ML20214T277
| ML20214T277 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom, 05000000 |
| Issue date: | 02/26/1986 |
| From: | Starostecki R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | Jordan E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE) |
| Shared Package | |
| ML20213E720 | List: |
| References | |
| FOIA-86-729 NUDOCS 8612080544 | |
| Download: ML20214T277 (5) | |
See also: IR 05000277/1985029
Text
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l q MEMORANDUM FOR: Edyard L. Jordan, Director, Division of
Emergency Preparedness and Engineering Response
FROM: Richard W. Starostecki, Director, Division of
Reactor, Projects
SUBJECT: REPORTABILITY UNDER 10 CFR 50.72 AND 50.73
As a result of our efforts to collect data relative to certain performance
indicators we are trending, we have found that licensees do not report certain
ESF or RPS actuations. During a recent inspection at the Peach Bottom Atomic-
Power Station-(Combined Inspection Report Nos. 50-277/85-29; 50-278/85-33
attached, refer to pgs 7, 8, & 9), the Resident Inspector identified a failure
by the licensee to report certain events as required by 10 CFR 50.72 and 50.73.
The failure to make the required reports was the subject of a Notice of
Violation.
In a January 21, 1986 response (attached), the licensee states that the events
have since been reported by LER but contends that NUREG-1022, " Licensee Event
Report System Description of System and Guidelines for Reporting" supports an
interpretation of 10 CFR 50.72 and 50.73 that the events were not reportable.
The licensee has selectively used portions of the NUREG to support its position.
I am concerned that the licensee's misunderstanding of the basis and purpose
)
for reporting safety system actuations may be snared by other licensees. Our
limited site reviews indicate inconsistencies in licensee reporting of safety
system challenges and a general lack of industry appreciation for the reporting
philosophy. It is our position that the events described in the Notice of
Violation were reportable in accordance with 10 CFR 50.72 and 50.73, and
consistent with the guidance provided by the NRC in the Code of Federal
Regulations and NUREG-1022, with supplements. In fact, as noted in the
attached inspection report, an adequate administrative procedure was bypassed
to allow non-reporting of the events.
I have attached a summary of our response to each of the licensee's arguments
and request your review. I suggest that the results of the IE and AE00 reviews
be disseminated through an IE Information Notice to assure a consistent
position. By copy of this mcmo, I am also alerting AE00 to this issue of
interpretatic,. If you need further details, please feel free to contact R.
Gallo, the Section Chief for Peach Bottom (488-1234).
20
REPKA96-729
4 861201
.[ l( 7 M-
Rich'ard W. Starostecki, Director
,, Division of Reactor Projects
Enclosures: As stated ,
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UB 2 61986
cc:
G. Holahan, NRR
J. Partlow, IE '
J. Heltemes, AE00
J. Sniezek, DEDROGR
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REGION I POSITIONS
1. The licensee argi[es on page 8 as follows:
"Section V of NUREG-1022 states, 'Actuations that need not be reported
are those initiated for reasons other than to mitigate the consequences
of an event'. The actuations discussed in this violation occurred
while there was no fuel in the reactor vessel. These actuations had
been evaluated as actuations which were not initiated to mitigate the
consequences of an event."
The licensee's quotation from NUREG-1022 is an example of quoting
out of context. First, only part of the sentence was quoted; the
the complete sentence is as follows:
"Actuations that need not be reported are those initiated for
reasons other than to mitigate the consequences of an event
(e.g., at the discretion of the litansea as part of a planned
precedure or evolution)."
The addition of the parenthetical example makes it clear that the
guidance was directed at pre planned or elective actuations only.
Second, the licensee's quotation is from the last sentence of a
section whose lead paragraph clearly refutes the licensee's
interpretation:
. . .
"[ Paragraph 50.73(a)(2)(iv)] requires events to be reported
whenever an ESF actuates either manually or automatically,
regardless of plant status. It is based on the premise that the
ESFs are provided to mitigate the consequences of a
significant event and, therefore, (1) they should work properly
when called upon, and (2) they should not be challenged
frequently or unnecessarily. The Commission is interested both
in events where an ESF was needed to mitigate the consequences
(whether or not the equipment performed properly) and events
where an ESF operated unnecessarily."
2. The licensee argues on page 8 that because the reactor was defueled,
that the RPS was not only not required to be operable, but also was
removed from service such that RPS actuations were not reportable.
The licensee quotes from Supplement 1 to NUREG-1022 in support of this
argument. The entire section is provided below with the portion quoted
by the licensee underlined.
!
6.9 Is the spurious operation of a system that is not required
to be operable reportable?
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Region I. Positions 2
Answer: If the system is not required to be operable and it has
been properly removed from service such that it can not
perform its intended function (e.g., manual discharge
valves are shut, breakers are open), then a spurious
actuation of part of the system (e.g., the pump starts but
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the discharge valve remains shut) is not reportable.
However, if the system actuates and performs its intended
function, the actuation is reportable even if the system
is not required to be operational.
First the licensee has again quoted out of context and omitted a clarify-
ing parenthetical expression. Physically disabling a system by opening
breakers or shutting valves is quite different from defueling the reactor
vessel in that the RPS receives initiating signals and attempts to move
the control rods. Tagging out the Control Rod Drive system to prevent
rod motion or deenergizing RPS would be valid ways to remove RPS from
service if permitted by technical specifications.
, Second, the licensee has quoted from Question 6.9 when Question 6.7
(on the same page) refutes the licensee's argument:
6.7 Often we are in operating modes when automatic scrams are ,
not required to be operable, or parts of the containment
isolation system may actuate when the system is not
required to be operable. Are such events reportable as
LERs?
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Answer: Yes. Actuations of ESF and RPS are reportable even if
, they are spurious or unnecessary. However, if the
actuation or trip is part of a preplanned sequence, or it
is a controlled (e.g. documented) and expected result of
, the procedure (see question 6.8), it is not reportable
under this criterion (see also question 6.9).
3. The licensee states on page 9 that seven of the events produced only a
single channel trip and that the scram signal resulted because the other
channel was already in a tripped condition. The licensee argues that
because the seven events "only produced a single channel actuation, they
were not, in themselves, sufficient to complete the minimum actuation
logic." The licensee quotes from NUREG-1022 in support of the argument:
" Additionally, NUREG-1022 states that '" Actuation" of multi-channel
ESF actuation systems is defined as actuation of enough channels to ~
- complete the minimum actuation logic ... Therefore, single channel
actuations, whether caused by failures or otherwise, are not
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reportable if they do not complete the minimum actuation logic'"
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Region I Positions 3
For the third time, the licensee has omitted a clarifying parenthetical
expression which refutes their argument. Omitted at the dots in the
quotation is the following:
"(i.e, activation of sufficient channels to cause activation of the
ESF Actuation System)"
In the seven cases cited by the licensee, the tripped condition of one channel
allowed the single channel activation to be sufficient to complete the minimum
actuation logic and cause the ESF actuation, in this case a scram generated by
the RPS.
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. PHILADELPHIA ELECTRIC COMPANY
2301 MARKET STREET
P.O. BOX 8699
PHILADELPHI A. PA.19101
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==JJ"E""Ji.- January 21, 1986 '
Docket Nos. 50-277
50-278
Inspection Report Nos. 50-277/85 ,
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50-278/85
i Mr. Samuel J. , Collins, Chief
Projects Branch 2
Division of Reactor Projects
U.S. Nuclear Regulatory Commission
Region I
631 Park Avenue '
King of Prussia, PA 19406
Dear Mr. Collins: .
Your letter dated December 20, 1985 forwarded
Combined Inspection Report Nos. 50-277/85-29; 50-278/85-33 for
Peach Bottom Atomic Power Station. Appendix A of your letter
addresses four items which do not appear to be in full compliance
with Nuclear Regulatory Commission requirements. These items are
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restated below followed by our responses.
I. Restatement of Violation
Technical Specification 6.8.1 and Regulatory Guide 1.33,
November 1972, require implementation of procedures for
j surveillance testing.
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l Surveillance Test Procedure ST 4.9.B, Portal Monitor
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Calibration and Source Check, requires a quarterly source
check and a semi-annual calibration of the portal monitors
throughout the plant, including portal monitor number 332.
Contrary to the above from about July 7,1985 to September
25, 1985, portal monitor nusber 332 was overdue for
calibration and in use at the 165 foot elevation of the
administration building bridge, and the semi-annual
calibration had not been performed since January 7,1985.
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, Mr'. Scmual J. Collins January 21, 1986
Page 2
This is a Severity Level IV Violation (Supplement 1)
applicable to DPR-44 and DPR-56.
.
Admission of Alleged Violation:
Philadelphia Electric Company acknowledges the violation
as stated.
Reason for Violations
l The station Instrument and Controls (IEC) Group
establishes the priorities of the Instrument Lab Group in
accordance with the requirements of the station and is
responsible for ensuring that surveillance tests which are
assignsd to the Instrument Lab and issued through the I&C
Group are completed in a timely manner. Although the
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subject surveillance test was issued in a timely manner,
the Instrument Lab individuals responsible for performing
health physics-related instrument surveillance tests were
redirected by the station Health Physics Group to assist
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with other radiation monitoring instrument work associated
with the Unit 2 pipe replacement outage and with
preparation for the Unit 3 refueling outage which started
in July, 1985. During this time period, the station IEC
Group failed to ensure that the test was completed in a
timely manner.
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significance of violation:
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ST 4.9.B controls the calibration and source check of the
j Eberline Portal Monitors, Model PMC-4, which are used as a
i . backup to the new and more sensitive Instrumentation
l Research Technology (IRT) Portal Monitors, Model PRM-110.
1 The subject Portal Monitor 332 is located in the Annex
l Bridge connecting the Turbine Building 0Blevation 165') to
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the Administration Building. The IRT portal monitors are
the primary monitors used at the exit of the Main Guard
House. All personnel must pass through the portal
monitors at the Main Guard House prior to exiting the
Peach Bottom site. The IRTs at the Main Guard House were
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in proper calibration during the period of time when the
calibration of Portal Monitor 332 was past due.
i Therefore, the IRTs would have prevented contamination
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from being carried off-site. The Annex Bridge portal
, monitor is used to control the potential spread of
! contamination to the Administration Building. Use of this
- bridge is restricted to authorized personnel. Although
l Portal Monitor 332 had not been calibrated since January
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Mr. Scmu21 J. Collins January 21, 1986
Pcgo 3
7, 1985, this monitor was source checked satisfactorily on
April 2, 1985.
Corrective &ctions Taken and Results Achieved:
ST-4.9.B was successfully performed on September 25, 1985,
immediately af ter it was discovered that the semi-annual
calibration of Portal Monitor 332 had not been performed
as required.
Corrective Actions Taken to Avoid Future Non-Compliance:
Responsibility for completion of ST-4.9.B has been
transferred from the station IsC Group to the station
Health' Physics Group because the portal monitors are more
closely related to health physics instrumentation. The
Senior Health Physicist is now responsible for ensuring
timely completion of this test.
Additionally, the instrument lab has established a
tracking mechanism to be used for controlling tests that
are not performed in a timely manner. All instrument
technicians have been instructed to use this tracking
mechanism.
Date When Full Compliance was Achieved:
Full compliance was achieved on September 25, 1985 when
ST-4.9.B was completed satisfactorily.
II. Restatement of Violation
Technical Specification 6.8.1 and Regulatory Guide 1.33,
November 1972, require that written procedures and
administrative policies be established, implemented and
maintained.
Administrative Procedures A-26, Rev. 24, and A-26A, Rev.
2, state that the Control Operators shall prepare blocking
permits. Procedure A-2 states that revised Administrative
Procedures must contain equivalent, more conservative, or
additional requirements to be issued on an expedited
basis. .s
Contrary to the above 1) In early September 1985, a
practice was instituted allowing Plant Operators-Nuclear
to prepare blocking permits; and 2) on October 11, 1985,
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Mr. Stmusl J. Collins January 21, 1986
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an expedited change to A-26 and A-26A was made, which
eliminated the requirement that Control Operators prepare
blocking permits, and did not contain equivalent, more
conservative or additional requirements.
. This is a Severity Level IV violation (Supplement 1)
applicable to DPR-44 and DPR-56.
Admission of Alleged violation:
Philadelphia Electric Company (PECo) agrees that a
practice was instituted allowing Plant Operators - Nuclear
to prepare blocking permits and that an expedited change
to Administrative Procedures A-26 and A-26A was made on
October. 11, 1985; however, PECo does not believe that
these 4xpedited changes were made in a less conservative
direction.
Reason for Violation:
The practice of allowing Plant Operators - Nuclear to
prepare blocking permits was instituted in September,1985
due to the heavy workload involved with the preparation of
blocking permits. On October 11, 1985, it was realized
that Administrative Procedures A-26 and A-26A had not been
complied with because these procedures specifically
required that a Control Ope'rator prepare blocking permits.
The Plant Operations and Review Committee (FGRC) met on
October 11, 1985 to discuss and approve revision of A-26
and A-26A to allow Plant Operators - Nuclear to prepare
blocking permits. The expedited procedural changes were
reviewed and approved by the Quality Assurance (QA)
Division that same day. When Procedures A-26 and A-26A
were originally written, rather than specify the
individuals who were approved to write permits by name,
the generic title of Control Operator was used because all
of the individuals involved at that time were Control
Operator s. This assignment of responsibility was not
intended to limit the individuals who could write permits
exclusively to those in the control Operator position. In
addition, it is our position that these procedural changes
were not made in a less conservative direction because:
(1) Plant Operators - Nuclear are intimately involved with
the plant equipment and have completed training programs
similar to that of Control Room Operators in the area of
plant equipment knowledge andotherefore have knowledge
similar to that of Control Operators (due to the nature of
their day-to-day activities), (2) Shift supervision is
responsiblq for ensuring all blocking permits are
adequate, regardless of who prepares the blocking permits,
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Mr. - Samual J. Collins January 21, 1986 l
Page 5
and (3) Prior to permitting the selected Plant Operators -
Nuclear (PO-N) to prepare blocking permits, each PO-N was
given one day of individual refresher training in the use
- of the Blocking and Permits Handbook by a qualified
- instructor. This instruction is equivalent to the
- instruction provided to Control Operators in this subject
area.
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Corrective Actions Taken and Results Achieved:
As stated previously, Procedures A-26 and A-26A were
approved by the PORC on October 11, 1985 and the QA
Division performed an expedited review of these procedures
on that same date. These changes allowed shift
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supervision to direct preparation of a blocking permit, as
necess&ry, thereby satisfying QA requirements as well as
station requirements.
Corrective Actions to be Taken to Avoid Future
, Non-Compliance
The corrective actions stated above will prevent
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recurrence.
- Date When Full Compliance Was Achieved
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?ull coupliance was achieved on October 16, 1985 when QA
Division completed the standard review of the changes to
A-26 and A-26A.
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III. Restatement of Violation
Technical Specification paragraph 4.6.D.4 requires that
each main steam safety relief valve be manually opened
once per operating cycle with the reactor pressure equal
to or greater than 100 psig to demonstrate its ability to
pass steam. Surveillance Test 10.4, Relief Valve Manual
Actuation, implements this requirement.
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Contrary to the above, no manual test of relief valves 71
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B, G, and K were performed on Unit 3 during the operating '
cycle 6 f rom September,1983 to July,1985.
This is a Severity Level IV Violation (Supplement 1)
applicable to DPR-56.
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Mr. Scaual J. Collins January 21, 1986
... PEge 6
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Admission of Alleged violation:
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Philadelphia Electric Company acknowledges the violation
as stated. '
,A
Reason for Violation:
Surveillance Test ST-10.4 (Relief Valve Manual Actuation)
was performed during Unit 3 reactor startup on September
3, 1983. A review of this test indicates that not all of
the safety relief valves were tested at that time. There
appears to have been an oversight on the part of the
personnel who performed and reviewed the test because, if
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all the relief valves were not tested, the test should
have been treated as a " partial test" under the
requirdments of Administrative Procedure A-3 (Procedure
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for Temporary Changes to Approved Procedures) . If the
test had been marked up as a " partial test" as required by
A-3, the Surveillance Test Coordinator would have known to
reissue ST-10.4 to check the relief valves that were not
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previously tested. However, because the test was not
properly marked up as being a " partial test", ST-10.4 was
not reissued. The reason for the violation was failure to
properly follow Administrative Procedure A-3.
! Corrective Actions Taken and Results Achieved
The personnel responsible for performing and reviewing the
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subject surveillance test have been counseled on the
proper method of handling " partial tests" in accordance
with Administrative Procedure A-3.
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Corrective Actions to be Taken to Avoid Future Non-
Compliance:
The Operations Engineer has issued a meno to shift
!. operating personnel concerning the proper method of
handling " partial tests" in accordance with Administrative
Procedure A-3. In addition, the duties of the
Surveillance Test Coordinator will be reviewed in light of
this violation with the intent of strengthening this ,
, function to prevent recurrences of this type.
, Date When Full Compliance Will Be Achieved:
- Unit 3 is currently in a refueling and maintenance outage.
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ST-10.4 is,. scheduled to be performed during Unit 3 startup
j which is currently scheduled for January 27, 1986.
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Mr. Semual J. Collino Jcnuary 21, 1986
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Page 7
Satisf actory performance of ST-10.4 will satisfy Technical
Specification 4.6.D.4.
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IV. Restatement of Violation
10 CFR 50.72 requires that the licensee notify the NRC
Operations Center via the Emergency Notification System
within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and 10 CFR 50.73 requires the preparation
of a Licensee Event Report of any event or condition that
results in manual or automatic actuation of any engineered
safety feature, including the reactor protection system.
Contrary to the above, eight reactor protection system
actuations occurred between August 29 and October 10, 1985
and, as of October 25, 1985, no reports were made to the
NRC.
