flanges, elbows, tees, bends, heat exchangers, welds and valves were examined for confor-mance to ASME Section III requirements and as'-built drawings.
I Portions of the small bore piping in the RHR system were selected for walkdown inspection. The portions examined were drain, vent or instrument attachments, nominally of 1" diameter, connected to the large bore piping.
Also identified was a Reactor Building column at elevation 645' for which s
a design calculation is to be reviewed (83-19-01).
1 I
9.*
l.
. 0 4
(Draft of Inspection 83-19)
Preservice Inspection (PSI) Progrem ASME Section XI Requirements for RHR and Reactor Recirculation Systems (Class I and 2 Code welds) were found to be met; however.PP&L staff unfamiliarity with the PSI contractor's work contributed to' the assessed weakness in licensee involvement in this program.
H i
Selected ultrasonic examination data for 167 ASME Class 1 and 2 welds in Core Spray, RHR, Main Steam and RWCU Systems were reviewed. Volumetric UT of nine weldments, independently selected by NRC inspectors, indicated areas where a more complete evaluation (e.g., independent verification) of NDE results was needed. This contributed to the above weakness, and to an unresolved item to re perform radiography on an RHR weld (83-19-07).
Welder Qualification This.was an'indepth review of the program including inspection.of the facilities, observation of welder qualification, review of methods used for preventing falsification, inspection of equipment, and interviews with personnel (including welders).
No indication of falsification of quali-fication records or other improprieties were noted. The activities meet applicable Codes and Standards requirements. Although the system lacks overview by independent organizations, there is QC surveillance and random Authorized Nuclear Inspector (ANI) checks.
Weld Quality Records Quality Control Inspection Reports were reviewed for conformance to Speci-fication and ASME B&PV Code Section III requirements. The records reviewed were selected from welds identified in RHR system walkdown inspections, a sample from the main steamline, and random welds. Carbon steel and stain-less steel weld records for original and repair welds on large pipe and small pipe systems were reviewed.
Records reviewed included applicable NDE examinations conducted and results of these examinations. Complete welder qualification record files for welders identified in the specific weld joint quality records were checked in both the Document Control Record System and the Weld Test Shop files.
These records covered the complete range of qualifications, not just the records applicable to specific joint records.,
In summary, the weld quality records examined in walkdown inspections and random selections met Bechtel and ASME Code requirements.
1 I
- 4 f'
s
,. 0 5
(Draft-of Inspection 83-19)
Control of Welding in the Plant Modification Organization (PMO) 1 The licensee and Bechtel established an interim organization to control activities upon completion of field fabrication and erection and until such time as'the licensee assumes full supervision of all activities.
The PMO control of welding procedures meets applicable ASME, ANSI and AWS Codes and Standards requirements and also provides for systematic control of "Non-Q" welding. The PMO program as constituted represents a system for controlling welding that is familiar to the licensee personnel as being essentially a continuation of the Bechtel construction program.
a Valve Material Certifications The inspector-reviewed material certification and QA documentation for selected valves in the RHR process system being examined by the inspection team. The certification and documentation packages were reviewed for con-formance to Specification and ASME Section III material requirements. The valves reviewed were made by Pacific Valves utilizing Pacific Southern Foundry castings and Anchor-Darling valves using Dodge Steel Castings.
Post-weld heat treatment (PWHT) of the Anchor-Darling Valves was consis-tent with normal metallurgical practice.- The Pacific valves reviewed indicated that the castings were repair welded in the as-cast condition, i.e., a supercritical (1650F) normalizing heat treatment which is not con-sistent with standard practice. The supercritical PWHT invalidates the filler metal material certifications which were tested in a subcritical simulated PWHT, and constitutes an unresolved item (83-19-08).
