ML20207J267
| ML20207J267 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 12/24/1986 |
| From: | Mccoy F, Wilson B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20207J237 | List: |
| References | |
| 50-400-86-76, NUDOCS 8701080367 | |
| Download: ML20207J267 (51) | |
See also: IR 05000400/1986076
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 81
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101 MARIETTA STREET,N.W.
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ATLANTA, GEORGI A 30323
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Report No.:
50-400/86-76
Licensee: Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-400
License No.:
e
,
Facility Name:
Shearon Harris
Inspection Conducted:
September 22-26, 1986
October 6-10, (1946
Novembe
3-7,
986
/2/A/ d
Inspector:
f
s
F. R. MCoy, Te'am Leader ~W
Ofteyigned
Team Members:
B. A. Wilson
S. Bitter
W. K. Poertner
H. P. Krug
J. E. Tedrow
R. Latta
D. P. Falconer
C. Vanderniet
U
P. B. Moore
B. Beardon
L. J. Watson
W. G. Kennedy, NRR
,
Approved by:
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B. A. Wilson, Acting Sec'fion Chief F
Uate Signed
Operational Programs Section
Division of Reactor Safety
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SUMMARY
Scope:
This routine, . announced inspection was conducted in the areas of
Technical
Specifications, control
room activities and plant procedures.
Procedures reviewed included administrative procedures, operating procedures,
emergency operating
procedures,
abnormal
operating
procedures,
general
procedures, annunciator panel procedures, operations work procedures, maintenance
procedures, and surveillance test procadures.
This inspection was a followup
inspection to that conducted July 14-18, 1986 and reported in NRC inspection
!..
report 50-400/86-57.
Results: One violation was identified for failure to follow procedures. This
violation is discussed in paragraph 10.
8701080367 861229
ADOCK 05000400
0
REPORT DETAILS
1.
Persons Contacted
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Licensee Employees
-#R. A. Watson, Vice President, Harris Project
- J. L. Willis, Plant General Manager
- C. R. Gibson, Assistant to the General Manager
.s
- J. L. Harness, Assistant Plant General Manager
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- J. M. Collins, Manager-Operations
- G. Campbell, Manager-Maintenance
<
-#R. B. Van Metre, Manager-Technical Support
- E. M. Steudel, Principal Engineer-Special Projects
- D. Tibbitts, Directcr-Regulatory Compliance
- H. W. Bowles, Director-0nsite Nuclear Safety
- D. Casada, Project Engineer-0nsite Nuclear Safety
- R. T. Biggerstaff, Principal Engineer-0nsite Nuclear Safety
- D. A. Morrison, Project Engineer-Onsite Nuclear Safety
- C. S. Bohanan, Director-Special Programs
-#C. H. Moseley, Manager-0perations Quality Assurance / Quality Control
- W. Powell, Manager-Training
-#D. C. Whitehead, Quality Assurance Supervisor-Operations
1
- J. H. Smith, Operations
-G. L. Forehand, Quality Assurance / Quality C'ntrol
-T. Brombach, Project Specialist - ISI
-M. Wright, Technical Support - ISI
- C. E. Ross, Quality Assurance / Quality Control
- J. L. Laurence, HEMS
- M. G. Casey, HPES
'
- E. E. Johnson, Document Services
'
- M. S. Halpern, Procedures Administration
- J. A. McAllister, Quality Assurance / Quality Control
,
- G. H. Davis, Technical Support
-#D. A. Nummy, Procedures Group
- W. A. Slover, Technical Support
- C. K. Jeffries, Regulatory Compliance
- A. J. Howe, Regulatory Compliance
-G. W. Taylor, Startup
-M. G. Wallace, Regulatory Compliance
5
Other licensee employees contacted included engineers,
technicians,
operators, mechanics, and office personnel.
,
NRC Resident Inspectors
- G. E. Maxwell
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-#S. P. Burris
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- Attended exit interview of 09/26/86
- Attended exit interview of 10/10/86
-Atter.ded exit interview of 11/07/86
2.
Exit Interview
The inspection scope and findings were summarized on September 26
October 10,
and November 7,
1986, with those persons inoicated in
paragraph 1 above.
The inspectors described the areas inspected and
discussed in detail the inspection findings.
No dissenting comments were
received from the licensee.
Although proprietary material was reviewed during the inspection, no
proprietary information is contained in this report.
3.
Licensee Action on Previous Enforcement Matters
This subject was not addressed in the inspection.
4.
Unresolved Items
Two unresolved items were identified during the inspection which are
associated with inadequate testing.
(See paragraph 10)
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5.
General Conclusions
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The inspectors concluded that although some specific deficiencies existed
with administrative procedures, system operating procedures, general
procedures, maintenance procedures and surveillance test procedures, these
,
<1efictencies were not indicative of major programmatic problems with
procedure adequacy. Additionally, the majority of the deficiencies were
considered to be of the type that should be readily identified during usage.
In the case of emergency operating procedures, abnormal operating
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procedures, annunciator panel procedures, and operations work procedurcs,
the inspectors considered that procedural deficiencies reflected some
programmatic problems that would require resolution prior to full power
,
operation.