This is a Severity Level IV Violation (Supplement 1)
applicable to DPR-56.
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Admission of Alleged Violation:
Philadelphia Electric Company agrees that eight actuations
of the Reactor Protection System (RPS) occurred between
August 29, 1985 and October.10,1985 at Peach Bottom Unit
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3 and that none of these actuations were reported under
the requirements of 10 CFR 50.72 and 10 CFR 50.73.
Reason for Violation:
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j The cause of the late reporting of these events was due to
, an interpretation of 10 CFR 50.72 and 10 CFR 50.73
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reporting requirements. Seven of the eight RPS actuations
- involved initiation of full scram signals due to false
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Intermediate Range Monitor (IRM) high flux signals. The
remaining RPS actuation involved a false scram discharge
volume high level signal. The eight actuations occurred
! with Unit 3 shutdown for refueling and no fuel in the
, reactor vessel. At the time of the events, it wa's
believed that RPS actuations, which occurred when the fuel
was completely removed from the reactor vessel, and whose
initiating signals were caused by other than the flux
sensing detectors, were not reportable. NUREG-1022,
, titled, " Licensee Event Report System - Description of
- System and Guidelines for Reporting",* the guidelines which
were published with 10 CFR 50.72 and 10 CFR 50.73 in the
Federal Register, the PBAPS Technical Specifications, and
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Mr. Scmu21 J. Collins January 21, 1986
Page 8
plant design analyses support this interpretation of the
reporting requirements of 10 CFR 50.72 and 10 CFR 50.73.
Section V of NUREG-1022, which provides a paragraph-by-
paragraph explanation of the LER Rule, contains guidance
for Paragraph 10 CFR 50.73 (a) (2) (iv) concerning
reportability of actuations of any engineered safety
feature, including RPS.Section V of NUREG-1022 states,
"Actuations that need not be reported are those initiated
for reasons other than to mitigate the consequences of an
event". The actuations discussed in this violation
occurred while there was no fuel in the reactor vessel.
These actuations had been evaluated as actuations which
were not initiated to mitigate the consequences of an
event.
Techni6al Specification Bases 3.1, concerning the Reactor
Protection System, states that "When there is no fuel in
the reactor, the scram serves no function; therefore, the
Reactor Protection System is not required to be operable".
The Updated Final Safety Analysis Report (Section 7.2.1)
states that "The safety objective of the RPS is to provide
timely protection against the onset and consequences of
conditions that threaten the integrities of the fuel
barrier and the nuclear system process barrier. .. . The
RPS limits the uncontrolled release of radioactive
material from the fuel and the nuclear system process
barrier by terminating excessive temperature and pressure
increases through the init'iation of an automatic scram".
These design objectives clearly indicate that an RPS
actuation which occurs when no fuel is in the vessel
serves no safety function.
In NUREG-1022, Supplement No.1, in the " Questions and
Answers from LER Workshops" section, additional
information supporting this interpretation is provided in
the answer to question 6.9 which states that reporting is
not required if "the system is not required to be operable
and it has been properly removed from service such that it
cannot perform its intended function". Concerning these
specific events, all fuel was removed from the reactor
vessel. This condition meets the specific intent of the
NRC answer, in that the system was not required to be
operable nor could it perform its intended function of
controlling reactivity.
Additionally, NUREG-1022 states that "' Actuation' of
multi-channel ESF actuation wystems is defined as
actuation of enough channels to complete the minimum
actuation logic... Therefore, single channel actuations,
whether caused by failures or otherwise, are not
reportable if they do not complete the minimum actuation
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Mr. Samuel J. Collins Jcnuary 21, 1986
Page 9
logic." Seven of the eight events occurred as a result of
single channel actuations because a preplanned trip of the
alternate channel, to support outage-related work, was
already in place prior to each event due. Therefore,
because seven of the eight events only produced a single
channel actuation, they were not, in themselves,
sufficient to complete the minimum actuation logic.
'
Using NRC guidance and plant design analyses, these
actuations were not viewed as being significant or useful
to identify and resolve threats to public safety.
Significance of violation:
The RPS actuations for each of the eight events identified
above occurred while the unit was in the refuel mode with
no fuel in the reactor vessel. These actuations were not
significant and they were not necessary "to mitigate the
consequences of an event" because of the plant
, configuration. Additionally, seven of these events would
not have occurred during power operation because the work
circumstances which caused the single channel actuations
cannot exist at that time. Therefore, the root cause
would not develop.
!
Corrective Actions Taken and Results Achieved:
Peach Bottom Atomic Power Station Licensee Event Reports
3-85-21 and 3-85-22 were submitted to NRC on December 18,
1985 and December 20, 1985, respectively. LER 3-85-21
concerned the false IRM signals and LER 3-85-22 concerned
the false scram discharge volume high level signal. All
of the events identified in this violation were reported
to NRC in these two LERs.
Corrective Actions Taken to Avoid Future Non-Compliance:
On October 11, 1985, a memorandum was issued by the
l Operations Engineer stating that all Engineered Safety
Feature actuations, including RPS actuations occurring
while the reactor is defueled, will be reported to the NRC
as a Licensee Event Report.
'
Date When Full Compliance Was Achieved
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Full compliance was achieved on December 20, 1985 with
submittal of Peach Bottom Atomic Power Station Licensee
Event Report 3-85-22
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Mr. Samu21 J. Collins January 21, 1986 '
Page 10
The cover letter which transmitted this Inspection
Report requested that PECo discuss the management controls used '
to ensure that PORC-approved procedures are not revised in a less
conservative direction via the issuance of non-PORC reviewed
guidance. Although not specifically tied to a violation, we
assume this request refers to a letter from the Operations
Engineer to the Operating Shif t dated August 29, 1985. This
letter provided interpretation guidance based on engineering
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judgment for the ESF actuation portion of Administrative
Procedure A-31 (Procedure for Notification of the NRC) . The
intent of this letter was to provide specific guidance on a
subset of events which are not addressed by the A-31 procedure.
There was no intent to revise in a less conservative manner or
otherwise circumvent the Administrative Procedure. Licensee
representatives from all utilites who are familiar with NUREG-
1022 and have attended the various NRC LER Workshops clearly
understand, as stated in the various NRC documents, that
engineering judgment must be used in determining the
reportability of events. This was the case in these instances.
- The purpose of the letter was to document the rationale of the
engineering judgment employed and provide consistency with regard
to the reportability of the specific events under the specific
i conditions stated in the letter.
In response to the concern raised in your cover
letter, the Plant Manager has directed all of the Senior Staff at
Peach Bottom that this form of guidance must be PORC approved
i prior to issuance. .
Should you have any questions or require additional
information, please do not hesitate to contact us.
Very truly yours,
!
/ <
/ / W
cc: T. P. Johnson, Resident Site Inspector
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, _b UNITED STATES [ N 2[
+*gomargI*,, NUCLEAR RE^aULATORY COMMISSIOi,
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- sung OF PRUSSIA. PENNSYLVANI A 19406 '%
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Docket Nos. 50-277/0PR-44 (
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Philadelphia Electric Company C'
ATTN: .Hr. S. L. Daltroff '
Vice President .
Electric Production .,
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2301 Market Street -
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Philadelphia,_ Pennsylvania 19101 1 s
,
Gentlemen: )~
Subject: Combined Inspection 50-277/85-29; 50 278/85-33 g
r + ,
This transmits the findings of the routine safety inspection by Messrs.
T. P. Johnson, J. P. Rogers, and.'J. H. Williams, on September 14 - October 25,
1985, at the Peach Bottom Atomic Power Station, Delta, Pennsylvania. These
findings were based on observation of activities, interviews, measurements and
document e.eviews, ar}d have been discussed with Mr. R. 3. Fleischniann of your
staff. ;
^
.N ,
Based on the results of this inspection, it appears that several of your activ-i l
ities were not conducted in full cbypliance with NR$ requirements, as set forth i
in the Notice of Violation, enclosed herne!th as Appfadix A. These violations
have been categorized by severity level in accordance With the revised NRC
Enforcement Policy (10 CFR 2, Appandix..C) published in the Federgl Register
Notice (49 FR 8583) dated March 6 1984. You are required to respond to this
letter and in preparing your response, you should follow the instructions in
Appendix A. m
'
As discussed in Appendix A, one issue cited relates to an apparent misinterpre-
tation of NRC reporting requira'ments under 10"CFR 50.72 and 50.73. We are
concerned, not only with the lack of reporting of Unit 3 reactor protection a
system actuations, but= also,vith the issuance of guidance which modified, in a
less conservative direction, a PORC approved Administrative Procedure, which
was intended to implement the requirements of 10 CFR 50.72 and 50.73. In addi-
tion to your response to the specific violation, please provide us with a
discussion of the management controls used to ensure that TORC approved pro-
cedures are not revised in a less conservative direction via the issuance of
non-PORC reviewed guidance. .-
> The responses directed by this letter and the accompanytrig Notice are not sub-
ject to the clearance procedures of the Office of Management and Budget as .
required by the Paperwork Reduction Act of 1980, PL 96-511. ,
, ,,g. ,
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A copy of this letter and the enclosurpg are being placed in the NRC Pub 1ic
Document Roo:n. ( ;' ~ \
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Philadelphia Electric Company 2 'n,.....
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Your cooperation with us is appreciated.
Sincerely,
o
a uei
J N')9d
. Ct1 Tins, Chief,
Projects Branch 2
Division of Reactor Projects
Enclosures:
1. Appendix A, Notice of Violation
2 NRC Region I Combined Inspection Report Nos. 50-277/85-29 and 50-278/85-33
cc w/encis:
R. S. Fleischmann, Manager, peach Bottom Atomic Power Station
John S. Kemper, Vice President, Engineering and Research
Troy B. Conner, Jr., Esquire (dithout Report)
Eugene J. Bradley, Esquire, Assissart General Counsel (Without Report)
Raymond L. Hovis, Esquire (Without Report)
Thomas Magette, Power Plant Siting, Nuclear Evaluations (Without Report)
W. H. Hirst, Director, Joint Generatton Projects Dept., Atlantic Electric
~
Public Document Room (PDR)
Local Public Document Room (LPDR)
Nuclear Safety Information Center (NSIC)
NRC Resident Inspector
Commonwealth of Pennsylvania
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bec w/ enc 15:
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Region I Docket Room (with concurrences)
Senior Operations Officer (w/o encis)
R. Gallo, Section Chief, DRP
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M APPENDIX A
e :.
.g NOTICE OF VIOLATION
Philadelphia Electric Company Docket / License: 50-277/DPR-44
Peach Bottom Units 2 and 3 50-278/DPR-56 '
.
As a result of the inspection conducted on September 14, 1985 - October'25,
r,, 1985, and in accordance with the revised NRC Enforcement Policy (10 CFR 2
Appendix C) published in the Federal Register on March 8, 1984 (49.FR 8583),
,g
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. the following violations were identified:
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1. Technical Specification 6.8.1 and Regulatory Guide 1.33, November 1972,
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g , require implementation of procedures for surveillance testing.
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, Surveillance Test Procedure ST 4.9.B, Portal Monitor Calibration and
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Source Check, requires a quarterly source check and a semi-annual
calibration of the portal monitors throughout the plant, including
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y.. portal monitor number 332.
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/ Contrary to the above from about July 7,1985 to September 25, 1985,
portal monitor number 332 was overdue for calibration and in use at the
165 foot elevation of the administration building bridge, and the semi-
annual calibration hadmot been performed since. January 7,1985. '
i This is a Severity Level IV Violation (Supplement 1) applicable to DPR-44
and DPR-56. -
2. Technical Specification 6.8.1 and Regulatory Guide 1.33, November 1972,
require that written procedures and administrative policies be estab-
11shed, implemented and maintained.
Administrative Procedures A-26, Rev. 24 and A-26A, Rev. 2 state that the
Control Operators shall prepare blocking permits. Procedure A-2 states
I that revised Administrative Procedures must.contain equivalent, more con-
'
servative, or additional requirements to be issued on an expedited basis.
.
Contrary to the above: 1) In early September 1985, a practice was insti-
tuted allowing Plant Operators-Nuclear to prepare blocking permits, and 2)
on October 11, 1985 an expedited change to A-26 and A-26A was made, which
eliminated the requirement that Control Operators prepare blocking'per- .
- mits, and did rot contain equivalent, more conservative or additional
requirenients.
'
This is a Severity Level IV Violation (Supplement 1) applicable to DPR-44-
and DPR-56.
3. Technical Specification paragraph 4.6.D.4 requires that each main steam
safety relief valve be manually opened once per operating cycle with the
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Appendix A 2
reactor pressure equal to or greater than 100 psig to demonstrate its
ability to pass steam. Surveillance Test 10.4, Relief Valve Manual Actua-
tion, implements this requirement.
Contrary to the above no manual test of relief valves 71 B, G, and K were
performed on Unit 3 during the operating cycle 6 from September, 1983 to
July, 1985.
This is a Severity Level IV Violation (Supplement 1) applicable to DPR-56.
4. 10 CFR 50.72 requires the licensee notify the NRC Operations Center via
the Emergency Notification System within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and 10 CFR 50.73 requires
the preparation of a Licensee Event Report of any event or condition that
results in manual or automatic actuation of any engineered safety feature,
including the reactor protection system.
Centrary to the above, eight (8) reactor protection system actuations
occurred between August 29 and October 10, 1985 and, as of October 25,
1985, no reports were made to the NRC.
This is a Severity Level IV Violation (Supplement 1) applicable to
Pursuant to the provisions of 10 CFR 2.201, philadelphia Electric Company is
hereby required to submit to this office within 30 days of the date of the
letter transmitting this Notice, a written statement or explanation of reply,
including: (1) the corrective steps which have been taken and the results
,
achieved; (2) the corrective steps which will be taken to avoid further viola-
tions, and (3) the date when full compliance will be achieved. Where good
cause is shown consideration will be given to extending the response time.
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-277/8'5-29 & 50-278/85-33
Docket No. 50-277 & 50-278
Licensee: Philadelphia Electric Company
~ 2301 Market Street
Philadelphia, Pennsylvania 19101
Facility Name: Peach Bottom Atomic Power Station Units 2 and 3
Inspection at: Delta, Pennsylvania
! Inspection conducted: September 14 - October 25, 1985
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Inspectors: T. P. Johnson, Senior Resident Inspector
J. H. Williams, Resident Inspector
J. P. Rogers, Reactor Engineer
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Reviewed by: /s /2/p[ps-
J. Beall, Project Engineer date
Approved by: b lb 18Bf
Robert M. Gallo, Chief date
Reactor Projection Section 2A
Inspection Summary: Routine, on-site regular and backshift resident inspection
(157 hours0.00182 days <br />0.0436 hours <br />2.595899e-4 weeks <br />5.97385e-5 months <br /> Unit 2; 140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3,
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operational safety, radiation protection, physical security, control room
activities licensee events, surveillance testing, refueling and outage
activities, maintenance, and outstanding items.
Results: Licensee management continued their involvement in Unit 2 and 3 opera-
tions. Personnel generally implemented station proceduras except for the .
following areas: administrative procedures for blocking and procedural revi-
sions (4.2.2); RHR system operating procedures (4.2.2); and, a surveillance
procedure for the portal monitor (4.1). Three of the 11 main steam safety
l relief valves on Unit 3 apparently were not tested during the last operating
cycle (7.2). During the period August 29 through October 10, 1985 eight RPS
actuations occurred in Unit 3 and no reports were made to the NRC in accordance
with 10 CFR 50.72. The actuations were.got reported due to a misinterpretation
of the requirements of 10 CFR 50.72 and 50.73 (4.3). Control Room operator
response during a feedwater transient and scram on Unit 2 was good. ,
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DETAILS
1. Persons Contacted
J. F. Mitman, Haintenance Engineer
'R. S. Fleischmann, Manager Peach Bottom Atomic Power Station
A. Fulvio, Technical Engineer
A. E. Hilsmeier, Senior Health Physicist
D. L. Oltmans, Senior Chemist
F. W. Polaski, Outage Planning Engineer
S. R. Roberts, Operations Engineer
D. C. Smith, Superintendent Operations
S. A. Spitko, Administration Engineer
J. E. Winzenried, Superintendent Plant Services
Other licensee employees were also ccatacted.
- Present at exit interview on site and for summation of preliminary findings .
2. Plant Status
2.1 Common
NRC Commissioner Zech toured the Peach Bottom facility on September
19, 1985. He met with the licensee management, the NRC Resident
Inspectors and Region 1 management personnel including the Regional
Administrator.
The Commissioner
Control Room licensed operatots, also held discussions with licensee
On September 23, 1985, a PECo chemistry technician drowned while
obtaining a sample in the discharge canal. His body was recovered on
September 25, 1985, by Pennsylvania State Police divers.
The annual Peach Bottom Emergency Exercise was held October 17, 1985' .
NRC Inspection 277/85-36 and 278/85-34 evaluates this exercise.
2.2 Unit 2
The unit began the report period at 100% power. On September 19,
1985, the unit was shutdown due to simultaneous inoperability of the
E-2 diesel generator and the 2A RHR pump (see detail 4.2.1).
The unit remained shutdown until October 4, 1985, when unit startup
I
was effected. The unit achieved 100% power on October 6, 1985.
The unit remained at 100% power until October 17, 1985, when Unit 2
scrammed
detail on low reactor water level due to loss of feedwater (see
4.2.3). The unit was restarted on October 18, 1985, and
achieved 100% power on October 19,1985. The unit remained at 100%
power the remainder of the report period.