Induction Heating Stress Improvement (IHSI)
The inspector reviewed the data package for heat treatment of austenitic-stainless steel weldments to mitigate intergranular stress corrosion crack-ing (SGSCC). The licensee subcontracted Ishikawajimama-Harima Heavy Indus-tries Nuclear Power Division (IHI) to conduct an IHSI treatment on a total of 105 welds. Prompt action to negate the potential for IGSCC by utiliza-tion of the IHSI treatment is considered a strength in the licensee's program.
i L
g n
i r
c e
n e
I n.
s t
ic e
n gn t
a C
nI r
a t
S E
a i
l A
e c
u W
es l
o s
ne c
s n
yc u
s o
di N
A C
G ev S
l r S
R T
G ee D
P N
E TS E
M ATL US N
N O
O I
C d
d d
w l
n T
n e
u e
o ayo A
E earn assn tse l
vci T
D h
oo tus aaddf eat S
I t nf C p
ed l eae uc S
o eyre er id mqu
)
C T
fisd cgtt Ranfn eer:B
,n tl e
. ) 'o ' o'a o c :.
cosa gi a tdtm I
U R
O al l
yd i c sasepeom s:
T i
wtrn ome tesee y
ntot C
Y t
enta edrrs etepr seosos 1
E D
p ienv hoo m
fadsu h c yL y 1
L i
vmod thfye al s
dt s(
E E
S r
eucA trtt js l
f e,pf y S. R o.i e ayngmys i
d e ir r
R ees i
W c
rc
~
S M
E s
o ya~
o m, n
f a r; faneas 0
A I
e tdtn
'a s iy tp ni itr o e go E
V D
n i n teos
- tdn, wrnwspri lC T
E e
,l a nht g
seei NE S
R e
dgah et f n mf wae.
dvilS p
nnue.
m loi eaemrs k
sl A
Y o
ei qu m sfe p
tSi un loeoRrgja N
T c
pr qo so tsi s
voto atdfl i
N R
S eetso e
h ep ynetai w
R A
A decuR sy cs Sor rt nee P
nneS stoyr n
yoi dohh - -
I E
iij l
aiBl a C
o c pd litt U
D goeo l
ae Adramn et Q
R nnrhr ni y nl Vnouao inff S
I A e pt t Abbac awqtc Fuoo I
I U
l i
S T
L A
I CE y
P g
S e
o h
l t
o fm o
C N
d w
oo h
A o
o e
tR t
Vs d
e Hn k
l n
M o
l t
el fi a
. i mo, s
ot W
T sr i
ia st s
wl m
y-eu e
w en e
so l
i c t
i sC a
vl ys v
A n
ea e
d A
RC S
R ye tc g
nm.
y in n
ge t
la i
it e
av p
ss f
Mi i
ey.
b d
b 3
?
l s
a i
n s
o y
i t
t l.
n ac r
a a
nn a
n t
AI e
r l
l e
u e,
c t
s r.
u n
n uc N
I S
o lo T
C is S
I N
as D
R e
A FA E
S ce T
e L
U B
S N
N O
0 L
0 O
C G
I 0
T E
n y
P 2
A D
o oal c-Pn E
T I
ci t
ld ac o
0 S
S
- et fie un ri 5
T epal sowt quton E
C U
txla n
a efsfU neum oeml d
e G
I O
4[n. l' dr iree a gt d k RT Y
o ere tutr n
er C
B i
ec1h ali -
eidpe E
t hncT ui y
hcnow L
S p
tae ladt tralt E.
W i
mRon afee o
f I
E r
f, r. t o v
tf f f yv p M
I c.o'o e
i o e 4 a.
q gor A
V s
fhdt hl s codK E
E e
trtnc dte nil T
R D
ne Ee n
ra omony S
epr n
at-iadob Y
e m
oen ayt tnoi A
T p
sdffo shtc a yh t s N
R o
sn ac ntea udtar N
A c
easS w
f p l
ece A
P S
s n
e oeam.
aemih syotv drsi vh f c l
E D
atiee ku-m e t ni n l
U R
itl e lsnte oro Q
I nranl anoot nfi eu S
A gt I S Wenni AotvQ I
I U
T S
LA I
CE P
S
)
1
/
n.
9 2
o i.