In each case, the licensee committed to take corrective actions
(identified as inspector followup items 400/86-76-01, 400/86-76-03, and
400/86-76-11 in this report) prior to entry into Mode 1 operation.
If
properly implemented, these corrective actions should assure procedure
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adequacy prior to full power operation.
Problems observed with performance of the diesel generator operability test
as delineated in violation 400/86-76-17 (paragraph 10) are considered by the
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inspectors to be a result of undergoing transition from a construction /
testing mode to an operating mode.
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Problems observed with RHR sys' tem testing as identified in unresolved items
400/86-76-14 and 400/86-76-16 and inspector followup item 400/86-76-15 could
' 'hW resulted in the licensee failing to properly implement surveillance
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requi ements. Confirmation of satisfactory performance of these tests prior
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to the required modes and completion of corrective actions to ascertain and
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correct, if necessary, any generic problem should alleviate concerns in this
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area.
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Concerns were identified relating to water haner potential as a result of
open drain Itnes on the emergency service water ; supply to auxiliary
feedwater ,and. as a result of lack. of high po' int vents in the auxiliary
feedwater and other safety related systems. The licensee's commitments to
evaluate, and where appropriate, take corrective actions, prior to the time
for which these systems are required, should alleviate concerns in this
area.
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6.
Review Of Emergency Operating Procedures
/
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The inspectors reviewed the applicalit's Emergencv Cperating Procedures
(EOPs) using the guidance of hmporary Instruction (TI 2515/79, " Inspection
of Emergency Operating Procedares." This TI was use dn lieu of Module
Number 424528, " Emergency Procedures."
The areas reviewd . included the
Procedures Generation Package (PGP), the Plar.t-Specific Technical Guidelines
(P-STG), the Verification and Validation, (V&V) program and the training of
licensed personnel.
Since the Plant-5p'ecific Writers Guide was reviewed in
detail following an audit by- NRR in July 1986, it yas not r'eviewed during
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this inspection.
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a.
Procedures Generation PacLage '
?
The applicant's PGP was ' submitted to the .NRC by letter dated
September 18, 1984. :In July 1986 an NRC headquarter's audit team
conducted a site visit to discuss their concerns and attempt to resolve
these concerns in a timely manner. This fs documented in a trip report
dated August 4,.1986. A second site visit was.also made on August 14,
7
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1986. On August 29, and September 19, 1986,~ the' applicant provided
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additional inforniatio'n' on"the concerns identified during the site
visits. On September 22,'1986, a Sa_fety Evaluation Report (SER) was
issued which concluded that the appficant's PGP was acceptable for a
low power license.
This acceptance, however, was conditioned upon
several commitments made by the licensee in response to NRC concerns.
The concerns identified in the SER were as follows:
(1) The E0Ps lack procedural details and rely heavily on operator
knowledge.
(2) There were apparent inconsistencies between the E0Ps and the
Writer's Guide.
(3) As part of the V&V program, the E0Ps were not verified to be in
compliance with the Writer's Guide.
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(4) The training program must compensate for the lack of detail
necessitated by the " flow path" format.
The acceptable conclusion of the SER was based on the applicant's
schedule for submittal of additional or clarifying information. This
schedule included:
Plant-specific information by October 1, 1986
Revise Writer's Guide and E0Ps - significant items by December 12,
1986, and all others by the end of the first refueling
Documentation of the V&V process in a revision to the PGP by
April 15, 1987
,
Information regarding the E0P training program consistent with the
training information to be provided for the Writer's Guide.
b.
Techriical Adequacy of E0Ps
The inspectors reviewed in detail seven E0Ps.
These E0Ps, the
corresponding Westinghouse Owners Group (WOG) Guidelines and titles are
as follows:
E0P
Guideline
Title
PATH-1
E-0 and E-1
Reactor Trip or Safety Injection / Loss
of Reactor or Secondary Coolant
PATH-2
E-3
Steam Generator Tube Rupture
EPP-4
Reactor Trip Response
EPP-5
Natural Circulation Cooldown
EPP-8
SI Termination
EPP-14
E-2
Faulted Steam Generator Isolation
FRP-C.1
FR-C.1
Response to Inadequate Core Cooling
For every step of each procedure, the licensee prepared a Step Devia-
tion Document (SDD). The intent of the SDD is to describe and justify
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any deviation between the licensee's procedure and the WOG Guideline.
The inspectors reviewed the above listed procedures against the
corresponding WOG Guideline and the SDDs.
In general, the inspectors
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determined that the licensee's E0Ps followed the intent of the WOG
Guidelines; however, many inadequately justified deviations were made.
Specific examples are as follows:
Foldout B does not completely follow the foldc.ut page
PATH-1
contents for E-0.
Foldout B could lead the operator into EPP-16 which
leads to PATH-2; verification of SI flow and AFW flow is
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disregarded.
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The plant difference document states that the discharge
pressure of low head SI pumps is 160 psig.
PATH-1 says
to verify RHR flow if RCS pressure <190 psig.
Reset of FW isolation (when Phase A and Phase B are
reset) is not called for in WOG.