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2.3 Unit 3
Unit 3 remained in a refueling / outage status during the entire report
period. ,
Major items completed during the inspection period were LPRM exchange,
SRM and IRM dry tube replacement fuel reconstitution, diesel generator
annual inspections, core spray sp,arger repair, IGSCC inspections and
recirculation suction pipe N-1 safe end plug sample removal.
Major items remaining are completion of recirculation and RHR piping
overlays, completion of system work and return to service, fuel
reload, vessel assembly and hydro, ILRT and unit startup (see detail
4.4).
Startup is scheduled for January 1986.
3. Previous Inspection Item Update
3.1 (Closed) Violation (277/84-17-02). Failure to take prompt corrective
action in response to identified failures to comply with maintenance
department ad.:inistrative (MA) procedures. The licensee responded to
the violation in a letter dated August 8, 1984. The inspector
reviewed the licensee response and determined it to be adequate.
Five MA procedures had been identified as overdue for their required
two year review. The inspector verified that the five MA procedures
(MA-4, MA-8, MA-11, MA-15 and MA-17) were reviewed and revised in
1984. In addition, a check was made of all other MA procedures to
ensure they were reviewed within two years. All MA procedures were
,
reviewed in calendar year 1984 or 1985. The licensee instituted a
tracking system for ensuring MA procedures are reviewed and revised
as required. This item is closed.
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3.2 (Closed) Unresolved Item (277/83-37-01). Secondary Containment Door
Alarms. The inspector had noted many malfunctioning secondary con-
' tainment door indicators (blue lights and position switches) and
numerous instances of personnel disregarding the blue light interlock.
In order to meet secondary containment integrity, Technical Specif1-
cation 3.7.C/4.7.C, at least one door in each access opening in the
reactor building must be closed. The blue light system reminds personnel
of this requirement. If a blue light is lit above a secondary con-
tainment door, the door is not to be opened as another door is already
opened. Opening both of these doors would thus breach secondary
containment integrity. The secondary containment access system is
tested every 2 months by performance of routine test, RT-1.8.1,
" Secondary Containment Access Control System Alarm Test," Revision 4,
September 20, 1983. This test verifies operability of the blue light
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system, the local audible alarms, and the remote control room annun-
ciator alarms.
formed as required with satisfactory results.The inspector verifie
Also, the inspector
observed,the satisfactory operation of the secondary containment
access control system on both Unit 2 and Unit 3. Based on Itcensee
satisfactory
item is closed. performance of RT-1.8.1 and inspector observations, this
3.3
, (Closed) Violation (277/84-07-01; 278/84-07-01). Failure to follow
' Standby Gas Treatment System (SGTS) Procedure.
to the violation in a letter dated June 7, 1984.The The licensee
response responded
was
revietted by the inspector and found to be acceptable. The licensee
revised the SGTS operating procedure of concern. The inspector reviewed
Equipment Cell Exhaust to Standby Gas, Revision 22, 1984. 2,
The revised procedure S.10.5.G deletes two steps that were done
locally in.the SGTS room.
These deleted steps are addressed adequately
in another
Revision procedure,
2, May SGTS Setup for Automatic Operation, S.10.5.A.
18, 1979.
This item is closed.~
3.4
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(Closed) Inspector Follow Item (277/84-15-02). . Standby Gas Treatment
System (SGTS) fan logic problem. A failure of the SGTS fan A inlet
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and
1984.outlet dampers occurred on a system start on Unit 2 on Aprt) 27,
This damper failure concurrent with a $GTS automatic initiation
caused by a group III isolation, would have made the SGTS inoperable.
This was due to the design of the B IGTS standby fan start circuit
differential pressure switch (OPS).
This DPS senses SGTS differential
pressure
condition.(DP) and automatically starts the B SGTS fan on a no flow
In this case, a no flow condition would have occurred;
however, the OPS would have sensed adequate DP, and the 8 SGTS fan
would not have been given a start signal.
2-84-08, May 29, 1984, The licensee issued LER
.
1985. The inspector reviewed both these LERs.and LER 2-84-08, Rev
The revised LER
referenced a system modification that would replace the DPS with
pitot tube flow elements and flow switches (FE/FS). These FE/FS
numbered 70004 and 70005 would ensure that the B SGTS fan wo
start on
SGTS fanno flow
(Unit 3). conditions for the A SGTS fan (Unit 2) or for the C
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on both Unit 2 and 3 on JanuaryModification 1505 (plant MOD 84-088) w
10, 1985. The inspector reviewed the
! completed MOD package including the following documentation: Modift-
cation correspondence, PORC approval sheet, safety evaluation, main-
! tenance request forms, construction job memo, field engineer check-
out, modification acceptance test, vendor information, and revised
electrical drawings (E-206 Rev. 24). The inspector discussed the
modification with the licensee. The inspector noted that the current
0-list, Revision 20, August 21, 1984, did not include the modified
FE/FS 70004 and 70005. The inspector contacted the licensee's
Mechanical Engineering Department to ensure that the FE/FS 70004 and
.
70005
inspector were
had tonobe included
further in the next revision to the Q-list.
questions. The
This item is closed.
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3.5 (Closed) Violation (277/84-17-02). Inadequate acceptance criteria in
surveillance procedures. The ifcensee responded to the violation in
a letter dated August 8,1984. The inspector reviewed the response
and deterpined it to be acceptable. The licensee revised the 3
affected procedures, ST12.15.1-3, ST 12.15.3-3, and ST 12.15.4-3, to
include more definitive acceptance criteria. The inspector reviewed
the 3 revised STs and determined that they were adequate. This item
is closed.
3.6 (Closed) Violation (277/84-15-05). Failure to post a radioactive
contamination area. The ifcensee responded to the violation in a
letter dated August 10, 1984. The inspector reviewed the licensee's
response and found it acceptable. The licensee has instructed all HP -
personnel tc include fire barrier seals in the swipe surveys as they
are potentially contaminated areas. The inspector verified this
through discussions with HP personnel. This item is closed.
3.7 (Closed) Unresolved Item (50-278/80-21-02). Withdrawing a control
rod with badly damaged seals. The licensee developed a procedure to
provide instructions for withdrawing a control rod with badly damaged
seals. The inspector reviewed procedure S.4.3.Q, " Withdrawal of a
Control Rod With Badly Damaged CRD Seals", Revision 0, August 25,
1980. The inspector noted that the procedure requires implementation
under the direction of a reactor engineer and that precautions are
included to provide actions if a control rod block alarm occurs. If
a control rod block alarm occurs from the Rod Block Monitor system,
the procedure requires immediate removal of the jumper that was
applied in order to cause the rod withdrawal motion. The inspector
discussed the use of this procedure with the licensee and verified
that operators were knowledgeable. Based on the licensee's procedure
S.4.3.Q, the inspector's review of the procedure and discussions with
licensee personnel, this item is closed.
3.8 (Closed) Unresolved Item (277/79-09-01; 278/79-10-01). Administrative
Procedure A-42, Revision 7, Jumper Log Procedure, did not require
PORC review ard approval for jumper installation on safety related
equipment. Procedure A-42 was revised and the current A-42, Revision
9, dated April 25, 1985, requires that "all jumpers shall be installed
via specific PORC approved procedures or the PEco blocking permit if
required as part of the permit". The inspector reviewed several
recent safety related jumpers and the implementing procedures listed
in the jumper log. The inspector verified that the use of the
jumpers had heen PORC approved prior to jumper installation. This
item is closed.
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3.9 (Closed) Unresolved Item (277/79-09-07; 278/79-10-07). Completed
surveillance tests were filed in standard file cabinets with no fire
rating pending shipment to permanent storage and microfilming. Some
completed tests had been stored for an extended period of time. A
system for the collection and storage of records was discussed in the
letter from S. L. Daltroff to T. T._ Martin (NRC) dated October 19,
1981. The letter stated that the licensee would be in full compliance
with the requirements of ANSI N45.2.9 by June 1983. In November,
1983, the NRC found a backlog of completed maintenance request forms
(MRFs) stored in several cardboard boxes under desks and along aisles
and radiation work permits st.ored in stacks on desks. Violations
277/83-32-01 and 278/83-30-01 were subsequently issued. The licensee
actions to comply with ANSI N45.2.9 will be inspected as part of the
inspection of the corrective action to the violations. This unre-
.
solved item is closed.
3.10 (Closed) Unresolved Item (277/79-09-09; 278/79-10-09). Administrative
Procedure A-26, Procedure for Corrective Maintenance, did not require
the licensee to document the cause of the failure, malfunction, or
defect, and corrective action taken to preclude repetition. Equipment
failures are documented on the Maintenance Request Form (MRF), which
includes documentation of corrective actions. Administrative Proce-
dure A-26 covers the use of the MRF. The Computerized History and
Maintenance Planning System (CHAMPS) maintains a history file on all
equipment. A-26 also states that the preparation of the Licensee
Event Report (LER) provides a mechanism for evaluating malfunctions
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of items specified in the Technical Specifications. The LERs include
cause, corrective action, and action to prevent recurrence. In addi-
l tion, the I&C Engineer and Maintenance Engineer are responsible for
the review of failure of "Q" listed equipment and equipment essential
to electric power generation. Based on the above, this item is closed.
l 3.11 (Closed) Unresolved Item (277/79-09-04; 278/79-10-04). No written
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program or documentation to demonstrate that the Plant Operation
Review Committee (PORC) and Off Site Review Committee (OSRC) performed
review, evaluation, and corrective action relative to failure to
follow procedures as required by Technical Specification 6.5.1.6.e.
The inspector reviewed Technical Specification 6.5.1.6.e, Administra-
tive Procedure A-4, Plant Operations Revew Committee Procedure, and
recent PORC meeting minutes. When a violation or suspected violation
of Technical Specifications, internal rules, procedures, or regulations
l 1s identified, the PORC investigates the cause and recommendations to
l prevent recurrence as documented in the PORC minutes. The'PORC minutes
I are then sent to the Nuclear Review Board (NRB) which replaced the
OSRC. The NRB reviews the PORC minutes and documents this in the NRB
minutes. The inspector reviewed selected NRB meeting minutes to,, .'
verify this. Based on the above, this item is closed.
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3.12 (Closed) Unresolved Item (277/79-09-05; 278/79-10-05). Only those
nonconformance reports (NCRs) deemed significant by the QA Division
Superintendent were sent to the OSRC (currently called the Nuclear
Review Board) for their review. All NCRs are listed and discussed in
the PORC* minutes. All PORC minutes are reviewed by the NRB. Also, a
log of all QA NCR's is distributed to the NRB members. Based upon
this information being available to NRB members for further review as
desired, this item is closed.
3.13 (Closed) Inspector Follow Item (278/85-27-01). Unit 3 core spray
sparger cracks. This item is closed based on detail 4.4.1. -
4. Plant Operations Review
4.1 Station Tours
The inspector observed plant operations during daily facility tours.
The following areas were inspected:
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Control Room
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Cable Spreading Room
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Reactor Buildings
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Turbine Buildings
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Radwaste Building
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Pump House
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Diesel Gen 2rator Building
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Protected and Vital Areas
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Security Facilities (CA,S, .SAS, Access Control, Aux SAS)
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High Radiation and Contamination Control Areas
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Shift Turnover
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Unit 3 Drywell
During a daily plant tour on September 25, 1985, the inspector noted.
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that the portal monitor on the 165 foot level of the administrative
building bridge was due for its 6 month calibration on July 7,1985,
as indicated on the calibration sticker attached to the monitor. This
portal monitor, Eberline model PMC-4B serial number 332, checks for
potential personnel contamination when exiting the power block at the
165 foot level of the turbine building and proceeding to the admints-
trative building. The inspector immediately notified the licensee of
the potential out of calibration portal monitor. The licensee began
an investigation to determine the calibration status of the portal
monitor.
There are two types of portal monitors in use at the station;
Eberline model PMC-4B and Instrumentation Research Technology (IRT)
model PRM-110. At the 165 foot administrative building bridge there
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is one Eberline portal monitor t At the 116 foot turbine
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' building / power block exit there are two IRT portal monitors with a
backup Eberline monitor which is not normally in use. At the securi-
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ty building exit concourse there are two IRT portal monitors with two
backup Eberline monitors which are not normally in use.
The inspgetor checked the calibration status of the IRT portal mont-
tors. Procedure RT-7.32, Portal Radiation Monitor Model PRM-110 Sen-
sitivity and Source Check, Revision 1, January 27, 1983, was
reviewed. The inspector verified that all four IRT portal monitors
currently in use were in calibration by reviewing the completed ,
monthly RT 7.32 procedures performed during the period April to Sep-
tember 1985.
Technical Specification 6.8.1 requires implementation of procedures
' for Surveillance Testing. Surveillance Test Procedure ST 4.9.B Por-
tal Monitor Calibration and Source Check, Revision 3, June 21,1983
and HPA-53, Calibration of Portal Monitors, Revision 1, August 8,
1978, detail the calibration frequency and calibration procedures for
the Eberline Model pMC-4B portal monitors. The inspector checked.the
most recently completed ST 4.9.8 test results. Quarterly source
checks were performed on August 10, 1984, October 1,1984, January 7,
1985 and April 2, 1985. Semi-annual calibrations were performed on
August 10, 1984 and on January 7, 1985. The source check and cali-
4
,
bration were 'due again on July 7,1985; however no records of the
completion of this surveillance were available. On September 26,
1985, the licensee informed the inspector that the ST 4.9.B procedure
performance was missed for the Eber11ne portal monitors on July 7,
1985, due to an oversight. All Eber11ne portal monitors were cali-
- brated on September 25, 1985; and verified by the inspector. Failure
to perform a required survet.1 lance test procedure is an apparent vio-
lation of Technical Specification 6.8.1. (277/85-29-02).
4.1.1 Control Room and facility shift staffing was frequently
checked for compliance with 10 CFR 50.54 and Technical
Specifications. Presence of a senior licensed operator in.
the control room was verified frequently.
4.1.2 The inspector frequently observed that selected control
- ' room instrumentation confirmed that instruments were opera-
ble and indicated values.were within Technical Specifica-
tion requirements and normal operating limits. ECCS switch
'
positioning and valve lineups were verified based on con-
trol room indicators and plant observations. Observations
included flow setpoints, breaker positioning, PCIS status,
and radiation monitoring instruments.
4.1.3 Selected control room off-normal alarms (annunciators) were
discussed with control room operators and shift supervision
to assure they were knowledgeable of alarm status, plant
conditions, and thatscorrective action, if required, was
being taken. In addition, the applicable alarm cards were
checked for accuracy. The operators were knowledgeable of
, , alarm status and plant conditions.
- S
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.
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.
.
9
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4.1.4 The inspector checked for fluid leaks by observing sump
status, alarms, and pump-out rates; and discussed reactor
coolant system leakage with licensee personnel.
4.1.5 * Shift relief and turnover activities were monitored daily,
including backshift observations, to ensure compliance with
administrative procedures and regulatory guidance. No in-
adequacies were identified.
4.1.6 The inspector observed main stack and ventilation stack
radiation monitors and recorders, and periodically reviewed
traces from backshift periods to verify that radioactive
gaseous release rates were within limits and that unplanned
releases had not occurred. No inadequacies were
identified.
4.1.7 The inspector observed control room indications of fire
detection instrumentation and fire suppression systems,
monitored use of fire watches and ignition source controls,
checked a sampling of fire barriers for integrity, and ob-
served fire-fighting equipment stations. No inadequacies
were identified.
. 4.1.8 The inspector observed overall facility housekeeping condi-
tions, including control of combustibles, loose trash and
debris. Cleanup was spot-checked during and after mainte-
nance. Plant housekeeping was generally acceptable.
'
4.1.9 The inspector verified operability of selected safety re-
lated equipment and systems by in plant checks of valve
positioning, control of locked valves, power supply avail-
ability, operating procedures, plant drawings, instrumenta-
tion and breaker positioning. Selected major components
were visually inspected for leakage, proper lubrication,
cooling water supply, operating air supply, and general
conditions. No significant piping vibration was detected.
The inspector reviewed selected blocking permits (tagouts)
for conformance to licensee procedures. No inadequacies
were identified.
4.1.10 The inspector observed portions of the Unit 2 plant startup
on October 4,1985, including the following:
--
Rod Sequence Control System and Rod Worth Minimizer
System operations. ,
I
i
--
Control Rod Withdrawal.
'
--
Main turbine sta'rtup and generator synchronization.
..
..
__ . _ . _ . _ __ .. _ . . _ - .
.
l
.
-
10
l
I --
Implementation of procedure GP-2, Normal Plant l
Startup, Revision 39, March 20, 1985.
,-- Additional licensed operator present for startup.
--
Shift Supervisor and Shift Superintendent frequent
supervision of licensed reactor operators involved in
startup activities.
The startup was being performed in accordance with plant
-
startup and system operating procedures. No unacceptable
conditions were identified.
4.2 Followup On Events Occurrina During the Inspection
4.2.1 Unit 2 2A RHR Pump Abnormalities
At 7:15 p.m. on September 19, 1985, the licensee declared
an Unusual Event and began to shutdown Unit 2 because the
2A RHR pump was declared inuperable due to low flow (Tech-
nical Specification 4.5.A), concurrent with the E-2 diesel
generator out of service for annual maintenance. Technical
Specification 3.5.F.1 requires the reactor to be in cold
shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with one low pressure emergency
core cooling system and a diesel generator out of service.
The reactor was manually scrammed at 9:51 p.m. from 30%
power. Group II and III primary containment isolations
' occurred because of.the low water level transient resulting
from the scram. The E-2 diesel generator was returned to
service at 2:55 a.m. on September 20, 1985, and the Unusual
Event was terminated. The licensee tested the pump in ac-
cordance with ST 6.8, RHR A Pump, Valve, Flow and Cooler
Test, Revision 27, August 24, 1985, and based upon these
tests decided to disassemble the pump and inspect the pump
internals. The licensee proceeded to cold shutdown to in-
vestigate the 2A RHR pump problem. During the period Sep-
tember 20-23, 1985, the 2A RHR pump was disassembled, the
pump internals and suction strainer were inspected, and the
pump was reassembled. No problems nor abnormalities were
noted. Subsequently, on Se 23, 1985, pump testing
in accordance with ST 6.8,'ptember led to unsatisfactory results.