(
t s
w i
s e
dn rn v
af eg i-ni b
ti e
e e
sk R
VD e %
R' l
c t
ra' t
Sd i
ar c
a T
lc a
to u
p nL w
nn m
e e
ao I
mg i
ri nn v
gs y
ii e
ro t
ag R
er e
tg 9
tr f
'n u no a
oh g
Is '
B s
l
[.
- p..
i' ENCLOSURE 13
'Recent Operational Problems (Related to Unit 1 Plant / System Control)
After the recent Unit 1/ Unit 2 tie-in outage, Unit I startup was marred on February 21, 1984 because two Reactor Core Isolation Cooling (RCIC)
System test connection valves had been left open. Escaping steam caused high temperatures in the RCIC Room and RCIC inoperability. The licensee determined that, contrary to specific instructions by the Plant Superin-tendent, post-outage system valve lineups had not been fully performed; portions of pre-outage lineups had been used for the post-outage lineup certification. Apparent Technical Specification violations of High Pres-sure Coolant Injection (HPCI) and RCIC System operability have been iden-tified as a result of increasing primary system pressure above 150 psi with the invalid valve lineup.
Failure to properly align systems after an extended outage is another apparent violation.
On January 26, 1984, approximately 10,000 gallons of Condensate Storage Tank water was spilled onto the Turbine Building floor while draining the Unit I reactor cavity due to a mispositioned valve (IR 387/83-28).
During January 19 - 24, 1984, the SBGTS malfunctioned at least seven times while performing preoperational tests..The system was undergoing modifica-tion and was not operated with an approved procedure (IR 387/83-29, Level IV violation proposed).
On December 9, 1983, due to operator inattention, reactor coolant tempera-ture increased to 150*F while in Operational Condition 5 (LER 83-161, IR 387/83-25, Level IV violation).
From November 3, 1983 to November 5, 1983, both channels of Main Condenser Offgas Treatment System explosive gas (hydrogen) monitoring were inoperable for about 51 hours5.902778e-4 days <br />0.0142 hours <br />8.43254e-5 weeks <br />1.94055e-5 months <br /> due to operator error during the valve lineup and in-effective response to alarms (IR 387/83-24 Enforcement Conference held December 13, 1983, two proposed Level IV violations).
From May 24, 1983 until June 7, 1983, the plant was operated with the mode switch in "Run" and none of the three channels of the main turbine trip system activation instrumentation were operable because they were bypassed due to previous modification work (IR 387/83-14, Level IV violation).
Standby Gas Treatment Inoperability during February 28 - March 1, 1983 (Civil Penalty imposed on April 22, 1983 - see, enclosed NRC Press Release).
e e
e 3 2
Analysis of Recent Unit 1 Operational-Related problems Overall, we have a concern that, although vigorous and extensive corrective action is normally a licensee characteristic, there are repetitive indications that off-normal plant conditions are not viewed by licensee personnel in their proper safety perspective.
Further, there seems to be a piecemeal approach to corrective actfons. We have interpreted the licensee's response to the various enforcement issues as follows:
(1) for the SGTS civil penalty, as being focused on the licensed staff; (2) for the surveillance inadequacies, as being focused on operator interface with supporting groups; (3) for the hydrogen analyzer lineup, as being primarily a non-licensed operator problem; (4) for the cold functional test problem, as being a preoperational test consideration without operational significance; and, (5) for the post outage lineup problem as a failure to comply with instructions. Our interpretations are premature for the cold functional test and the post-outage lineup in that the licensee has not yet had the opportunity to respond formally, Region I views these problems differently.
Each represents an abnormal plant condition. The licensee's lack of timely attention / response to off-normal con-ditions indicates that personnel operating the plant are simply not looking at certain plant conditions critically enough. We do not believe that individuals responsible for plant lineups should personally accept non performance of parts of those lineups after an extensive, 79-day outage. We do not believe that SGTS fan trips. should be summarily classed as insignificant and repeated seven times.
We are disturbed that five consecutive shifts did not react to a hydrogen anal-yzer alarm. We consider insufficient emphasis on Technical Specification re-quirements as a contributor to several occurrences. Underlying all this, we perceive an untoward willingness to dismiss abnormal plant circumstances.