Throttling of AFW flow to steam generators is required
earlier in PATH-1 than it is called for in WOG;
justification is inadequate.
Foldout E does not conform to the foldout page contents
EPP-8
of E-1
WOG Response Not Obtained (RNO) for starting one air
compressor and establishing instrument air to contain-
ment was deleted.
WOG RNO kickout goes to E-1 "LOCA"; the E0P kickout goes
to EPP-9, " Post-LOCA Cooldown and Depressurization."
Two CAUTION statements were added that were not required
EPP-14
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by WOG and were inappropriately worded as action steps.
Step 6 transitions back to PATH-1; this was not required
by WOG nor adequately justified in S00.
Step 7 calls for in-core temperatures being below 900 F:
FRP-C.1
WOG temperature requirements are less than 700F.
WOG calls for ensuring power is available to pressurizer
PORV block valves.
The SDD explanation for deleting
this step is incorrect since it addresses the avail-
ability of power to the PORVs instead of to the block
valves.
Criteria for identifying a ruptured steam generator are
PATH-2
not listed; SDD states that this is required knowledge.
Step 4 is missing the target value for boration for each
EPP-4
stuck rod as required by WOG.
Step 6a SDD setpoint for SI was listed as 1881 psig
while EPP-4 lists 1850 psig.
Step 10b. tells operator to start one or more RCP(s)
while WOG only specifies one RCP; justification is
inadequate.
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In addition, the inspectors reviewed the licensee's setpoint study to
verify the correctness of plant-specific values that had been
incorporated into the E0Ps. Many deviations were noted as a result of
this review. In comparing the nine footnote values required by FRP-C.1
against the setpoint study, one was found to be incorrect while three
others in the setpoint study were listed as "later."
It was
subsequently determined that the inspectors were provided with an
uncorrected copy of the setpoint study; however, the corrected copy
maintained by the licensee was also found to have numerous errors.
The licensee acknowledged that both the SDD and the setpoint study had
not been maintained up-to-date to reflect numerous changes made to the
E0Ps. They also acknowledged that many steps in their E0Ps did not
conform to the WOG and in most of the identified cases, the deviations
were inappropriate or inadequately justified.
In a letter to the NRC dated October 8, 1986, the licensee responded to
the inspector findings with regard to the E0Ps. The licensee stated
that a comprehensive review of their E0P network relative to the WOG
Guidelines was completed on October 3, 1986. This review was conducted
by a three member task force consisting of an SRO licensed shif t
technical advisor (STA) and two SRO contract personnel familiar with
both the WOG guidelines and the licensee's E0P network. Each procedure
was evaluated relative to the WOG Guideline and where necessary
additional justification was incorporated in the SDD.
In those cases
where the deviation was deemed inappropriate, the E0Ps were modified to
be consistent with the WOG Guideline.
This review process was audited by the inspectors on October 8-10,
1986.
In reviewing PATH-1, the inspector noted three deviations that
were overlooked or inadequately justified. These deviations included:
On an ATWS event, failure to verify the TDAFW pump running, if
necessary.
On an ATWS event, failure to ensure PORVs and block valves open
following emergency boration.
Inadequate justification for the throttling AFW flow at a time
earlier than called for in the WOG guideline.
The licensee acknowledged these findings and committed to correcting
the first two examples. They also provided additional information from
Westinghouse which appeared to provide adequate justification for the
third example. The licensee also stated that only a first level review
had been completed and additional reviews by other qualified personnel
would be conducted prior to issuance of the revised E0P network.
This
major revision is scheduled to be completed by December 12, 1986. The
October 8,1986 letter also contained commitments to review and update
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the setpoint study and the SDDs.
These revisions are scheduled to be
completed by October 15, 1986 and January 31, 1987, respectively.
Additional NRC review in this area will be conducted following the
revisions and prior to mode 1 operations. Completion of this review is
identified as an inspector followup item (400/86-76-01).
c.
Validation and Verification Program
The PGP committed to perform simulator testing, table top reviews, and
control room walkthroughs as part of the E0P validation and
verification (V&V) program.
As
part
of
this
in aaction,
the
inspectors'
interviewed
Mr. Robert Shepherd of RMS, Inc., who provided consulting services to
the licensee on their E0P development program.
The inspectors
determined that part 1 of the V&V program, simulator testing, was
conducted on the old Harris simulator, the Seabrook simulator and the
new Harris simulator in Pittsburg while it was undergoing acceptance
testing. The dates and approximate time periods were as follows:
Old Harris simulator:
June - August, 1983 -
3 weeks
Seabrook simulator:
March, 1985
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I week
New Harris simulator:
July, 1985
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I week
Overall, a formal V&V program using the present E0Ps on the new Harris
simulator has not yet been conducted. The V&V program conducted to
date has been somewhat deficient in several respects. The old Harris
simulator apparently had computer modeling limitations such that it was
difficult, if not impossible, to enter red path critical safety
functions. Also, the procedures used were not specific to Harris but
were generic to both the Harris and Robinson plants. Although some
work was conducted while the new simulator was in Pittsburgh, it was
part of a simulator acceptance testing program rather than strictly E0P
validation. A report containing recommendations for E0P changes was
made as a result of. these tests.