The unit remained shut down during the period September 23
- October 3,1985, as the licensee continued to investigate
the 2A RHR pump flow and pressure abnormalities. The 2A RHR
pump exhibited lower than expected discharge pressure at
i
pump flows greater than 11,200 gpe. The licenset plotted
the 2A RHR pump curve, data, pump developed head versus
flow. The Itcensee additionally examined the pump inter-
nals, piping, suction valve and torus strainer for obstruc-
.
tions and found none. The pump was run with the suction
_ _ _ _ _ . . . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _
. . . - - . . -
.
l
'
11
strainer removed and then with the strainer installed.
There was no difference in the flow characteristics as the
ST 6.8 data was unable to meet the test acceptance
, criteria.
The inspector reviewed the ST 6.8 data taken during the
period September 19 through October 4,1985. The inspector
also reviewed selected test data (pump head and flow) when
plotted on the Bingham pump curve M-1-V-284-1. Normal pump
discharge pressure was 200 psig at flows of 11,500 gpm;
however, the pump was exhibiting discharge pressures of the
range 140 to 170 psig at pump flows of 11,500 gpm.
Technical Specification 4.5.A requires that each RHR pump
deliver 10,900 gpm against a system head corresponding to a
vessel pressure of 20 psig based on individual pump tests.
ST 6.8 acceptance criteria for RHR pump flow is 11,500 gpm.
Previous tests for the 2A RHR pump met the acceptance cri-
teria of 11,500 gpm. The inspector reviewed selected com-
pleted ST 6.8 for the period 1977 - 1985. No abnormalities
l were observed. On October 2, 1985, the licensee submitted
,
an emergency Technical Specification change request to al-
low a lower 2A RHR pump flow. On October 3, 1985, the
licensee informed the inspector that PEco engineering had
evaluated the 2A RHR pump flow problem and had determined
that the pump could currently meet the Technical Specif t-
cation requirement of 10,900 gpm. The licensee stated that
the ST 6.8 acceptance criteria of 11,500 gpm was based on
,
pump runout criteria and not Technical Specification re-
quirements. The 2A RHR pump data shows that at a flow of
10,900 gpm, the pump operates on the pump curve. The in- ,
'
spector Verified this by independently plotting pump head
and flow data. Based on this PEco engineering evaluation,.
the licensee declared the 2A RHR pump operable after satis-
factory completion of ST 6.8 on October 3,1985. Unit 2
-
was then prepared for restart. The inspector reviewed the
.
ST 6.8 test results and the temporary procedure change
.
(TPC) to ensure compliance with Technical Specification
6.8.3 and Administrativt. Procedure A-3, Procedure for Tem-
,
porary Changes to Approved Procedures, Revision 7, January
7, 1985. The TPC was approved by two people, one SRO and
one member of PORC. The inspector also verified that the
l PORC approved this TPC by attending the PORC meeting on -
October 4, 1985. (Seedetail4.6.)
l The inspector reviewed the licensee's formal engine'ering
l evaluations of the 2A RHR pump test data, dated October 4,
1985 and October 9,.1985. The evaluations state that the
Technical Specification requirement of 10,900 gpm at 20
psig reactor pressure can be met if the 2A RHR pump oper-
ates "on the pump curve" at 10,900 gpm and at a minimum of
- S.
~
i
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, _ _ _ , m _ _ _ . , _ _ _ _ , _ _ _
__ _ . __ .. _ _ _ _ _ _ .
._ . _. . _
_.
- -
.
,
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-
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i
'
205 psig discharge pressure. The evaluations also state
the original ST 6.8 acceptance criteria of 11,500 gpm was
based on pump runout criteria in a broken loop. An accep-
tance criteria of -10,900 gpm was considered satisfactory to
" meet the Technical Specification 4.5.A required flow. 1
i
The inspector discussed the status of the 2A RHR pump with
the Station Manager. Based on these discussions, the
licensee intended to declare the 2A RHR pump operable, per-
form plant startup, and perform the following:
.
(1) Weekly testing of the 2A RHR pump per ST 6.8.
.
(2) Trending test data for the 2A RHR pump to monitor po-
tential further degradation.
(3) pursuing 2A RHR pump repairs during a Unit 2 outage
currently scheduled for late November,1985.
The inspector reviewed 2A RHR pump ST data performed on
October 3, 10, 11, 16 and 25, 1985. This test data met
the 2A RHR pump acceptance criteria of greater than 205
psig discharge pressure at a flow of 10,900 gpm.
The insoector will continue to follow these activities.
<
(IFI 277/85-29-03.)
1 4.2.2 Unit 2 Engineered Safeguards Features (ESF) Actuation
At 6:07 p.m. on September 24, 1985, an ESF actuation oc-
curred on Unit 2 while in cold shutdown. The ESF actuation
was due to low reactor water level and caused a reactor
,
scram signal and Group II/III primary containment isola-
l tion. The low reactor water level condition was caused by
l the draining of the reactor vessel via the shutdown cooling
suction lines for the 2C RHR pump and through the RHR full
flow test line to the torus. The licensee initially esti-
mated that reactor water level decreased from a level of an
initial value of +25" to about -20". The reactor was shut-
down prior to the event and no control rod motion occurred.
The Group II/III isolations operated correctly. Reactor
level was restored to normal, and the scram signal and the
Group II/III isolations were reset. The licensee made an
ENS call per 10 CFR 50.72.
The inspector reviewed the control room logs, recorder
traces and discussed the event with the operators. Further
discussions were condycted with licensee operations
supervision.
l
..
l
. _ - _ _ _ _ _ _ . _ _ . _ _ - - . . . . _-- ..- .-, .- , , -. -
._ _ ._ _ _ . .
.
.
13
The Unit 2 licensed reactor operator was completing RHR
system operating procedure S.3.2,C.1, Shutdown Cooling
Mode, Revision 13, July 26, 1984, in order to remove the 2C
RHR pump from shutdown cooling. The operator did not close
- valve M0-2-10-15C, 2C RHR pump shutdown cooling suction
valve as required by S.3.2.C.I. The operator then began
implementing RHR system operating procedure 5.3.2.C.3,
Placing Torus Cooling In Service, Revision 9, March 28,
1985, for the 2A RHR pump. Procedure S.3.2.C.1 opened RHR
torus return valves MO-2-10-39A and 34A. This valve align-
.
ment allowed the reactor vessel to gravity. drain from the
shutdown cooling lines through the 2C RHR pump to the torus
via the torus cooling return line. Once the vessel level
reached zero inches reference, a Group II/III primary con-
tainment isolation occurred, closing the RHR shutdown cool-
ing valves MO-2-17 and 18. This isolated the drain path. t
' Reactor water level was recovered by the condensate pumps
that were operating in automatic startup level control on
long path recirc. The licensee estimated that level
dropped about 35 inches.
Inspector review of control room reactor water level re-
corders indicated the following:
(1) The reactor water level recorder LR-96 trace which is
fed from level indicator LI-94, went from +25 inches
- to zero inches. The scale is from zero inches to +60
inches and the.. instrument is calibrated at 1000 psig
and is automatically density compensated; and the lev-
el trace indicates true level.
(2) The reactor water level recorder LR-110 trace, which
is fed from level transmitter LT-110A, went from
l
greater than +50 inches to +15 inches. The scale is
I +50 inches to -165 inches and the instrument is cali-
brated at 1000 psig. Since the plant was in cold
shutdown, the +15 inches indicated level has to be
adjusted to obtain true level. The licensee deter-
mined that the actual level was -7 inches based on
instrument calibration data.
.
The inspector discussed this event with the licensee. Dis-
l
ciplinary action was taken against the licensed operator.
The licensee indicated that RHR procedure S.3.2.C.1 would
be revised to ensure procedure completion prior to entry
into another RHR procedure. The inspector reviewed the
licensee's upset report regarding the event, including'the ..
analysis for actual level based on instrument calibration
data. The inspector' independently calculated the level
decrease, and this calculation concurs with the licensee
..
.
. . - - - - - , ._- =
_ - _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
.
.
L 14
determined value. The licensee issued a LER for this
event. (See detail 6.2.5.)
,The cause of this event was a violation of the RHR system
operating procedure S.3.2.C.1, however because the NRC
wants to encourage and support licensee initiative for
self-identification and correction of problems no notice of
violation is issued since (1) the licensee identified the
problem, (2) it fits Severity Level IV or V, (3) the viola-
tion will be reported as an LER, (4) measures were taken to
correct the problem and additional measures were taken to
prevent recurrence, and (5) it is not a violation that
could reasonably be expected to have been prevented by cor-
rection of a previous violation. The inspector had no fur-
ther questions at this time.
4.2.3 Unit 2 Scram On Loss of Feedwater
'
At 9:21 a.m. on October 17, 1985, Unit 2 scrammed on low
reactor level (0 inches) from 100% power due to a total
loss of reactor feedwater. All three operating turbine-
driven reactor feedwater pumps tripped on overspeed due to
a malfunction of the automatic feedwater control system.
Reactor water level decreased to -95 inches indicated (-178
inches is the top of the active fuel). Primary containment
isolations occurred for Groups I, II, III and the reactor
recirculation pumps tripped on low-low level. RCIC and HPCI
auto initiated and. injected into the reactor vessel to re-
cover level to +50 inches by 9:25 a.m. The licensee de-
clared an Unusual Event, made an ENS call, and issued a
press release.
The cause of the feedwater control system malfunction was
determined by the licensee to be a loose connection in the
feedwater flow summer unit, General Electric supplied de-
vice FSUM-2-6-103. The flow summer unit is connected by
use of a retractable ribbon cable. This cable has 18 male
connections which slip fit into the flow summer unit and
lock with the use of two tabs. The flow summer unit then
may slide in and out of the control cabinet. The licensee
discovered that the connector was loose causing a loss of
flow summer unit output signal. This loss of output signal
, was sensed by the steam flow / feed flow comparator unit as a
false loss of feed signal. This then resulted in a signal
being sent to all three reactor feed pump turbines to in-
crease feed flow, resulting in a transient which caused all
3 reactor feed pumps to trip on overspeed. The licensee
replaced the flow summer unit with an identical device from
Unit 3, which was shutdown for refueling. The inspector
reviewed electrical schematic drawing (ESD) on the
.
feedwater control system, 6280-MI-5-25, Revision 40, dated
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
l
,
O
.
15
l
l
June 17, 1985. This ESD shows that a zero outpt
total feedwater flow summer unit (FSUM-2-6-103) s j
sensed by the feed flow / steam comparator unit, ca l
, command signal to be sent to all operating reactor l
feedwater pumps to increase speed. The inspector also re- '
viewed the preliminary licensee upset report for the event
and the completed GP-18, Scram Review Procedure.
The Senior Resident Inc.nector and 3 other NRC Region I in-
spectors were in the contro? room at the time of the tran-
sient and scram observing the 9nnual emergency exercise.
The licensee recovery actions we.e good. Once reactor lev-
el was stabilized, the licensee setered HPCI and RCIC, re-
opened the MSIVs and placed the C reacier feed pump in
service. Unit 2 restarted on October 18, 1965, and the
reactor was critical at 6:35 a.m. The unit achieved 100%
power on October 20, 1985. The feedwater control system
responded normally in automatic 3-element control during
power escalation.
Within the scope of this review, no violations were
identified.
4.3 Logs and Records
The inspector reviewed logs and records for accuracy, completeness,
abnormal conditions, significant operating changes and tr ads, re-
quired entries, operating and night order propriety, corr equip-
ment and lock-out status, jumper log validity, conformance to
Limiting Conditions for Operations, and proper reporting. The fol-
lowing logs and records were reviewed: Shift Supervision Log, Reac-
i tor Engineering Log Unit 2, Unit 2 Reactor Operator's Log, Unit 3
Reactor Operator's Log, Control Operator Log Book and STA Log Book,
Night Orders, Radiation Work Permits, Locked Valve Log, Maintenance
Request Forms and Ignition Source Control Checklists. Control Room
logs were compared against Administrative Procedure A-7, Shift
Operations. Frequent initialing of entries by licensed operators,
,
shift supervision, and licensee on-site management constituted evi-
dence of licensee review.
On October 11, 1985, while reviewing the Unit 3 Operator's Log in the
a
Control Room, the inspector noted that on October 10, 1985, at 1:52
p.m., Unit 3 experienced a scram from th~e IRM monitoring system. At
the time of the scram no fuel was in the reactor vessel and a special
4 procedure was in effect to prevent automatic starting of the ECCS._ ,.s -
The control rods were withdrawn to reduce radiation exposures for -
.
work planned on repairing the core spray "T" box. The control rods -
were blocked and there was no.npsition indication on any of the 185
control rods. Neither control rod drive pump was operating nor were
there accumulator pressure and the reactor was at atmospheric pres-
sure. The licensee was questioned about making an ENS call to the
,,
-
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f
5
.- ,- - , -..ww-,~. ---_-,--,,-,-v.-- - - - - - - - - - - - - , - - - - - - - , - - -
..
,
.
.
.
16
NRC to report the reactor protection system actuation in accordance
with 10 CFR 50.72(b)(2)(11). The inspector determined that on August
29, 1985, the licensee issued written guidance on reporting scrams
during the Unit 3 refueling outage when there was no fuel in the re-
actor. The licensee determined that with no fuel in the reactor ves-
sel there was no longer a reactor and therefore no need for a reactor
protection system. Based upon this logic the licensee reasoned that
actuations of the reactor protection system were not reportable.
This interpretation was limited to scram signals with no fuel in the
vessel. All other actuations of engineered safety features were to
be reported as required by, Administrative Procedure A-31. The
licensee was informed that 10 CFR 50.72 requires notification of the
NRC within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of any event or condition that results in manual
or automatic actuation of any engineered safety feature, including
the reactor protection system, and that this requirement applied to
each nuclear power reactor licensed under 10 CFR 50. In addition, 10
CFR 50.73 requires that a Licensee Event Report be prepared for such
events. When informed on October 11, 1985, the licensee immediately
rescinded the August 29, 1985 guidance memorandum. Upon further re-
view of the Unit 3 Operator Log by the inspector it was determined
that while the August 29, 1985 guidance was in effect there were sev-
en additional reactor protection system actuations, as follows:
Date Time Scram
8/29/85 5:30 p.m. "D" IRM spike with A channel tripped
,,
for relay work
9/11/85 1:55.a.m. Scram Discharge Volume High Level
9/11/85 7:43 p.m. "A" IRM spike
9/12/85 11:57 p.m. "C" IRM spike and B RPS channel *
tripped
9/13/85 12:10 a.m. "C" IRM spike
9/13/85 9:33 a.m. "A" IRM spike
9/14/85 1:49 a.m. "C" IRM spike
None of the above actuations were reported to the NRC via the ENS
, telephone nor was a Licensee. Event Report submitted to the NRC.
Failure to make reports to the NRC as required by 10 CFR 50.72 and
50.73 is an apparent violation (278/85-33-03).
.s
.
..
- _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __
_. . _ _ _ _ . _ _
_ . . _
-
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.
j .. .
-
17
4.4 Refueling / Outage Activities
4.4.1 Unit 3 Core Spray Sparger Cracks
During in vessel remote visual inspection of the B loop of
core spray piping, per IE Bulletin 80-13, crack indications
were observed in the annulus area on Unit 3. The licensee
proposed repair of the core spray piping by welding two
brackets to the T-box junction core spray and pipes. The
inspector attended a meeting on September 17, 1985, among
the NRC (NRR), the licensee and General Electric, to dis-
cuss the status of the core spray pipe inspections, crack
indications and repair dispositions. The inspector re-
viewed the Licensee Event Report #3-85-14 dated September
25, 1985, regarding the core spray cracks. The licensee
performed repairs on the core spray piping during the peri-
od October 4-9, 1985. The inspector reviewed the core
spray sparger repair work including the following: mockup
training, ALARA review, modification package, safety evalu-
ation, repair activities, HP controls and QC. The inspec-
tor observed some of the welding of the brackets in the
reactor vessel from the fuel floor. NRC Inspections
! 278/85-36 and 278/85-37 further review HP controls and
maintenance activities for the core spray sparger crack
repairs. Within the scope of this review, no unacceptable
conditions were identified.
4.4.2 Control of Unit 3 Equipment During Refueling / Outage
On October 10, 1985, the inspector reviewed the licensee's
procedures and requirements for writing permits and block-
ing sequences for tagging and control of safety related
equipment. In early September 1985, the licensee institut-
ed a practice of allowing three non-licensed Plant
Operators-Nuclear (PON) to write permits on equipment not
covered by Technical Specifications in order to increase
,
permit production during the Unit 3 outage. Each of these
-
PONS have about five years plant experience in their cur-
rent position. In addition, they were given special train-
ing in the rules for permits and blocking, and in writing
permits. The licensee revised the scope of permits written
by the PONS in early October 1985 to include safety related
systems for which an approved blocking sequence existed or
for which a member of shift supervision had defined how to
block the system. The inspector reviewed the following
Administrative Procedures for requirements on writing
permits:
"
--
A-40, Working Hour Restrictions, Rev. 2, 2/15/84
--
' A-41, Procedure for Control of Safety Related Equip-
j ment, Rev. 2, 8/31/82
. y
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.
- - - , . _ - - - - - ,,,w , , , - - - - - - --,--e-
'
,
.