Balancing this viewpoint is the fact that major plant protection and safeguards functions have not been significantly disabled, and component inoperabilities affecting those functions have been quickly corrected.
For example, the post-outage lineup errors found by the licensee on February 21, 1984 were relatively minor; the re-verification checks were extensive, and neither HPCI nor RCIC were inoperable for a prolonged time during operation. The problem, as we see it, is one of the range of critical attention, and a lack of sufficient emphasis upon making sure that everything is working the way it should.
This is a pro-blem in need of strong licensee management attention, yet not one which justi-fies a hold on operation of either unit.
We plan a special team inspection focused upon two unit operations early during the Unit 2 startup period, and our evaluation of this nrea must also consider the licensee's input during a meeting we plan to hold with them in the near future.
ENCLOSURE 13 C
UNITED STATES fM"%g NUCLEAR REGULATORY COMMISSION
[gq OFFICE OF PUBLIC AFFAIRS, REGION I
%qg 631 Park Avenue, King of Prussia, Pa.19406
. April 22, 1983 N3.
I-83-44
Contact:
Karl Abraham Tel.:
215/337-5330 5000 NRC STAFF ALLEGES VIOLATION OF OPERATING PROCEDURES AT SUSQUEHANNA UNIT 1; PROPOSES TO FINE PENNSYLVANIA POWER & LIGHT COMPANY 560,000.
The Staff of the Nuclear Regulatory Commission has cited the Pennsylvania Power and Light Company for al.leged violation of certain requirements in the technical specifications of its operating license for the Susquehanna Steam Electric Station Unit ? near Berwick, Pennsylvania.
The staff proposes to
' ' fine the company 56P,03.
On March 2,1983, utility officials reported to the NRC Resident Inspector j
that plant workers had randered two duplicate subsystems of the standby gas treatment system (SGTS) inoperable during February 28 and March 1, yet operae tion of the plant had cent f aued.
Under the technical specifications of the operating license for Su pahanna, the company mu.st begin within one hour to shut the plant down any time both subsystems of the standby gas treatment system become inoperable.
NRC inspectors included an examination of these circumstances in an inspection that had begun on January 12 and ended on March 8, 1983.
t i
The standby gas treatment system is one of the means used to reduce the quantity of radioactive gases that may be released from a nuclear power plant j
in the event of an accident. Because there was no accident in connection with j
i these occurrences, the disabled condition of the SGTS did not endanger either i
workers at the plant or the public.
The NRC staff alleges that on February 28, 1983, one of the two SGTS subsystems was taken out of service in order to remove some test cannisters that help measure the efficiency of radioactive iodine removal from radio-active gases generated when the plant is running. Because of inadequate review and approval of this maintenance activity, electric power was also cut to the other subsystem, thereby making both subsyctems inoperable.
j Although alarms sounded in the control room for bott. the subsystem that was intended to be shut down, and for the second subsystem that should have remained in operation, the NRC staff alleges that "the indications and alams were not adequately investigated, and the alarms were not entered into logs during shifts and at shift turnovers as required by procedures, indicating that operators were not aware of the inoperability of both SGTS subsystems,"
according to the Notice of Violation sent to the company.
~
(MORE)
r,,
a.
I f
l
- s,a J
l 2
After completion of maintenance on one subsystem on March 1,1983, an I
attempt was made to start it. After some difficulties, the subsystem finally was started. Not until about 3 p.m. that day did workers realize that both 3
subsystems had been inoperable for approximately 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> on February 28, and i
March 1, because of open circuit breakers in both systems.
In a letter to the company, James M. Allan, Acting Regional Administrator, said that "had the alarm response procedure been more thorough and had the operators been properly trained and attentive to the procedure, the fact that both standby gas treatment subsystems were inoperable could have been recognized sooner".
The company has 30 days to either pay the proposed fine or to request in writing that part or all of it be withdrawn.
The company also has 30 days to write to the NRC staff what it has done or will do to assure that these alleged violations do not recur.
The Commonwealth of Pennsylvania has been informed of this proposed enforcement action.
9 l
,1 t
m__m_-__m.-_-
- _ - _ -