The inspectors could find no
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evidence, however, that the recommendations from this report were
incorporated into the E0Ps.
With regard to the table-top reviews, the licensee stated that they
were performed as committed to in the PGP but the supporting
documentation was subsequently lost. Mr. Shepherd of RMS stated that
his company was responsible for the control room walk-throughs. These
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walk-throughs were accomplished with a normal operations crew and were
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witnessed by human factors experts.
He also stated RMS has
documentation to support these walk-throughs.
The licensee is planning a formal V&V program in 1987.
There are
several factors impacting the schedule for this program:
simulator
availability, new revisions to WOG guidelines, and E0P revisions based
on this inspection.
This program is tentatively scheduled for
completion in for June 1987. Further NRC review in this area following
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completion of licensee actions is identified as an inspector followup
item (400/86-76-02).
d.
E0P Operator Training
The inspectors observed NRC administered simulator examinations,
interviewed training personnel and interviewed three licensed operators
in the control room. Although the operators appeared to be comfortable
with the use of the flow path network and familiar with the intent of
the procedures, the inspectors identified several concerns with respect
to procedural knowledge. These concerns were primarily based on the
level of detail required to be memorized by the operators in the
verifications of automatic actions and the omissions of " Response Not
Obtained" in both the flow paths and the narrative procedures. These
concerns were also previously identified by the NRR audit team
(reference their report dated August 4,1986). In response to the NRR
audit team findings, the licensee, by letter dated October 1,
1986,
submitted additional information concerning the E0P training of
licensed operators.
Enclosure 1 to this letter answered two NRR
concerns and seven comments. Those NRR items that coincided with the
findings of this inspection team were the following:
CONCERN 1A:
Certain plant-specific information which is called
for in the Westinghouse ERGS has not yet been provided in the
Harris E0Ps.
CONCERN 18:
Develop or provide evidence of a training program
that systematically assures that information gaps in flow charts
and textual procedures are addressed specifically during future
training;...
COMMENT 1:
The extensive use of the flow charts in the E0Ps as
described in the writer's guide reduces the amount of information
that procedures can provide to operators.
The training program
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must compensate for this lack of information,
i.e., the operators
knowledge of plant procedures must be greater.
COMMENT 3B:
Indicate the use of a wide variety of scenarios
including multiple failures, to fully exercise the E0Ps on the
simulator and thus expose the operators to a wide variety of E0P
uses.
On September 24, 1986, the inspectors briefly walked through Flow
Path-1 with three licensed personnel in the control room.
These
interviews substantiated the fact that there were gaps in the operator
knowledge that were not covered by written procedures.
For example;
when the operators were asked to verify Phase A, Phase B, or feedwater
isolation, none of 'the three successfully named all of the affected
valves.
In addition, mistakes were made in the setpoints for
safeguards initiation and other verifications such as containment
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ventilation isolation, proper operation of containment fan coolers and
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verification of main steam isolation.
The inspectors interviewed two training department representatives to
ascertain if simulator scenarios included equipment failures designed
to test the operators ability to correctly perform the required
verifications.
The inspectors also reviewed several
simulator
scenarios. Although multiple failures are included in their simulator
exercises, they are limited to major or more obvious equipment failures
such as ATWS, stuck open PORV, failure of SI pump, etc. They do not
include less obvious malfunctions such as failure of one or more
4
containment isolation valves to close.
In response to the findings of the inspectors and the NRR audit team,
the licensee has provided the following:
(1) Attachment 1 of their October 1,1986 submittal is a step matrix
that identifies the plant specific information that was not
included in the E0P network.
In many cases the step matrix
identifies procedural revisions that will be made to include the
necessary information.
(2) Attachment 2 of the same submittal is an emergency procedures task
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training matrix that shows where training on plant specific
information required to execute the E0Ps has been provided_for the
cold license group and will be provided for hot license
candidates.
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(3)
In developing the above two attachments, the licensee identified
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three tasks requiring additional training.
They committed to
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complete this training by December 31, 1986.
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(4) The licensee developed PATH GUIDES-1 and 2 which are textual
versions of Flow Paths-1 and 2.
These guides were originally
intended to be a backup to the flow paths; however, as a result of
the NRC findings, the licensee intends to expand the use and
content of these guides both in the training of operators and
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their use in the control room.
(5) Computer capability through the use of the ERFIS program is
scheduled to be implemented for rapid reference to a CRT displayed
list of automatic actions. This should enable the operators to
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quickly display, for example, the list of Phase A isolation valves
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which will highlight any mispositioned valves.
(6) Operations management procedure, OMM-004, Post Trip / Safeguards
Review, contains multiple attachments that identify many automatic
actions that require verification. Verification of these actions
using these attachments is intended to be en STA function.
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As part of the E0P revision effort, currently underway, the Harris
training unit will determine the additional training that will be
required.
This retraining should encompass any already identified
4
deficiencies, E0P revisions, use of additional aides such as the
computer and path guides and other training as may be required by PGP
revisions. The October 8,1986 submittal committed to completion of
all required retraining prior to exceeding 5*4 power.