18
~ a --
A-26 Procedure for Corrective Maintenance, Rev. 24,
1/4/85
--
' A-26A, Procedure for Corrective and Preventive Mainte-
nance Using Champs, Rev. 2, 2/21/85
Administrative Procedures A-26 and A-26A require that a
Control Operator prepare permits for tagging and control-
ling safety-related equipment.
The Control Operator is defined in procedure A-26A as the
posted Control Operator (a licensed reactor operator).
Procedure A-26A further states that the Control Operator
is responsible for preparing, applying and issuing blocking
permits, equipment turnover, and for removal of blocking
permits. The inspector noted that PONS had written the
following permits:
--
Unit 3 Control Rod Drives on September 16, 1985
--
Unit 3 HP3W Crossover Valve on September 25, 1985
--
Unit 3 HPCI Turbine Exhaust on October 4, 1985
The preparation of these permits was not in agreement with
the revised guidance the licensee provided to expedite per-
mit preparation. The inspector brought the discrepancy
between A-26 and A-26A and the revised practice to the
licensee's attention on October 11, 1985. Procedures A-26
and A-26A were revised, reviewed and approved by PORC
(Meeting 85-148) and subsequently reviewed and approved
by the QA Division on October 11, 1985. Both A-26 and
A-26A were revised, on an expedited basis, to state that as
necessary shift supervision shall direct preparation of a
permit.
Procedure A-2, Rev. 27, dated January 7, 1985, Administra-
tive Procedure
revised "A" for Control and Use of Documents states that
Procedures must be reviewed against QA Program
Requirements and must contain equivalent, more conservative
or additional requirements to be issued on an expedited
basis.
The inspector reviewed the training given to operators as-
sociated with permits and blocking, plant systems, safety
systems, and Technical Specifications. The inspector de '
termined that Control Operators get more training than PONS
in plant systems, sa
and permit writing. (ety In systems, Technical
addition to Specifications,
this extra training,
.
, _ _
-_.
4
. ,
19
the Qualification Manual (August, 1983) for Control Opera-
tors requires the trainee to show competence in the re-
quirements for writing: (a) blocking permits, (b) radiation
, work permits, (c) temporary clearance forms, and (d) safety
permits.
The t aspector stated that the October 11, 1985 expedited
change to A-26 and A-26A was in a less conservative direc-
tion because of the additional training and demonstrated
~
knowledge of Control Operators in the areas of safety sys-
tems, plant systems, Technical Specifications and permits
and blocking over and above that demonstrated by PONS. In
addition, the change did not contain equivalent or addi-
tional requirements. Therefore, it appears that the
licensee did not follow procedure A-2 .in making the change
to procedures A-26 and A-26A.
Technical Specification section 6.8.1 states that written
procedures and administrative policies shall be estab-
lished, implemented and maintained that meet the require-
ments of Regulatory Guide 1.33, November 1972. Failure to
follow procedures A-26, A-26A and A-2 is an apparent viola-
tion of Technical Specification 6.8.1.-(277/85-29-01;
278/85-33-01)
4.5 Engineered Safeguards Features (ESF) System Walkdown
The inspector performed a det' Ailed walkdown of portions of the Stand-
by Gas Treatment System (SGTS) in order to independently verify the
operability of the Unit 2 and Unit 3 common system. The SGTS
walkdown included verifications of the following items:
--
Review of SGTS documentation listed in the Attachment to this
report.
--
Inspection of system equipment conditions.
--
Confirmation that the system check-off-list (COL) and operating
,
procedures are consistent with plant drawings.
--
Verification that system valves, dampers, breakers, and switches
are properly aligned.
,
'
--
Verification that instrumentation is properly valved in and
--
Verification that valves required to be locked have appropriate
locking devices. s
--
Verification that control room switches, indications and con-
trols are satisfactory.
K
.. - . - - - . _ _ . _ - . _ _ _
--- -.- - _- . - - - . .
.. .. - . _.
^
.
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20
--
Verification that surveillance test procedures properly imple-
ment the Technical Specifications surveillance requirements.
No unacceptable conditions were identified.
4.6 Plant Operations Review Committee (PORC)
The inspector attended the PORC meeting #85-142 on October 4,1985.
The inspector reviewed the requirements of the administrative proce-
dure A-4, Plant Operations Review Committee Procedure, Revision 20,
'
July 30, 1985, and Technical Specifications (TS) section 6.5.1. The
PORC meeting was conducted in accordance with A-4 and TS 6.5.1 as
verified by checking the following-items:
--
A quorum of the PORC was present.
--
The meeting composition was adequate.
--
Written minutes were generated.
--
Procedure changes and plant modifications were reviewed.
Within the scope of the PORC meeting review, no unacceptable condi-
tions were identified.
4.7 General Employee Training (GET)
The inspector attended the Peach Bottom GET requalification training
on October 9, 1985. The inspector monitored GET course content to
ensure it met the requirements of FSAR Section 13.3.4 and A-50,
Training Procedure, Revision 10, September 6,1984. The GET course
included the following areas: radiation protection, security, emer-
gency and evacuation procedures, quality assurance and industrial
I
'
safety. Within the scope of the review of this GET course, no unac-
ceptable conditions were identified.
5. TMI Action Plan (TAP) Item Status
'
5.1 TAP Item II.F.1.4, Containment Pressure Monitor and II.F.1.5
Containment Water Level Monitor (Closed)
Instrumentation required for these TAP items was addressed under
plant modification 80-31. This modification work was reviewed
during Inspections 277/82-07; 278/82-07, and 277/83-34; 278/83-32.
The inspector reviewed the completed modification package including
the safety evaluation, maintenance request forms, and acceptance
testing. The recorders and indicators installed in the control room
were examined to verify that they were installed as described. The
i inspector reviewed relevant drawings and FSAR section 7.20 to ensure
appropriate changes had been made. The licensee submitted a Techni-
cal Specification change request by letter dated February 11, 1982,
- i
- . _ . _ , -- - - . --. .- - . . _ - . -- .- -.- . . - - .--- ._
. . . . . __ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. . _ _ _ _ _ _ _ _ - _ _ _
.
.
'
21
to incorporate the instrumentation into the Technical Specifications.
This change has not been issued by NRC as of this time. No unaccept-
able conditions were noted. TAP ttems II.F.1.4 and 5 are considered
complete and are closed.
5.2 TAP Item II.K.3.57, Manual Activation of ADS (Closed)
TAP item II.K.3.57 requires that the emergency procedures include
verification that a source of cooling water is available prior to
actuation of the automatic depressurization system (ADS). Alternate
water sources should be identified and referenced in the procedures.
The inspector reviewed the licensee's Transient Response Implementa-
tion Plan (TRIP) procedures T-101, RPV Control and T-111, Level Res-
toration. Based on these procedures, the alternate water source
requirements prior to ADS manual actuation of TAP item II.K.3.57 have
been incorporated into the emergency procedures. This item is
closed.
5.3 TAP Item II.K.3.16.B Reduction of Challenges and Failures of Relief
Valves (Open)
NRR letter dated April 23, 1984, endorsed the following four modifi-
cations for implementing TAP item II.K.3.16.B. These modifications
are based on the BWR Owner's Group Evaluation BWR OG-8134 dated March
31, 1981.
5.3.1 Low-Low Set (LLS) Reitef Logic System or Equivalent
Manual Action (Closed)
The LLS reitef logic system will open a selected relief
valve on concurrent signals of reactor high pressure scram
and any safety relief valve (SRV) opening. The BWR Emer-
gency Procedure Guidelines, Revision 1, January 31, 1981,
call for equivalent manual action. An SRV is manually held
open beyond the reclosure setpoint.
The inspector reviewed Peach Bottom TRIP procedure T-101.
This procedure directs the operator to manually open one or
more relief valves if the relief valves are cycling to
maintain reactor pressure below 1090 psig and to reclose
the relief valve at 950 psig.
I
NRR letter dated October 23, 1984, concurred with this ac-
tion. This item is closed.
5.3.2 Increase Relief Valve Simmer Margin (Closed) e
.s
Increasing the difference between the SRV set pressure and
the reactor pressure vessel operating pressure is intended
,.to minimize leakage and reduce potential spurious openings.
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_ - . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _
.
.
22
The inspector reviewed Technical Specification 2.2, Reactor
Coolant System Integrity. The relief valve settings listed
in the Technical Specification conform to the set point l
, increases specified in License Amendment Nos. 36 and 41 for
Units 2 and 3, respectively. The NRC's safety evaluation
supporting Amendment 36 dated August 18, 1977 concluded
that the higher SRV setpoints reduce the probability of
excessive leakage and spurious valve openings. NRR letter
dated October 23, 1984, concurred with these actions. This
t item is closed.
'
5.3.3 Preventive Maintenance Program (Closed)
Each licensee should have a preventive maintenance program
to enhance the performance of SRVs. During each refueling
outage, 50% of the target rock SRVs " top works" containing ,
the pilot stage should be steam / nitrogen tested for j
recalibration of setpoints, pilot leakage determination, ;
'
and refurbishment.
Peach Bottom Technical Specification 4.6.0 requires the
following actions be performed at least once per operating
cycle:
(1) The removal of at least five of eleven target-rock
relief valves for checking or replacement so that all
valves are tested every two cycles.
,
(2) At least one relief valve shall be disassembled and
inspected.
(3) All piping, switches, and accumulators for continuous
valve bellows monitoring shall be inspected.
(4) Each relief valve shall be manually opened once at
reactor pressure greater than or equal to 100 psig.
(See detail 7.2.)
NRR letter dated October 23, 1984, concurred with the above
actions,
t
A review of procedure M-1.6 Relief Valve Replacement, con-
firms that before a relief valve is installed its setpoint
must be determined and indicated.
The inspector reviewed all surveillance test ST-13.32,
Safety and Relief Valve Replacement, forms for the last six
years. From these SI's all relief and safety valves have
been removed, tested, and inspected as per Technical Speci-
fication 4.6.D. This item is closed.
.
.
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23
!
5.3.4 Lower the reactor vessel water level isolation setpoint l
for main
level 1 (0steam
pen). isolation valve (MSIV) closure level 2 to
' As stated in licensee letter dated June 19, 1984, this mod-
ification will be implemented no later than the first
refueling outage after issuance of a licensee amendment.
The licensee amendment application was transmitted to the
NRC by letter dated April 19, 1984. NRR issued Amendments
Nos. 111 and 115 on October 2, 1985. This item is open
pending licensee implementation of,the Amendment and in-
spector review.
5.4 Status of Closed TMI Action Plan Items
The inspector evaluated the THI Action Plan Items that were closed to
determine whether problems have been experienced subsequent to
the item being closed. The inspector noted that with regards to Item
I.A.1.3, the licensee uses overtime for operators on a routine basis.
Overtime data through September, 1985, for licensed reactor opera-
tors indicates a low of 574 hours0.00664 days <br />0.159 hours <br />9.490741e-4 weeks <br />2.18407e-4 months <br /> and a high of 1258 hours0.0146 days <br />0.349 hours <br />0.00208 weeks <br />4.78669e-4 months <br /> of over-
time. The licensee's letter to Region I dated August 16, 1985,
in association with an enforcement conference held on June 21, 1985,
acknowledged a problem in this area and indicates that they are pur-
suing a solution. The inspector also noted in reviewing Item I.A.I.1
that while the STA is effectively used at Peach Bottom, the position
is a three year assignment and therefore the STA is not likely to
have many years of experience in the job. Currently the most eFpe-
rienced STA has two years on shift. In an emergency, situation the
on shift STA could be rather inexperienced.
TMI Items II.F.1 and II.F.2 required installation of wide range in-
struments as described below:
Instrument Range
Torus level, LR 8123 l' to 21'
Torus Temperature, TR 8123 30 degrees to 230 degrees F
Drywell Pressure, PR-8102 5-25 psia
0-225 psig
Reactor Level, LR 110 -165" to +50"
0" to -325"
Reactor Pressure, PR 404 0 to 1500 psig
The accuracy and range of the instruments is such that slight drifts
in the electronics can cause r.g dings which prompt the operators to
request corrective maintenance. The apparent instrument drift has
resulted in a high rate of unavailability of the instruments and op-
erators to have less confidence in the instruments. The inspector
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e
24 I
has noted that these instruments are tagged out of service more fre-
quently than other instruments. This instrumentation which is infre-
quently used requires a considerable amount of licensee attention.
The inspector will continue to review the performance of these in-
struments and operator attitudes about them.
6. Review of Licensee Event Reports (LERs)
6.1 The inspector reviewed LERs submitted to NRC:RI to verify that the
details were clearly reported, including the accuracy of the descrip- ,
'
tion and corrective action adequacy. The inspector determined wheth-
er further information was required, whether generic implications
were indicated, and whether the event warranted on-site followup.
The following LERs were reviewed: l
'
LER No.
LER Date
Event Date Suoject
September 6, 1985
August 7, 1985
2-85-14
September 24, 1985
Scram and Group II/III Isolations On Reactor
Low Level
August 20, 1985
2-85-15 RPS ahd FCIS Actuation
September 20, 1985
August 22, 1985
"2-85-16 RPS and PCIS Actuation
September 20, 1985
August 26, 1985
LER No.
LER Date
Event Date Subject
2-85-17
September 24, 1985 Torus low Level During Startup
August 25, 1985
- 2-85-18 Reactor Water Cleenup System Isolation
October 11, 1985
September 12, 1985 ""
- 2-85-19 2A RHRsPump Inoperable
October 18, 1985
September 19, 1985
..
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October 21, 1985 Isolation in Cold Shutdown
"
September 24, 2985 k' '
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3-85-11 * Degraded Fire Berriers '
October 1, 1985
-
.
June 21, 1985 , (
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3-85-13 Crack Indications in RHR Pipe Welds
August 22, 1985
July 26, 1985 \
3-85-14 Core. Spray Sparger Juncti$n Box Cracks
September 25, 1985 '
August 26, 1985
4
'
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-
6.2 On-Site-Followup
i
For LERs selected for on-site' followup and review (denoted by aster-
isks above), the inspector verified that appropriate corrective ac-
tion was taken or responsibility assigned and that continued
operations of the facility was conducted in accordance with Technical
.
Specifications and did not constitute an unreviewed safety question
as defined in 10 CFR 50.59. Report accuracy, compliance with curre.it
' reporting requirements and applicability to other site systems and
components were also reviewed.
, 6.2.1 LER 2-85-12 concerns a reactor scram on Unit 2 during
.
' startup due to high IRM flux. This event was reviewed in
detail 4.2.2 of NRC Inspection 277/85-30. No discrepancies
were identified relative to this LER.
6.2.2 LER 2-85-16 concerns a reactor scram on Unit 2 during
l
startup due to a spurious low level signal while returning
a pressure transmitter to service. This event was reviewed
in detail 4.2.4 of NRC Inspection 277/85-30. No inadequa-
cies were identified relative to this LER.
.
6.2.3 LER 2-85-18 concerns an isolation of the Reactor Water
Cleanup (RWCU) system due to personnel e ror The Unit 2
RWCU system isolated on high flow at 10:30 a.m. on Septem-
ber 12,1985. This group IIA primary contain:nent. Isolation
system (PCIS) actuation occurred while operators we , re-
turning the 2A RWCU filter demineralizer to service upon
completion of backwash and precoat operations. The appar-
ent cause of the high flow and isolation was a momentary
excessive RWCU system flow as the filter domineralizer was
valved too quickly 1,qto service. The PCIS actuated cor-
.
rectly and the licensee made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> report on the ENS per
! ..
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-
-
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26
10 CFR-50.72. The licensee reset the PCIS signal and re-
turned the RWCU to service. The inspector reviewed the ,
event, checked operator logs and discussed the isolation !
, with the shift operators and licensee management. The '
- non-licensed operator involved in valving in the filter
demineralizer was counselled on the correct procedure for
return to service. No inadequacies were identified
>
relative to this LER.
'
6.2.4 LER 2-85-19 concerns the 2A RHR pump inoperability and
the event is reviewed in detail 4.2.1 of this report. No
inadequacies were identified relative to this LER.
6.2.5 LER 2-85-20 concerns a reactor low level scram signal
and PCIS Group II/III isolation while in cold shutdown due
to vessel draining through the RHR system to the torus.
This event is reviewed in detail 4.2.2 of this report. No
,
inadequacies were identified relative to this LER.
1 7. Surveillance Testing
,
7.1 The inspector observed surveillance tests to verify that testing had
i
been properly scheduled, approved by shift supervision, control room
operators were knowledgeable .regarding testing in progress, approved -
procedures were being used, redundant systems or components were
available for service as required, test instrumentation was calibrat-
ed, work was performed by qualified personnel, and test acceptance
criteria were met. Parts of the following tests were observed:
--
ST 6.8, RHR A Pump, Valve, Flow and Cooler Test, Revision 27
August 24, 1985, performed on October 3, 10, 11, and 16, 1985.
--
ST 6.8.1, Daily RHR A System and Unit Cooler Operability, Revi-
sion 16, October 25, 1985, performed on October 25, 1985't
In addition, a review of the following completed surveillance tests
was performed:
--
ST 4.9.B Portal Monitor Calibration and Source Check, Revision
3, June 21, 1983, performed on April 2,1985, January 7,1985,
August 9,1984, and October 1,1984.
'
--
RT 7.32, Portal Radiation Monitor Model PRM-110 Sensitivity and
Source Checks, Revision 1, January 27, 1983, performed on April
17, 1985, May 26, 1985, and on June 13, 1985.
No inadequacies were identified.