Further NRC
review in this area following completion of licensee actions is
identified as an inspector followup item (400/86-76-03).
e.
Document Control of E0P Materials
During the week of November 3-7,
1986, the inspectors queried the
licensee about maintenance of document control in accordance with the
licensee's quality assurance program for E0P source documents and E0P
development documentation. Source documents would include ERG manuals,
PGP, and E0P setpoint study.
E0P development documentation would
include step deviation documents and verification and validation
documentation. The licensee stated that these types of documents were
not currently being maintained in accordance with the licensee's
quality assurance document control program.
At the exit interview,
however, the licensee committed to incorporate these documents into
their document control system. Evaluation of licensee actions on this
matter is identified as an inspector followup item (400/86-76-04).
7.
Review Of Operations Procedures
This review consisted of a detailed technical review of selected portions of
operating procedures, general procedures, abnormal operating procedures, and
annunciator panel procedures associated with seven randomly selected
systems. These systems were the auxiliary feedwater system, residual heat
removal system, class 1E electrical system, containment ventilation system,
vacuum relief system, emergency service water system, and post accident
hydrogen monitoring system. This review also encompassed a technical review
of general procedures associated with normal plant heatup and normal plant
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shutdown. Additionally a generic review of abnormal operating procedures,
annunciator panel procedures, and operations work procedures was conducted.
a.
Auxiliary Feedwater System
The inspectors reviewed the operating procedures and annunciator
response procedures associated with the auxiliary feedwater (AWF)
system. The procedures were reviewed to determine that the important
safety requirements were satisfied and that the procedures contained
the necessary prerequisites, precautions, limitations and check lists.
Provisions to fill, drain, vent, startup, shutdown, change from one
operating mode to another, and identify abnormal conditions were
reviewed. Selected portions of the following procedures were reviewed
and walked down during the inspection:
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Auxiliary Feedwater System
Feedwater Malfunctions
Safe Shutdown in Case of Fire or Control Room
Inaccessibility
APP-ALB-014
Main Control Board
APP-ALB-017
Main Control Board
Service Water System
GP-002
Normal Plant Heatup from Cold Shutdown to Hot
Subcritical, Mode 5 to Mode 2
Main Steam System
The inspectors had the following observations:
'.strument numbers for the turbine driven AFW pump lube oil
pressure, governor end bearing oil drain temperature, and coupling
end bearing oil temperature were not included in OP-137.
The
licensee had initiated PCR000242 to produce a drawing for the lube
oil system and identify instrumentation and valves not previously
labeled.
In addition, valve numbers for nine instrument air
isolation valves in the valve checklist were not provided.
The
licensee had identified these discrepancies in the procedure and
will provide the valve numbers upon completion of the system valve
tagging.
Resolution of these problems as well as other operating
procedure problems specifically noted in paragraph 7 is identified
as an inspector followup item (400/86-76-05).
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The primary source of feedwater to the AFW system is the
condensate storage tank (CST).
The licensee utilizes the
emergency service water (ESW) system as a backup source of water.
OP-137 provided instructions on switchover of the two AFW motor
driven pumps and the turbine driven pump to a supply from the ESW
'ystem.
The initial valve lineup checklist indicates that the
orain valves in the ESW system supply lines were open.
The
switchover involved closing a drain line between two series
isolation valves in each supply line.
FSAR section 10.4.9.2.2
states that the switchover from the CST to the ESW system is
performed manually from the control room.
FSAR figure 9.2.1.1
indicates that the system lineup includes two series valves in
each supply line [1-SW-121 and 1-SW-123, train A (motor driven);
1-SW-130 and 1-SW-132, train B (motor driven); 1-SW-124 and
1-SW-125 train A (turbine driven); and 1-SW-127 and 1-SW-129
train B (turbine driven)] with a drain line between the valves
,
, ,
.-
.
- = _ . - - _ -
12
isolated by a closed drain valve (1-SW-122 and 1-SW-131, train A
and B (motor driven) and 1-SW-125 and 1-SW-128, train A and B
(turbine driven), respectively). ~ Each drain line was shown with a
capped end. OP-137 deviates from the FSAR description in that
local manual actions,
i.e., closing four drain valves, must be
accomplished prior to opening the isolation valves from the
control room.
In addition, the FSAR indicates that the drain
valves are closed and therefore, implies that the line is water
solid.
The current switchover sequence would result in air
trapped between the isolation valves to be swept into the pumps
and AFW piping which could result in pump damage or trip and/or
water hammer in the AFW piping.
The licensee stated that the
drain lines were kept open to prevent corrosion in the ESW system
piping.
The licensee agreed to reevaluate the effect of air in
the piping and perform an evaluation to determine if an unreviewed
safety question existed. NRC evaluation of the unreviewed safety
question determination is identified as an inspector followup item
(400/86-76-06).
FSAR Section 10.4.9.5 states that the AFW pumps have an alarm for
low pump suction, and a pump trip and alarm on low-low pump
suction. The inspector determined that the alarm for low-low pump
suction was not provided. The licensee has initiated PCR000466 to
resolve this item by plant circuit modification or FSAR
description change. Resolution of this concern is identified as a
part of inspector followup item 400/86-76-05.
The following deficiencies, noted in field walkdowns, had been
previously identified by the licensee and corrective action
initiated; or actions were taken by the licensee during the
inspection to correct the deficiencies:
-
Vibration element disconnected from turbine driven AFW pump.
-
Replacement of electrical cover on turbine driven AFW pump
governor control.
-
Caps missing on drain lines or not indicated in valve
checkli st.
-
Nameplates labeled incorrectly on main control board for main
steam supply valves.
-
Dust covers to be provided for valve 1-AF-41.
Repair of oil level gauge on turbine driven AFW pump.
-
Correction of valve number in OP-137 from 1-CE-109 to
-
1-AF-109.
- ..
-
-
. . .
.. -
13
The inspector observed that the A0P-010 section which identifies
steam voiding in the AFW piping could be enhanced by revising the
procedure t] indicate where temperature will be monitored by hand
held instruments to assure that all affected pumps and piping are
identified.
Attachment I of OP-126 did not require independent verification of
valves E5-315 and E5-316, low vacuum trip isolation valves.
Resolution of this concern is identified as a part of inspector
folicwup item 400/86-76-05.
b.
Containment Ventilation And Vacuum Relief System
The inspectors reviewed and walked down selected portions of the
operating procedures, annunciator response procedures and abnormal
optrating procedures associated with the containment Ventilation and
Vacuum Relief (CVVR) system. The procedures were reviewed to determine
that the important safety requirements were satisfied and that the
procedures
contained
the necessary ~ prerequisites,
precautions,
limitations and check lists. Provisions for startup, shutdown, change
from one operating mode to another, and identification of abnormal
conditions were reviewed.
Selected portions of the following
procedures were reviewed during the inspection:
Containment Ventilation and Vacuum Relief System
Loss of Containment Integrity
ALB-APP-028
Main Control Board
APP-ESF-A
ESF Bypass Panel A
EST-212
Type C Local Leak Rate Tests
OMM-11
Locked Valve List
The inspectors had the following observations:
Dampers on the CVVR system were not tabeled to indicate the open
or closed position.
Independent verification of the position of
safety related dampers, which is required by procedure PLP-702,
Independent Verification Review, would be difficult. The licensee
committed to proviodocal open/ closed indication on safety
related dampert. This is identified as an inspector followup item
(400/86-76-07).
EST-212, Local Leak Rate Testing, does not indicate that
replacement of vent caps on test line connections is independently
verified.
The
licensee
committed
to
revise
EST-212
to
independently verify replacement of the caps. Resolution of this
. _ _
_
_
__
_
_-
_
14
concern is identified as a part of inspector followup item
400/86-76-05.
Technical Specification 3.6.1.7 requires that the 42 inch purge
makeup and exhaust system valves be closed and sealed closed.
These valves are 1-CP-7, 1-CP-10, 1-CP-1 and 1-CP-4.
The licensee
uses the isolation of air supply to valves 1-CP-1 and 1-DP-7 to
seal close the valve and the removal of control power to seal
close valves 1-CP-10 and 1-CP-4.
The inspectors noted that this
is not specifically addressed on either the valve lineup
verification sheet or locked valve list.
The licensee committed
to revise OP-168 and OMM-11 to indicate that the air supply line
to 1-CP-1 and 1-CP-7 was locked closed and to specifically
identify the switch removing control power form valves 1-CP-10 and
1-CP-4.
In general, the lineup of the air supply to safety-
related dampers is not verified within operating procedures. The
inspectors consider such verification necessary in order to
properly verify system configuration.
Resolution of concerns
associated with air supplies to dampers is identified as an
inspector followup item (400/86-76-08).
The inspector noted the following discrepancies in OP-168 during
the field walkdown. The licensee indicated that actions would be
taken to correct these discrepancies.
Damper E5-1A-NNS was not on the damper checklist.
Manual air isolation valve near 2CP-B1-SA-1 was leaking.
Instrument air isolation valves for dampers 2-CP-B4-SB-1 and
2-CP-88-SB-1 were not labeled.
The metal identification tag for CB-D2-SB-1 was missing.
Inlet screen for containment vacuum relief valve 2-CB-B2-SB-1
did not appear to be properly bolted in place.
Drain valve on ventilation filter housings was not labeled.
(Licensee identified)
Resolution of these concerns is identified as a part of inspector
followup item 400/86-76-05.
c.
Class IE Electrical Systems and Post Accident Hydrogen Systems
The inspectors reviewed the operating procedures, abnormal operating
prm.edures, and annunciator response procedures for the post accident
hydrogen system, diesel generator emergency power system, and AC
electrical distribution system.
Selected portions of the following
procedures were used in accomplishing this review.
Some procedures
were entirely walked through with licensee operations personnel.
'
l
1
_,
. . .