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7.2
The inspector reviewed ST 10.4, Rev.10 Relief Valve Manual Actua-
tion, performed on Unit 3 on September 3,1983. The inspector noted
that four relief valves (71 B, G, K and 1.) were not tested during the
September,1983 performance of ST 10.4. ST 10.4 was also performed on
November 21, 1983 and February 28, 1985, and tested Unit 3 valves 71E
and 71L respectively. No other copies of ST 10.4 for Unit 3 could be
found, therefore it appears that reitef valves 71 B, G, and K were
not tested for Unit 3 during operating cycle 6 (September 1983
through July 1985). Technical Specification paragraph 4.6.D.4
requires that each relief valve be manually opened once per operating
cycle with the reactor pressure equal to or greater than 100 psig to
demonstrate its ability to pass steam. Surveillance Test 10.4 imple-
ments this requirement.
The inspector discussed the missing test data with the licensee who
indicated a data search was being made to determine if these relief
valves had been tested.
No additional surveillance records were
found during this report period. The inspector checked the similar
test for Unit 2, recorded on ST 10.4, Rev.14, performed July 9,
1985. All eleven relief valves were tested. Failure to manually test
relief valves 71 B, G, and K is an apparent violation of Technical
Specification 4.6.D.4 surveillance requirements (278/85-33-02).
7.3
The inspector reviewed the core spray sparger line break differential
pressure (d/p) instrument Technical Specification (TS) surssillance
requirements. This instrument senses d/p between the core spray in-
jection line and above the core plate. The instrument alarms in the
control room on high d/p, indicative of a break in the core spray
sparger line within the versel annulus region.
The inspector noted a discrepancy with respect to the TS surveillance
requirements.
TS Table 4.2.B item (8) references the " core spray
sparger d/p"
per six months.
instrument with a required calibration frequency of once
TS 4.5.A item (e) references the " core spray header
delta-P instrumentation" with a required calibration frequency of
once per three months. The inspector infomed the licensee of this
discrepancy. The licensee calibrates the core spray d/p instrument
using surveillance test procedures ST 2.2.01 A and B for Unit 2 and
ST.2.7,01 A and B for Unit 3. The core spray d/p instrument, DPIS-
2(3)-14-43A and B, calibration is performed every three months. The
inspector reviewed completed ST records to verify that the above sur-
veillance test is performed every three months. The licensee intends
,
to submit a TS change request to clarify this discrepancy. The in-
'
spcctor will review this item in a future inspection (IFI
277/85-29-04). .
,.
(
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8. Maintenance
'
For the following maintenance activities the inspector spot-checked admin-
istrative controls, reviewed documantation, and observed portions of the
actual maintenance:
K
i
_ -- - -_------ __ --------- -
_,
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28
Maintenance
Procedure /
Document Equipment
Date Observed
SP-863 *
Unit 3 Core Spray October 8, 1985
"T-Box" Repair
Administrative controls checked included maintenance requests, blocking
and shif t turnover information. permits, fire watches and ignition source con
Documents reviewed included procedures,
material certifications and receipt inspections, welder qualif,.1 cations and
weld information data sheets. '
No inadequacies were identified.
9. Radiation Protection
Duringincluding
units, this report theperiod, the inspector examined work in progress in both
following:
--
Health Physics (HP) controls
--
Badging
--
Protective clothing use
--
Adherence to Radiation Work Permit (RWP) requirements
..
--
Surveys
--
Handling of potentially contaminated equipment and materials
The
Physics inspector
procedures. observed individuals frisking in accordance with Health
locked as required. A sampling of high radiation doors was verified to be
.
each tour.
RWP line entries were reviewed to verify that personnel h
observed to be meeting the applicable requirements.provided No unacceptable con-
the re
ditions were identified.
10. Physical Security
The inspector monitored security activities for compliance with the ac-
cepted Security Plan and associated implementing procedures, including:
operations of the CAS and SAS, checks of vehicles on site to verify pro
dures on each shift, inspection of physical barriers, checks
vital area access and escort proced,gres. No inadequacies were identified.
..
h
_ _ _ . _ _ _ - _ _ - - - - - - - -
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l
11. In-Office Review of Public and Special Reports
The inspector reviewed the following documents:
--
Unit 2 Inservice Inspection Program Final Report, dated July 13,
1985.
--
Peach Bottom Monthly Operating Report for September, 1985.
--
Unit 2 Containment Integrated Leak Rate Test Report, dated June 11,
1985.
--
Semi-Annual Effluent Release Report No. 19, Revision 1, dated October
9, 1985.
Within the scope of the review of these documents, no unacceptable condi-
tions were identified.
12. Inspector Follow Items
Inspector follow items are items for which the current inspection findings
are acceptable, but due to on going licensee work or special inspector
interest in an area, are specifically noted for future follow-up. Follow-
up is at the discretion of the inspector and regional management. Inspec-
tor follow items are discussed in Detail 4.2.1 and 7.3.
13. Management Meetings
13.1 Preliminary Inspection Findin s
A verbal summary of preliminary findings was provided to the Station
Superintendent at the conclusion of the inspection. Durinc the in-
spection, licensee management was periodically notified e f of
the preliminary findings by the resident inspectors. No written in-
spection material was provided to the licensee during the inspection.
No proprietary information is included in this report.
13.2 Attendance at Management Meetings Conducted by Region-Based
Inspectors
The resident inspectors attended entrance and exit interviews by
region-based inspectors as follows:
l
Inspection Reporting
Date Subject Report No. Inspector
10/15/85 (Ent) Emergency Preparedness 277/85-36 Hawxhurst
10/18/85 (Exit) Annual Exercise.s 278/85-34
9/30/85 (Ent) Local Leak Rate Testing 278/85-35 Kucharski
10/4/85 (Exit) ,
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Inspection Reporting !
Date Subject Report No. Inspector i
10/8/85 (Ent) Unit 3 Core Spray 278/85-36 8tcehouse
10/11/85(Exit) Sparger Repair
10/15/85 (Ent) SNM Accountability 277/85-37 Della Ratta
10/18/85(Exit) and Control 278/85-38
10/21/85 (Ent) Unit 3 Pipe Repairs 277/85-38 Reynolds
10/25/85(Exit) 278/85-37
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ATTACHMENT
S.10.5.A, Setup of The Standby Gas Treatment System for Auto Operation, Revi-
sion 2, 05/18/79
S.10.5.A C.O.L., Standby Gas Treatment Auto Operation, Revision 6, 09/28/81
'
S.10.5.B, Manual Start of Standby Gas Treatment System, Revision 4, 10/01/84
S.10.5.C, Shutdown of Standby Gas Treatment System Following " Auto" Initiation
Caused by Group 3 Isolation, Revision 4, 05/18/79
S.10.5.C.1 C.O.L., Unit 2 S.G.T.S. Return To Normal, Revision 3, 12/21/83
S.20.5.C.2 C.O.L., Unit 3 S.G.T.S. Return To Normal, Revision 3, 12/22/83
S.10.5.D, Shutdown of the Standby Gas Treatment System Following Manual Start,
Revision 1, 04/15/73
S.10.5.E Routine Inspection of S.G.T.S., Revision 5, 08/02/84
S.10.5.F, Manual Operation of the S.G.T.S. for DOP and Halogenated Hydrocarbon
Testing, Revision 2, 07/11/84
S.10.5.G, Manual Swap Over of Reactor Building Equipment Cell Exhaust to Stand-
by Gas, Revision 2, 10/22/84
FSAR Section 5.3, Secondary Containment System
Technical Specifications 3.7.B/4.7.B, Standby Gas Treatment System
Technical Specifications 3.7.C/4.7.C, Secondary Containment
P&ID M-388, Reactor Building Ventilation Flow Diagram, Revision 19, 3/13/85
P&ID M-391, Containment Isolation Control Diagram, Revision 17, 3/21/79
P&ID M-397, Standby Gas Treatment Control Diagram, Revision 27, 10/29/82
E-206 Sheet 1 of 1, ESD Standby Gas Treatment System, Revision 24, 7/19/84
E-206 Sheet 2 of 2, ESD Standby Gas Treatment System, Revision 24, 7/19/84
E-208 ESD Standby Gas Treatment System Isolation Valves, Revision 13, 11/4/75
M-I-S-23 Sheet 18, ESD Primary Containment Isolation System, Revision 68,
9/17/84
M-I-S-23 Sheet 16, ESD Primary Containment Isolation, Revision 60, 1/15/82
ST-13.9, Secondary Containment Capability Test, Revision 7, 5/16/83
~
ST-13.7A, SGTS Differential and Heater dapacity, Revision 3, 7/11/84
% J
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IMMEDIATE NOTIFICATION RULE
l50,72
ERIC W. WEISS
'
EVENTS ANALYSIS BRANCH
DIV!SION OF EMERGENCY PREPAREDNESS & ENGINEERING RESPONSE
OFFICE OF INSPECTION AND ENFORCEMENT
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NUCIEAR POWER PLANT
'
FUEL FACILITY
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NRC OPERATIONS
CENTER
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OTHER COMPUTER
HQ ~
DATA
FEDERAL
REGIONAL EMERGENCY BASE
DUTY OFFICER AGENCIES'
i. OFFICER *
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EVENTS % REGIONS
MA AGEMENT. REPORT
INPO + " NOTEPAD"
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COMPUTER
! ASSISTED
! ANALYSIS
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IMMEDIATE NOTIFICATION CONTENTS
EVENT CLASSIFICATION (EtERGENCY CLASS OR l-HOUR OR 4-HOUR)
PLANT & UNIT
TIME & DATE OF EVENT (GIVE TIME ZONE)
RX POWER (IN PERCENT) AT TIME OF EVENT ,
'RX POWER (IN PERCENT) AT TIME OF REPORT
ANYTHING UNUSUAL OR NOT UNDERST0OD
STATUS OF SAFETY SYSTEfiS
ESF ACTUATION
LC0 STATEMENT .
SI OR ECCS (INITIATING SIGNAL)
RESIDENT INSPECTOR INFORMED
CAUSE OF EVENT (CALL BACK IF NOT KNOWN)
SEQUENCE OF ACTIONS OR SYSTEM INTERACTIONS -
,
-
PLANS FOR RX OPERATION .
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,,
.
.
STAFF LEVEL P0lNTS' 0F CONTACT
S'JBJECT/ SCHEDULE Stdf PH0'!E OFFICE
(AREA CODE 301)
850.72 Iru"EDI ATE ERIC WEISS (492-4973) IE
-
NOTIFICATION (PUBLISHED)
850.73LER(PUBLISHED) FRED HEBDON 492-4480 AE0D
E53.47EMERGENCYPLANNING MIKE JAMG3CHIAN (492-7000) RES
-
APPENDIX E TO PART 50
NUREG-0554 (PROPOSED RULE
JAN. 84) .
350.54LICENSECONDITION ,
z
$50.55ECDR DON SMITH (492-7000) RES
PART 21 DEFECTS
(PROPOSED RLi' E .
'
FEB. 84)
PART 73 SECURITY JULIE METZGER 427-4310 NMSS
(FALL OF 84) ,
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IMMEDIATE NOTIFICATION NO LONGER
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REQUIREDBY@50,72
, WORKER INJURIES NOT RELATED TO RADIATION OR CONTANI!1ATIO:1
.. LOW LEVEL RELEASES LESS THAN 2 x PART 20 LIMITS AVERAGED
OVER ONE HOUR
.
. CERTAIN TESTIi!G OR OPERATION RESULTING IN PREPLANNED SCRAMS
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EXAfiPLES OF I EEDIATE NOTIFICATIONS
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WITH 4 - HOUR DEADLI.lE
, CERTAIll UNCOMPLICATED SCRAMS WHERE PLANT RESPONDS fl0RM
. LOW LEVEL RELEASES * ,
. TRANSPORT OF CONTAMINATED INDIVIDUALS *
. NEWSWORTHY ITEMS *
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- ASSU.11NG tl01 - H0'JR CRITERIA OR EiERGENCY CLASS APPLIES.
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UVERVIEW 0F THE REVISED LER SYSTEM
.
- BASIS
.-
-
IMPROVE LERS FOR OPERATING EXPERIENCE FEEDBACK TO
CONFIRM SAFETY MARGINS AND IDENTIFY SAFETY PROBLEMS.
-
REVISIONS ,
.
-
CRITERIA ARE BASED PRIMARILY ON THE NATURE, COURSE,
. AND C011 SEQUENCES OF THE EVENT.
- EVENTS ARE REPORTED REGARDLESS OF THE PLANT OPERATING
MODE OR POWER LEVEL. ,
L
- REPORTS CONTAIN A DETAILED NARRATIVE DESLRIPTION OF
POTENTIALLY SIGNIFICANT SAFETY EVENTS.
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OVERVIEW 0F THE REVISED LER SYSTEM (CONTINUED)
-
EXPECTED RESULTS
.
- FEWER LERS (ABOUT 50% LESS)
-
REPORTS ONLY OF SIGNIFICANT EVENTS
- BETTER REPORTS ($0RE USEFUL) -
,
-
LICENSEES ARE PERMITTED AND ENCOURAGED TO REPORT ANY EVENT
THAT DOES NCT l'EET THE CRITERIA CONTAINED IN 550 73(A), IF
THE EVENT
- d!GHT BE OF SAFETY SIGNIFICANCE,
,
-'d:GHT BE OF GENERIC INTEREST OR CONCERN,
- CCNTAINS A LESSON TO BE LEARNED.
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PARAGRAPH-BY-PARAGRAPH EXPLANATION OF THE LER RULE
PARAGRAPH 50 73(A)(2)(I)
COMPARIS0N OF 50 73 AND 50 72
50 73(A)(2)(1)(A) THE COMPLETION OF ANY NUCLEAR PLANT SHUTDOWN
REQUIRED BY THE PL ANT' S ' IECHN IC AL SPEC I FIC ATIONS J
OR ,
(B) ANY OPERATION OR CONDITION PROHIBITED BY THE .
-
PL ANT'S IECHNIC AL SPECIFICATIONSJ OR
(C) ANY DEVI ATION FROM THE PL ANT'S IECHNICAL
SPECIFICATIONS AUTHORIZED PURSUANT TO 550 54(x)
0F THIS PART.
.
....................................................................
.
'
50 72(s)(1)(1)(A) THE INITIATION OF ANY NUCLEAR PLANT SHUTDOWN
REQUIRED BY THE PLANT'S IECHNICAL SPECIFICATIONS.
(B) ANY DEVIATION FROM THE PL ANT'S IECHNIC L
SPECIFICATIONS AUTHORIZED PURSUANT TO 550 54(x)
0F THIS PART.
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PARAGRAPH 50 73(A)(2)(II)
.. ', [ COMPARISON OF 50 73 AND 50 72
.
59 73('A)(2)(II) ANY EVENT OR CONDITION THAT RESULTED IN THE
,
CONDITION OF THE NUCLEAR POWER PLANT, INCLUDING
.
ITS PRINCIPAL SAFETY BARRIERS, BEING SERIOUSLY
,,~[~ "" 6 D(; p h.* D 'N. N*..W c ' DEGRADED, OR THAT RESULTED IN THE NUCLEAR
POWER PLANT BEING:
(A) IN AN UNANALYZED CONDITION THAT SIGNIFICANTLY
COMPROMISED PLANT SAFETY;
(B) IN A CONDITION THAT WAS OUTSIDE THE DESIGN
BASIS OF THE PLANT; OR
(C) IN A CONDITION NOT COVERED BY THE PLANT S ,
-
OPERATING AND EMERGENCY PROCEDURES.
...................................................................
.
50 72(B)(1)(II) ANY EVENT OR CONDITION DURING OPERATION THAT
RESULTS IN THE CONDITION OF THE NUCLEAR POWER
PLANT, INCLUDING ITS PRINCIPAL SAFETY BARRIERS,
BEING SERIOUSLY DEGRADEDj OR RESULTS IN THE
NUCLEAR POWER PLANT BEING:
t
(A) IN AN UNANALYZED CONDITION THAT SIGNIFICANTLY
COMPROMISES PLANT SAFETY;
(B) IN A CONDITION THAT IS OUTSIDE THE DESIGN
BASIS OF THE PLANT; OR
(C) IN A CONDITION NOT COVERED BY THE PL ANT' S*
OPERATING AND EMERGENCY PROCEDURES.
,
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50 72(B)(2)(1) ANY EVENT, FOUND WHILE THE REACTOR IS SHUTDOWN,
THAT, HAD IT BEEN FOUND WHILE THE REACTOR WAS
IN OPERATION, WOULD HAVE RESULTED IN THE NUCLEAR
POWER PLANT, INCLUDING ITS PRINCIPAL SAFETY BARRIERS.
BEING SERIOUSLY DEGRADED OR BEING IN AN UNANALYZED
- CONDITION THAT SIGNIFICANTLY COMPRCMISES PLANT
' -
SAFETY.
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PARAGRAPH 50 73(A)(2)(Ill)
COMPARISON OF 50 73 AND 50 72
.
50 73(A)(2)(lli) ANY NATURAL PHENOMENON OR OTHER EXTERNAL
CONDITION THAT POSED AN ACTUAL THREAT TO THE
SAFETY OF THE NUCLEAR POWER PLANT OR SIGNIFICANTLY
HAMPERED SITE PERSONNEL IN THE PERFORMANCE OF
DUTIES NECESSARY FOR THE SAFE OPERATION OF THE
NUCLEAR POWER PLANT.
...................................................................
.
50 72(s)(1)(111) ANY NATURAL PHENOMENON OR OTHER EXTERNAL
CONDITION THAT POSES AN ACTUAL THREAT TO THE
i SAFETY OF THE NUCLEAR POWER PLANT OR SIGNIFICANTLY
HAMPERS SITE PERSONNEL IN THE PERFORMANCE OF .
DUTIES NECESSARY FOR THE SAFE OPERATION OF THE
PLANT.