15
Post Accident Hydrogen System
Diesel Generator Emergency Power System
AC Electrical Distribution
OPT-1510
Emergency Diesel Generators Daily Inspection / Checks
Loss of Uninterruptible Power Supply
Loss of One Emergency AC Bus (6.9KV) or One
Emergency DC (125v) Bus
Low Voltage Operations
APP-ALB-015
Main Control Board
APP-ALB-022
Main Control Board
APP-ALB-024
Main Control Board
APP-ALB-025
Main Control Board
APP-ALB-026
Main Control Board
APP-ALB-028
Containment Hydrogen Purge System
APP-AEP-002
Auxiliary Equipment Panel No. 2
APP-DGP
Diesel Generatcr Panel
APP-150
"A" Recombiner Local Control Panel Annunciator
Panel Procedure
The inspectors had the following observations and comments:
During the review of procedure OP-125 it was noted that after the
hydrogen purge and hydrogen recombiner systeras are placed in
operation, the procedure does not require operating parameters to
be observed or recorded on these systems. Several precautions and
limitations are specified in section 4 of this procedure.
For
example, precaution 4.5 stated to never exceed 1400 degrees shroud
temperature on a hydrogen recombiner, precaution 4.7 specifies for
proper containment hydrogen purge system operation that system
filter differential pressures must not be exceeded, precautions
4.8 and 4.9 specify that after placing a hydrogen recombiner in
service to monitor its performance hourly for proper operation and
log the hydrogen concentration hourly.
These precautions and
limitations could be overlooked by the operators unless the
procedure specifically directed the operator to note and record
these parameters.
Resolution of this concern is identified as a
part of inspector followup item 400/86-76-05.
During the walkthrough of procedure APP-DGP, it was noted that
part of the response for a diesel high pressure crankcase trip
required the operator to check the blower motor for proper
operation. Discussions with operations personnel revealed that no
blower motor existed for this system.
The licensee plans to
revise this procedure accordingly. Also when the diesel fails to
start, part of the response for this situation requires the
operator to open all fuel valves. This matter was discussed with
operations personnel who interpreted this step to mean to verify
that the fuel oil system is lined up in accordance with normal
.
.
.
.
___ - - -
_
_.
_
. _ _ .
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_ _ _ _ _ _
_ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
__
_
16
operating procedures.
The licensee stated that this procedure
would be revised to clarify the meaning of this step. Resolution
of these concerns is identified as a part of inspector followup
item 400/86-76-05.
During the walkthrough of procedure OP-155, it was noted that
Attachment VI of this procedure specified an upper limit on
generator field voltage of less than 181 volts.
However, the
voltage meter which the operator will use to monitor this voltage
(EI-6954A) only has a range of 0-150 volts. With this situation
an operator may not realize that he has reached or exceeded the
upper limit specified by the procedure. This matter was discussed
with licensee personnel who decided to change the upper limit on
the generator field voltage to less than 150 volts. Resolution of
this concern is identified as a part of inspector followup item
400/86-76-05.
During a comparison of procedures OP-155 and OPT-1510 the
inspector found discrepancies between the two procedures for
maintaining starting air pressure and control air pressure.
Specifically, procedure OP-155 requires the starting air pressure
to be maintained between 200-255 psig while procedure OPT-1510
requires this start.ing air pressure to be maintained between
190-255 psig.
Also procedure OP-155 requires the control air
pressure to be maintained greater than 50 psig while procedure
OPT-1510 requires this pressure to be greater than 60 psig. This
item was discussed with licensee representatives who stated that
the difference between these procedures was the result of a recent
revision to procedure OP-155 which changed these values.
The
licensee stated that procedure OPT-1510 would be revised to
provide consistency. Resolution of this concern is identified as
a part of inspector followup item 400/86-76-05.
During procedure walkthroughs, the inspectors noted that relief
valves were excluded from system lineups.
The inspectors were
concerned with how these types of valves would be controlled and
verified for system startup and operation to ensure that these
valves are not gaged or capped.
The licensee stated that system
valve lineups would be revised to include relief valves.
During
the week of October 6-10, 1986, the licensee stated that 16
procedures required revision and all 16 had been revised.
A
sample review of three procedures; OP-111, RHR System, OP-110,
Safety Injection, and OP-145, Component Cooling Water, reflected
that the valve lineup verification sheets had been revised to
include relief valves.
.
.
.
.
_ _ _
_________________
17
d.
Residual Heat Removal System
The inspectors reviewed selected portions of the following procedures
associated with the residual heat removal (RHR) system:
RHR System
Safety Injection
Loss of Residual Heat Removal
GP-2
Normal
Plant Heatup From Cold Shutdown to Hot
Subcritical, Mode 5 to Mode 3
GP-6
Normal Plant Shutdown
GP-7
Normal Plant Cooldown
GP-9
Refueling Cavity Fill, Refueling, and Draindown of the
Refueling Cavity
OST-1107 ECCS Flowpath and Piping Field Verification
OST-1108 RHR Pump Operability, Quarterly Interval
The inspectors reviewed the procedures for technical adequacy,
appropriate acceptance criteria and independent verification.
The
inspector also conducted a system walkdown of the RHR system and
procedure with an operator to determine the adequacy of the procedure
and to confirm the system configuration conforms to the plant drawings.