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PARAGRAPH $0 73(A)(2)(lv)
'
COMPARIS0N OF 50 73 AND 50 72
50 73(A)(2)(lv) ANY EVENT OR CONDITION THAT RESULTED IN
MANUAL OR AUTOMAT!C ACTUATION OF ANY
ENGINEERED SAFETY FEATURE (ESF), INCLUDING
THE REACTOR PROTECTION SYSTEM (RPS).
HOWEVER, ACTUATION OF AN ESF, INCLUDING THE
RPS, THAT RESULTED FROM AND WAS PART OF THE
PREPLANNED SEQUENCE DURING TESTING OR
.
REACTOR OPERATION NEED NOT BE REPORTED.
.
...................................................................
.
50 72(s)(1)(lv) ANY EVENT THAT RESULTS OR SHOULD HAVE
RESULTED IN EMERGENCY CORE COOLING SYSTEM
(ECCS) DISCHARGE INTO THE REACTOR COOLANT
g
SYSTEM AS A RESULT OF A VALID SIGNAL.
.
50 72(s)(2)(ll) ANY EVENT OR CONDITION THAT RESULTS IN
MANUAL OR AUTOMATIC ACTUATION OR ANY
ENGINEERED SAFETY FE ATURE (ESF), INCLUDING
THE REACTOR Pa0TECTION SYSTEM (RPS).
HOWEVER, ACTUATION OF AN ESF, INCLUDING THE
RPS, THAT RESULTS FROM AND IS PART OF THE
PREPLANNED SEQUENCE DURING TESTING OR
REACTOR OPERATION NEED NOT.BE REPORTED.
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. PARAGRAPHS 50 73( A)(2)(v) AND (vi)
. COMPARISON OF 50 73 AND 50 72
50 73(A)(2)(v) ANY EVENT OR CONDITION THAT ALONE COULD HAVE
PREVENTED THE FULFILLMENT OF THE SAFETY
FUNCTION OF STRUCTURES OR SYSTEMS THAT ARE
NEEDED TO:
(A) SHUT DOWN THE REACTOR AND MAINTAIN IT IN s
A SAFE SHUTDOWN CONDITION)
(B) REMOVE RESIDUAL HEAT)
(C) CONTROL THE RELEASE OF RADIDACTIVE MATERIAL)
.
(D) MITIGATE THE CONSEQUENCES OF AN ACCIDENT.
(vi) EVENTS COVERED IN PARAGRAPH (A)(2)(v) 0F THIS
SECTION MAY INCLUDE ONE OR MORE PROCEDURAL
ERRORS, EQUIPMENT FAILURES, AND/OR DISCOVERY
OF DESIGN, ANALYSIS, FABRICATION, CONSTRUCTION,
AND/OR PROCEDURAL INADEQUACIES. HOWEVER,
INDIVIDUAL COMPONENT FAILURES NEED NOT BE
REPORTED PURSUANT TO THIS PARAGRAPH IF
REDUNDANT EQUIPMENT IN THE SAME SYSTEM WAS
OPERABLE AND AVAILABLE TO PERFORM THE REQUIRED
SAFETY FUNCTION.
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50 72(B)(2)(lll) ANY. EVENT OR CONDITION THAT ALONE COULD HAVE
PREVENTED THE FULFILLMENT OF THE SAFETY
FUNCTION OF STRUCTURES OR SYSTEMS THAT ARE
NEEDED TO:
(A) SHUT DOWN THI REACTOR AND MAINTAIN IT IN
A SAFE SHUTDOWN CONDITJON,
(B) REMOVE RESIDUAL HEAT,
(C) CONTROL THE RELEASE OF RADIOACTIVE MATERIAL,
,
(D) MITIGATE THE CONSEQUENCES OF AN ACCIDENT.
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. PARACRAPHS 50 73( A)(2)(vill) AND (1x)
, COMPARIS0N OF 50 73 AND 50 72
50 73(A)(2)(vill)(A) ANY AIRBORNE RADIOACTIVITY RELEASE
THAT EXCEEDED 2 TIMES THE APPLICABLE
CONCENTRATIONS OF THE LIMITS SPECIFIED
IN APPENDIX B, TABLE 11 0F PART 20 0F
THIS CHAPTER IN UNRESTRICTED AREAS,
VHEN AVERAGED OVER A TIME PERIOD OF
ONE HOUR.
(B) ANY LIQUID EFFLUENT RELEASE THAT
EXCEEDED 2 TIMES THE LIMITING COMBINED
MAXIMUM PERMISSABLE CONCENTRATION
(MPC) (SEE NOTE 1 0F APPENDIX B
TO PART 20 0F THIS CHAPTER) AT THE
. PolNT OF ENTRY INTO THE RECEIVING
WATER ( 1. E. , UNRESTRICTED AREA) FOR
ALL RADIONUCLIDES EXCEPT TRITIUM
AND DISSOLVED NOBLE GASES, WHEN
AVERAGED OVER A TIME PERIOD OF ONE
HOUR.
.
(IX) REPORTS SUBMITTED TO THE COMMISSION IN
ACCORDANCE WITH PARAGRAPH ( A)(2)(vill) 0F
, THIS SECTION ALSO MEET THE EFFLUENT
RELEASE REPORTING REQUIREMENTS OF PARAGRAPH
20 405(A)(5) 0F PART 20 0F THIS CHAPTER.'
esee seeesse***eeee******esesseseeeeeeeee'eseeeeeeeeeeeee**eseesseee
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50 72(B)(2)(lv)(A) ANY AIRBORNE RADIOACTIVE RELEASE THAT
EXCEEDS 2 TIMES THE APPLICABLE CONCENTRA-
TIONS OF THE LIMITS SPECIFIED IN APPENDIX B,
IABLE 11 OF PART 20 0F THIS CHAPTER IN
UNRESTRICTED AREAS, WHEN AVERAGED OVER A
TIME PERIOD OF ONE HOUR.
(B) ANY LIQUID EFFLUENT RELEASE THAT EXCEEDS
2 TIMES THE LIMITING COMBINED MAXIMUM
'
PERMISSABLE CONCENTRATION (MPC) (SEE
. NOTE 1 0F APPEND'lx B TO PART 20 0F THIS
CHAPTER) AT THE POINT OF ENTRY INTO THE
RECE IVI NG WATER ( 1.E. , UNRESTRICTED
AREA) FOR ALL RADIONUCLIDES EXCEPT
TRITIUM AND DISSOLVED NOBLE GASES, WHEN
AVERAGED OVER A TIME PERIOD OF ONE HOUR.
, (IMMEDIATE NOTIFICATIONS MADE UNDER THIS
PARAGRAPH ALSO SATISFY THE REQUIREMENTS
OF PARAGRAPHS (A)(2) AND (B)(2) 0F
520 403 0F PART 20 0F THIS CHAPTER.)
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PARAGRAPH 50 73(A)(2)(x)
'
COMPARISON OF 50 73 AND 50 72
.
1 .
50 73(A)(2)(x) ANY EVENT THAT POSED AN ACTUAL THREAT TO THE
SAFETY OF THE NUCLEAR POWER PLANT OR SIGNIFICANTLY
, HAMPERED SITE PERSONNEL IN THE PERFORMANCE OF
DUTIES NECESSARY FOR THE SAFE OPERATION OF THE
NUCLEAR POWER PLANT INCLUDING FIRES, Toxic GAS
RELEASES, OR'RADICACTIVE RELEASES.
e
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50 72(s)(1)(vi) ANY EVENT THAT POSES AN ACTUAL THREAT TO THE
SAFETY OF THE NUCLEAR POWER PLANT OR SIGNIFICANTLY
HAMPERS SITE PERSONNEL IN THE PERFORMANCE OF
DUTIES NECLSSARY FOR THE SAFE OPERATION OF THE
NUCLEAR POWER PLANT INCLUDING FIRES, T0XIC GAS
RELEASES, OR RADIOACTIVE RELEASES.
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,~- ,- - - - , - g - , - - , ,n,,- -
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COMPARIS0N OF 50 73 AND 50 72
50 73 - NO COMPARABLE REQUIREMENT.
...................................................................
.
50 72(E)(1)(v) ANY EVENT THAT RESULTS IN A MAJOR LO.SS OF
EMERGENCY ASSESSMENT CAPABILITY, OFFSITE
RESPONSE CAPABILITY, OR COMMUNICATIONS
CAPABILITY (E.G., SIGNIFICANT PORTION OF
CONTROL ROOM INDICATION, EMERGENCY NOTIFICA-
TION SYSTEM, OR OFF3ITE NOTIFICATION SYSTEM).
.
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50 72(B)(2)(v) ANY EVENT REQUIRING THE TRANSPORT OF A
RADIOACTIVITY CONTAMINATED PERSON TO AN
OFFSITE MEDICAL FACILITY FOR TREATMENT.
50 72(B)(2)(vi) ANY EVENT OR SITUATION, RELATED TO THE
HEALTH AND SAFETY OF THE PUBLIC OR
ONSITE PERSONNEL, OR PROTECTION OF THE
ENVIRONMENT, FOR WHICH A NEWS RELEASE
IS PLANNED OR NOTIFICATION TO OTHER GOVERN-
' MENT AGENCIES HAS EEEN OR WILL BE MADE.
SUCH AN EVENT MAY INCLUDE AN ONSITE
FATALITY OR INADVERTENT RELEASE OF
RADIOACTIVE CONTAMINATED MATERIALS.
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SSINS No.: 6835
.
UNITED STATES
NUCLEAR REGULATORY COMMISSION
OFFICE OF INSPECTION AND ENFORCEMENT
WASHINGTON, D.C. 20555
October 15, 1985
IE INFORMATION NOTICE N0. 85-80: TIMELY DECLARATION OF AN EMERGENCY CLASS,
IMPLEMENTATION OF AN EMERGENCY P1AN, AND
EMERGENCY NOTIFICATIONS
Addressees:
All nuclear power facilities holding an operating license (OL) or a construction
permit (CP).
Purpose:
This information notice is provided to describe an instance when an emergency
condition was not classified and declared in a timely manner and to clarify the
requirement for licensees to a<iequately notify the NRC Headquarters Operations
Officer of emergencies. The NRC expects that recipients will review this
notice for applicability to their facilities. Suggestions contained in this
notice do not constitute NRC requirements; therefore, no specific action or
written response is required.
Description of Circumstances: .
Davis-Besse: ,
e At 1:35 a.m. on June 9, 1985, the Davis-Besse plant experienced a complete loss
of main and auxiliary feedwater for nearly 12 minutes. This event is described
in more detail in Information Notice 85-50, " Complete Loss of Main and Auxiliary
~
l Feedwater at a PWR Designed by Babcock & Wilcox," and NUREG-1154, " Loss of Main
and Auxiliary Feedwater Event at the Davis-Besse Plant on June 9,1985." The
emergency plan identified the loss of feedwater event as a Site Area Emergency.
However, it appears that all knowledgeable personnel in the control room were
occupied with stabilizing the plant and, thus, were not able to classify the
,
event as a Site Area Emergency and activate the energency plan. It is possible
l that had the plant not been brought to a stable condition quickly and had plant
l
safety further dc.Jraded, the efforts of all knowledgeable personnel in the
! control room would have been required for recovery efforts, further delaying
initiation of appropriate onsite and offsite emergency response.
l At 2:11 a.m., the shift technical advisor (STA)' called the NRC Operations
'
Center from the control room using the Emergency Notification System to report
the event pursuant to 10 CFR 50.72. At the beginning of the event, the STA
l had been in his quarters in the administration building, which is outside the
,
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Octcbar 15, 1985
Ptga 2 of 3
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protected area about a half mile from the plant. Although the STA mentioned
the trip of the main and auxiliary feedwater pumps, the STA did not describe
the length of time that the plant was totally without feedwater or the difficulty
the plant had in restoring auxiliary feedwater. No Emergency Class was declared,
nor was the fact conveyed to the NRC that plant conditions which warranted the
declaration of a Site Area Emergency had existed for nearly 12 minutes.
At 2:26 a.m., the STA informed the NRC that an Unusual Event had been declared
at 2:25 a.m. The STA also informed the NRC that although the emergency plan
identified the total loss of feedwater event as a Site Area Emergency, the plant
was no longer in this emergency action level at this time. At 2:29 a.m., the
licensee informed the county that an Unusual Event had been declared. The licensee
depended on a procedure that required the county to notify the State of Ohio.
However, because the county could not reach the local state representative, the
State of Ohio was not notified of the Unusual Event declaration until after the
event had been terminated, more than 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after its declaration.
At Davis-Besse, the emergency plan is initially implemented by the shift
supervisor, who also has primary responsibility for ensuring that the plant is
maintained in a safe condition. Because of the competing priorities of (1)
directing attention to necessary recovery actions to obtain a safe and stable
plant and (2) reviewing the emergency plan and initiating its actions, there
was a substantial delay in declaring an Emergency Class and implementing the
emergency plan. If the June 9 event had progressed in severity, valuable time
needed to initiate appropriate onsite and offsite response to the emergency
would have been lost.
Corrective actions being undertaken by the licensee as a result of this event
include a number of operational and' procedural changes that include but are
,
' not limited to the following: The STA shift schedule will be changed from a
24-hour duty day to rotating 12-hour shifts. The STA will spend the entire
shift within the protected area, and the STA office will be located within 1 to
2 minutes of the control room. The STA will be trained as an Interim Emergency
,
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Duty Officer to advise the shift supervisor in event classification and protective
action. The licensee will make emergency notifications directly to the State
of Ohio.
,
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Point Beach:
On July 25,1985, at 7:25 a.m. (eastern time), Point Beach Unit 1 experienced
an event involving loss of offsite power. Point Beach Unit 2 continued to
operate normally during this event. Because of the incomplete understanding of
the event by those making the notification to the NRC Operations Center, the
NRC Operations Center was not made aware of the details of the event. At 7:37
a.m. , a security guard called the NRC Operations Center to notify the NRC that
Point Beach Unit 1 had declared an Unusual Event-l The explanation for the
Unusual Event was that the plant had a turbine runback. When the NRC Headquarters
Operations Officer asked questions, the security guard was unable to provide
additional information because of his limited technical knowledge of the plant
and because the call was made from a location outside the control room where
the security guard could not obtain additional information from the operators
involved.
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October 15, 1985
t . Page 3 of 3
The NRC Headquarters Operations Officer called the control room, and as a result
of asking q'r?stions learned that a station transformer had been lost. However,
not until 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> later, when the plant notified the NRC Headquarters Operations
Officer that the Unusual Event was terminated, did the NRC Headquarters Operations
Officer learn that there had actually been a loss of offsite power.
Discussion:
Licensees should not delay the declaration of an Emergency Class when conditions
warrant such a declaration. Delaying the declaration can defeat the appropriate
response to an emergency. It is the licensee's responsibility to ensure that
adequate personnel, knowledgeable about plant conditions and emergency plan
implementing procedures, are available on shift to assist the shift supervisor
to classify an energency and activate the emergency plan, including making
appropriate notifications, without interfering with plant operation.
When 10 CFR 50.72 was published in the Federal Register (48 FR 39039), the NRC
made clear its intent that notifications on the Emergency Notification System
to the NRC Operations Center should be made by those knowledgeable of the
event. If the description of an emergency is to be sufficiently accurate and
timely to meet the intent of the NRC's regulations, the personnel responsible
for notification must be properly trained and sufficiently knowledgeable of the
event to report it correctly. The NRC did not intend that notifications made
pursuant to 10 CFR 50.72 would be made by those who do not understand the event
that they are reporting.
No written response to this information notice is required. If you need
additional information about this matter, please contact the Regional Adminis-
trator of the appropriate NRC regional office or the technical contact listed *
below.
.
2
ward orda'n, Director
Divisio Emergency Preparedness
and E neering Response
Office of Inspection and Enforcement
Technical Contact: Eric W. Weiss, IE
(301) 492-9005
Attachment: List of Recently Issued IE Information Notices
.
.
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Attrchment 1
October 15, 1985
,
LIST OF RECENTLY ISSUED
IE INFORMATION NOTICES
Information Date of
Notice No. Subject Issue Issued to
85-17 Possible Sticking Of ASCO 10/1/85 All power reactor
Sup. 1 Solenoid Valves facilities holding
85-79 Inadequate Communications 9/30/85 All power reactor
Between Maintenance, facilities holding
Operations, And Security an OL or CP; research
Personnel and nonpower reactor
facilities; fuel
fabrication and
processing facilities
85-78 Event Notification 9/23/85 All power reactor
facilities holding
85-77 Possible Loss Of Emergency 9/20/85 All power reactor
Notification System Due To facilities holding
85-76 Recent Water Hammer Events 9/19/85 All power reactor
. facilities holding
.
l *
85-75 Improperly Installed Instiu- 8/30/85 All power reactor
' mentation, Inadequate Quality facilities holding
Control And Inadequate Post- an OL or CP
modification Testing
85-74 Station Battery Problems 8/29/85 All power reactor
facilities holding
84-70 Reliance On Water Level 8/26/85 All power reactor
Sup. 1 Instrumentation With A facilities holding
Common Reference Leg an OL or CP
85-73 Emergency Diesel Generator 8/23/85 All power reactor
Control Circuit Logic Design - facilities holding
.
f
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OLi= Operating License
CP = Construction Permit
.
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ERIC W. WEISS .
EVENTS ANALYSIS BRANCH
i DIVISION OF EMERGENCY PREPAREDNESS AND ENGINE
,
OFFICE OF INSPECTION AND ENFORCEMENT
U. S. NUCLEAR REGULATORY COMMISSION
.
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550.72 IMMEDIAT$ NOTIFICATIONS
.
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IMMEDIATE NOTIFICATION C0flTENTS
EVENT CLASSIFICATION (EERGENCY CLASS OR 1-HOUR O
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PLANT a UNIT
,
TIE & DATE OF EVENT (GI'JE TIE ZONE) -
RX POWER (IN PERCENT) AT TIE OF EVENT '
'
RX POWER (IN PERCENT) AT TIE OF REPORT
ANYTHING UNUSUAL OR NOT UNDERST0OD -
STATUS OF SAFETY SYSTEftS '
ESF ACTUATION
'
LC0 STATEMENT '
SI OR ECCS (INITIATING SIGNAL)
RESIDENT INSPECTOR INFORED
CAUSE OF EVENT (CALL BACK IF NOT KNOWN)
SEQUENCE OF ACTIONS OR SYSTEtt INTERACTIONS '
,
t PLANS FOR RX OPERATION
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4 U.S. NUCLEAR REGULATORY COMMISSION
NRC FORM 381 ^" V'D * * **
i EVENT NOTIFICATION 315
E.aen ExP,RES .0@11
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A. EVEftT CLASSeftCATIONtREQU4 RED NOTIFICATION
6. S ATON
1 ALERT f .
EVENT
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2. SITE AREA EMEh?L*.S l *
3 GENERAL EMERGENCY l
7 f0.72 NON-EMERGENCY )Ago
RCT WILL MAKE ALL OTHER NOTIFICATONS
8. UNPLANNED RE' 8m l moo
4. PHYS 8 CAL SECURITY 1 jaco
SAFEGUARD $
80 l stana
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- EO AND 4AT NOT REQUIRED FOR SOME EVENTS
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S. NOTIF#CATsON OF lRDO
UNUSUAL EVENTS
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C. EVENT DESCRIPTIONICAUSE .
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E. PLANNED ACTION / PRES $ RELEASE
.
F. OUTEIDE AGENCY OR PERSONNEL NOTIFIED by LICENSEE
Loca6
lista s.
time s
G OUTY OFFICER
PLEASE CALL B ACK WITH ANY CH APeGES OR
ADDITION AL INFORM ATION
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1MMEDIATE NOTIFICATION NO LONGER
-
REQUIREDBY950.72 .
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, WORKER INJURIES NOT RELATED TO RADIATION OR CONTAMI
.
. LOW LEVEL RELEASES LESS THAN 2 x PART 20 LIMITS AVERAGED
1
DVER ONE HOUR
, CERTAIN TESTING OR OPERATION RESULTING ~IN PREPLANNED
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EXAf1PLES OF It?lEDIATE NOTIFICATIONS
WITH Li - HOUR DEADLIflE
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. CERTAIN UNCOMPLICATED SC' LAMS WHERE PLANT R
. LOW LEVEL RELEASES * ,
. TRANSPORT OF CONTAMINATED INDIVIDUALS'
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. NEWSWORTHY ITEMS * .
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'ASSU.1NG1 110 1 - HOUR CRITERIA OR Ei1ERGENCY CLASS
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$ 50.72 Notifications March 1, 1985 - April 30, 1985
- of Reports Name # of Reports -
Name # of Reports Name
'
Harris 1 1 Point Beach 1, 2 d *'
Arkansas 1, 2 7
Prairie IS 1, 2 - 3
Beaver Valley 1, 2 2 Hatch 1, 2 34
Bellefonte 1, 2 0 Hope Creek 1 0 Quad Cities 1, 2 -
23
Rancho Seco 1
,
Big Rock Point 2 Indian Point 2 5
0
Braidwood 1, 2 O Indian Point 3 5 River Bend 1
6 Robinson 2 e2
Browns Ferry 1, 2, 3 32 Kewaunee
Salem 1, 2 9
Brunswick 1, 2 20 Lacrosse 16
LaSalle 1, 2 29 San Onofre 1 2
Byron 1, 2 23
San Onofre 2, 3 21
Limerick 1 16
- Callaway 1 9
Seabrook 1 0
Calvert Cliffs 1, 2, 7 Maine Yankee 3
Sequoyah 1, 2 7
Catawba 1, 2 13 Marble Hill 0
7
0 McGuire 1, 2 2 Shoreham
Clinton 0 South Texas O
'
Comanche Peak 1, 2 0 Midland 2
Cook 1, 2 18 Millstone 1, 2 11 St. Lucie l' 2 , 6
Summer 6
C:oper 1 Millstone 3 0
Monticello 5' Surry 1, 2 3
Crystal River 3 2
8 Susquehanna 1, 2 22
Davis-Besse 1 8 Nine Mile Pt 1 1
- Diablo Canyon 1, 2 1 Nine Mile Pt 2 0 Three Mile IS 1
North Anna 1, 2 .5 Three Mile IS 2 1
Dresden 1. 2, 3
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14 4
10 Oconee 1, 2, 3 13 Trojan
Duane Arnold 7 Turkey Point 3, 4 6
Farley 1, 2 5 Oyster Creek
2 Vermont Yankee 7
Fermi 2 14 Palisades 0
Palo Verde 1 10 Vogtle 1
Fitzpatripk . 1
0
Waterford 3 18
Ft. Calhoun 1 9 Palo Verde 2 20
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Palo Verde 3 0 Wolf Creek 1
'
Ft. St. Vrain 5
Peach Bottom 2, 3 4 Watts Bar 1, 2 0
Ginna 10 12
Perry 1 0 WNP 2
Grand Gulf 1 5
Yankee Rowe 3
Haddam Neck 2 Pilgrim 1 9
Zion 1, 2 12
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SUGGESTIONS FOR 10 CFR 50.72
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ADD REPORTING REQUIREMENTS:
DIESEL FAILURES ,
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ANTICIPATED EMERGENCIES
CONTENTS OF NOTIFICATIONS (SPECIFIC OR GENERAL)
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DELETE REPORTING REQUIREMENTS
SPURIOUS ACTUATIONS THAT DO NOT SIGNIFICANTLY AFFECT
OPERATIONS ..
SINGLE TRAIN SAFETY SYSTEM FAILURES
'
i SCRAMS WHEN NO RODS MOVED OR SHOULD HAVE MOVED
.
EN$ANCECONSISTENCYWITHTECHNICALSPECIFICATIONS
ADD EXEMPTION PROVISIONS TO S50.72 SIMILAR TO 550.73
-CLARIFY REPORTING THRESHOLD FOR EMERGENCY PREPAREDNES
. RESPONSE CAPABILITY
~
ENHANCE CONFORMITY AMONG PLANTS OF DIFFERENT VINTAGES
(1.E. DEFINITION OF ESF VARIES)
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SSINS No.: 6835
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
4 - - - 0FFICE OF INSPECTION AND ENFORCEMENT
WASHINGTON, DC 20555.
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April 3, 1985
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NOTIFICATIONS TO THE NRC OPERATIONS
IE INFORMATION NOTICE No. 85-27:
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CENTER AND REPORTING EVENTS IN LICENSEE
EVENT REPORTS .
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- Addressees
}
- All nuclear power reactor facilities holding an operating license (0L) or a
'
construction permit (CP).
l
Purpose:
,
This notice is provided to clarify the requirement for licensees to report to
the Headquarters Operations Center an event or condition that results in or
could result in multiple failures in safety systems. This guidance is also
applicable to the requirement for licensees to repcrt events as Licensee Event
...
Reports (LERs). It is expected that recipients will review the information No specific
for
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applicability to their facilities and take appropriate action.
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action or response.is required by this notice.
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. Description of Circumstances: -
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This, issue has arisen as a result of a recent event at a nuclear power plant
i
during which multiple failures occurred in the' scram system, but the licensee
i
did not consider it necessary to report the failures to the Headquarters
Operations Center.
The event occurred while performing single control rod scram time testing.
,
One of the control rods scheduled for testing failed to scram when the
Subsequent scram
testing of
pilot solenoid valve stuck in the energized position.the remaining
The unit was operating at power
. control rods exhibited initial hesitation.
l when the problems occurred.
.
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,. Discussion:
)l -
Theparagraphof10CFR50.72thatrequiresr$portingofallmultiplefailures
and some single failures is paragraph 50.72(b)(2)(iii), which requires the
,
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licensee to notify the NRC Operations Center as soon as practical and in all -
-
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cases within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of the occurrence of:
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April 3, 1985
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c Any. event or. condition that alone could have prevented
the fulfillment of the safety function of structures or
systems that are needed to:
-
(a) Shut down the reactor and maintain it in a safe
shutdown condition, -
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(b) Remove residual heat,
(c) Control the release of radioactive material, or
(d) Mitigate the consequences of an accident.
10 CFR 50.73(a)(2)(v) also contains words identical to the preceding excerpt.
Multiple failures of redundant components required to perform any of the above
safety functions are reportable. A single failure in a component required to #
perform any of the above safety functions is reportable when there is sufficient
reason to expect that the failure mechanism is one that could occur in a
redundant component.
Multiple failures of redundant components of a safety system are sufficient
reason to expect that the failure mechanism, even though not known, could
prevent the fulfillment of the safety function. While the failure of a single i
,
rod to scram may not cause a reasonable doubt that other rods would fail to
scra'm, the failure of multiple rods to scram causes a reasonable doubt that
other rods.could be affected and, thus, this is an event or condition that
f ,
could prevent the fulfillment of the safety function (i.e., the RPS scram)
.
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needed to shut down the reactor. ,
A single failure in a safety system is reportable when it is determined that
the failure mechanism could reasonably be expected to occur in a redundant
compgnent or components of a safety system such that,the fulfillment of the
t.
safety function would be prevented. The preamble to the Federal Register
Notices that published the 10 CFR 50.72 and 10 CFR 50.73 rules provide as an
example:
'
...if a pump fails because of improper lubrication, there
is a reasonable expectation that the functionally redundant
pump, which was also improperly lubricated, would have also ,
failed before it completed its safety function, then the
failure is reportable and the potential failure of the
.
functionally redundant pump must be reported.
Such a single failure is reportable to the NRC Operations Center as soon as -
practical and in all cases within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of determining that the failure
mechanism could reasonably be expected to occur in a redundant component or
components of a safety system. Similarly sucir a single failure is reportable
in a Licensee Event Report within 30 days of determining that the failure
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mechanism could reasonably be expected to occur in a redundant component or
components of a safety system.
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April 3, 1985
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No written response to this information notice is required. If you need
additional information about this matter, please contact the Regional Admini-
strator of the appropriate NRC regional office or the technical contacts listed
below. .
.
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wa d dan, Director
Divisi of Emergency Preparedness ,'
and ngineering Response
Office of Inspection and Enforcement ,
Technical Contacts: 10 CFR 50.72
E. W. Weiss, IE
(301) 492-9005
F. J. Hebdon, AE00
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, (301) 492-4480
Attachment: List of Recently Issued IE Information Notices
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EDWARD 1. JORDAN, DIRECTOR
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DIVISION OF EMERGENCY PREPAREDNESS AND ENGINEERING RESPONSE - .-
0FFICE OF INSPECTION AND ENFORCEMENT ,
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U. S. NUCLEAR REGULATORY COMMISSION
S
- S50.72 IMMEDIATE NOTIFICATIONS
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NRC INCIDENT RESP _0NSE PROGRAM
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INCIDENT BEGINS
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pA4 flY EY 5 (
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CALL TO NRC OPERATIONS CENTER (W/I ONE HOUR)
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OPERATIONS CENTER ASSESSES INCIDENT AND CONTACTS
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REGIONAL DUTY OFFICER AND HQ MANAGEMENT TO INITIATE RESPONSE. $p%7
v
- Ed W
EMERGENCY RESPONSE IN ACCORDANCE WITH NRC
MANUAL CHAPTER 0502 (REGIONS, NRR, IE, NMSS)
- *
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RESPONSE CENTER ACTIVATED REGIONAL IEAM TO SITE-
COLLECT AND ASSESS INFORMATION REGARDING" PLANT CONDITION
RECOMMEND ACTIONS FOR PROTECTION'0F THE PUBLIC
v
PLANT STABILITY ACHIEYED .
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DEACTIVATION OF EMERGENCY RESPONSE
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INVESTIGATION PHASE '-
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IMMEDIATE NOTIFICATIONS
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NUCICAR POWER PLANT
. OR
FUEL FACSLlTY
1 f
NRC OPERATIONS
CENTER
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COMPUTER
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HQ OTHER
REGIONAL FEDERAL DATA
EMERGENCY BASE
DUTY OFFICER OFFICER * AGENCIES *
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7
REGION EVENTS % EGidNS R
MANAGEMENT *
INPO + ** NOTEPAD **
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ASSISTED
ANALYSIS
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TECHNICAL INVESTIGATION -
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EMERGENCY EVENTS
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DEACTIVATION OF EMERGENCY RESPONSE
. - (NON-EMERGENCY EVENTS)
v
EDO ESTABLISHES TECHNICAL INVESTIGATIVE TEAM
v
FACT FINoING
v
ASSESS INFORMATION ,
v
PREPARE REPORT WITH RECOMMENDATIONS
v
NRR/IE EVALUATE AND INITIATE APPROPRIATE ACTION
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EVENT SCREENING AND EVALUATION ,
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. PROMPT SCREENING. BASED ON 50 72, WRITTEN LER RECEIVED
50,55E OR PART 21 NOTIFICATION ~
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0RAB/EAB CONFERENCE CALL
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INSPECTION -
GENERIC CONCERNS ISSUE REPORT WITH
'
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ENFORCEMENT -
INFO NOTICE / BULLETIN / RECOMMENDATIONS
"
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FOLLOW UP GENERIC LETTERS V
NRR/IE EVALUATE AND
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IE/NRR/AE0D BIWEEKLY
INITIATE APPROPRIATE
BRIEFINGS
l -
ACTION
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ACRS BRIEFING
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AEOD - ENGINEERING EVALUATIONS 27
IE - INFORMATION NOTICES 94
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j NRR - GENERIC LETTERS 24
ABNORMAL OCCURRENCES
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- AEOD - P0wER REACTOR EVENT REPORTS BI-MONTHLY
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NRC RESP 0NSE T0
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EVENTS AT LICENSED FACILITIES
REAL TIME FOLLOW DURING EVENT
EVALUATION TO DETERMINE ADEQUACY OF LICENSEE CORRECTIVE ACTIONS SUBSEQUENT
~
TO EVENT
.
EVALUATION TO DETERMINE GENERIC IMPLICATIONS FOR SINILAR FACILITIES ,
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AGENCY ROLE
FOR REAL TIME FOLLOW
MONITOR THE LICENSEE TO ASSURE APPROPRIATE PROTECTIVE ACTION IS
-
BEING TAKEN WITH RESPECT TO OFFSITE REC 0fetENDATIONS.
.
SUPPORT THE LICENSEE (TECHNICAL ANALYSIS & LOGISTIC SUPPORT)
.
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SUPPORT OFFSITE AUTHORITIES, INCLUDING CONFIRNING THE LI,CENSEE'S
REC 0petEN0ATION TO 0FFSITE AUTHORITIES. . .
KEEP OTHER FEDERAL AGENCIES AND ENTITIES INFORMED OF THE STATUS OF
THE INCIDENT.
KEEP THE MEDIA INFORMED OF THE NRC'S KNOWLEDGE OF THE STATUS OF
THE INCIDENT, INCLUDING COORDINATION WITH OTHER PUBLIC AFFAIRS
GROUPS.
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10 CFR 50.72 REP 0RTS
10 CFR 50.72 REQUIRES RAPID NOTIFICATION BY TELEPHONE TO THE OPERATIONS CENTER .
FOR EVENTS HAVING POTENTIAL SAFETY SIGNIFICANCE
. PROFESSIONAL IN OPERATIONS CENTER SCREENS ON REAL TIME BASIS EVERY EVENT TO
DETERMINE NEED FOR ACTIVATING HEADQUARTERS AND REGIONAL RESPONSE TEAMS -
'
POTENTIAL EMERGENCIES ARE DISCUSSED WITH HEADQUARTERS AND REGIONAL SENIOR
MANAGEMENT TO DETERMINE NEED FOR ACTIVATING RESPONSE TEAMS
.
REGIONAL OFFICE RESPONSIBLE FOR FACILITY IS NOTIFIED OF EVERY EVENT -
,
EVERY EVENT IS SCREENED IN HEADQUARTERS DURING FIRST TWO HOURS OF FIRST
WORKING DAY FOLLOWING RECEIPT OF TELEPHONE NOTIFICATION
'
IE DETERMINES NEED FOR GENERIC C0 muNICATION (BULLETIN OR
INFORMATION NOTICE)
NRR DETERMINES NEED FOR LICENSING ACTIONS ON SPECIFIC PLANT
'
OR OTHER PLANT
- - -
REGIONAL OFFICE DETERMINES ADEQUACY OF LICENSEE CORRECTIVE ACTIONS ,
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SHORT TERM EVENT SCREENING
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IdCFR50.72REPORTEDEVENTSAREDISCUSSEDINMORNINGTELEPHONECONFERENCECALL
BETWEEN NRR AND IE TO DETERMINE SAFETY SIGNIFICANCE AND/OR GENERIC IMPLICATIONS
REGION DAILY REPORT ITEMS ARE DISCUSSED IN MORNING TELEPHONE CONFERENCE CALL
BETVEEN NRR AND IE TO DETERMINE SAFETY SIGNIFICANCE AND/OR GENERIC IMPLICATIONS
EVENT FOLLOW-UP ASSIGNMENTS ARE MADE IN MORNING TELEPHONE CONFERENCE CALL
REGIONAL OFFICE OR LICENSEE CONTACTED WHERE NECESSARY TO OBTAIN ADDITIONAL ,
INFORMATION
-
REGIONAL REPRESENTATIVES AT PLANT SITE RELIED UPON TO COLLECT FACTS ON EVENTS
REGIONS CONFER WITH NRR/IE AS NECESSARY TO EVALUATE LICENSEE CORRECTIVE ACTIONS
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