Some changes were noted to be pending on some of these documents in
order to reflect changes in actual plant configuration and operating
characteristics. As an example, the licensee determined that 19 system
high point vents are planned to be installed in the emergency core
cooling systems. Of these 19 vents, 6 are planned to be installed in
the RHR system.
The licensee will have to revise the operating
procedures to reflect these additional vents once installed.
Overall,
the licensee appears to have adequate procedures in the area of RHR
system operations to commence operation of the unit.
As indicated
above, the procedures will require revisions to reflect changes in
plant configuration; however, the inspectors believe that this will be
a " fine-tuning" process and the licensee has the mechanisms in place to
properly accomplish this.
-.
,
,
,
,
-
, - - - .
--
18
e.
Emergency Service Water System
The inspectors reviewed the following procedures associated with the
ESW system:
Component Cooling Water
Chemical and Volume Control System
Loss of Service Water
Loss of Component Cooling Water
Loss of Essential Services Chilled Water
AL,'-017
Loss of Instrument Air
1-APP-Al
Auxiliary Control Panel Annunciators
1-APP-CTMP
Cooling Tower Makeup Annunciator Panel
This review included reading through the procedure, examining the
review and research files for the operating procedures, and for the ESW
system, a walkdown of the actual system with an operator. Valve lineup
checklists were kept in the control room and were noted to be
satisfactory from the standpoint of independent verification.
The
inspectors performed a walkdown of the ESW system with one of the
reactor operators. During the walkdown the operator was queried as to
which train provided power to the " swing" or
"C"
charging / safety
injection pump (CSIP).
The operator was then asked whether or not it
was possible to switch trains and whether a procedure existed to
accomplish the switchover. The operator correctly stated that the
"C"
CSIP was connected to the "B"
train and that it could be switched to
the "A" train by disconnecting the motor from the
"B" train and pulling
redundant "A"
train cable out of an existing conduit and connecting it
to the pump.
The operator was not aware of a procedure to accomplish
the switchover but stated that it was a maintenance activity and the
inspectors might find the procedure in the maintenance section.
A
request made to the maintenance department for the procedure revealed
that such a procedure did not exist.
The licensee stated that the
switchover process was fairly simple, but lengthy; however, the
licensee believed that the switchover was within the skill of the craft
and therefore could be accomplished through a work order.
The
inspectors agreed that this process was simple and straightforward;
however, noted the following concerns:
The task will alter the configuration of a safety related system
without the use of an approved or controlled procedure;
Being done by a work request alone will not guarantee qualifica-
tions other than the skill of the craft;
This will not be a frequently performed task.
i
'
.
. - .
. -.
- . _ . .
- . _ - - -
19
In view of the above concerns, the establishment of a procedure to
perform the task of switching a " swing" pump from one electrical train
to the other is considered necessary and is identified as inspector
followup item (400/86-76-09).
f.
General Procedures
The inspectors reviewed and conducted a control room walk-through of
portions of the following general procedures.
GP-002
Normal
Plant Heatup from Cold Shutdown to Hot
Subcritical Mode 5 - Mode 3
GP-006
Normal Plant Shutdown from Power Operation to Hot
Standby Mode i to Mode 3.
These procedures appeared, in general, to provide adequate instructions
for the conduct of the heatup and shutdown evolutions. Several minor
discrepancies were noted in GP-002 as detailed below:
Prerequisites did not require the shift foreman to review the
equipment inoperable record, the temporary jumper and bypast log
or the minimum equipment list prior to initiating heatup.
Resolution of this concern is identified as a part of inspector
followup item 400/86-76-05.
Opening of the accumulator discharge valves and racking out their
respective breakers
are
not independently verified.
The
inspectors consider that the licensee should review general
procedures to ensure adequate implementation of independent
verification requirements. Resolution of this concern, as well as
the independent verification concern delineated in paragraph 11.h.
of this report is identified as an inspector followup item
(400/86-76-10.)
Attachment I does not require the performance of the Hydrogen
Purge System valve lineup checklist contained in OP-125, Post
Accident Hydrogen System.
Resolution of this concern is
identified as a part of inspector followup item 400/86-76-05.
g.
General Review of Abnormal Operating Procedures
During the course of the inspection conducted during the week of
October 6-10, 1986, the inspectors completed a detailed review of four
AOPs and a table top review of eight A0Ps.
In general the AOPs
appeared in need of a review to insure a consistent format is
established and minor administrative inadequacies in the procedures are
corrected.
Examples of these problems are as follows:
.
%
.
W
&
,
20
Notes are included in the immediate actions.
Caution statements are included in the immediate actions.
Symptoms and automatic actions were not validated using the
simulator.
Many terms need clarification;
e.g.,
backup heaters instead of
heaters, abnormal decrease instead of decrease.
Not all annunciators are identified by ALB number.
Some valves are identified by valve number only and not by noun
name.
When told to verify flow, no amount is specified; e.g. , >300 GPM.
Kickout procedure numbers were missing.
Manual valves were not checked as possible leakage paths.
The inspectors consider that the adaptation or establishment of a
writers guide would enhance the overall consistency of the procedures
and insure uniformity in future revisions to the A0Ps. Writers guides
do exist for other facility procedures; however, none appear to have
been used in the preparation of the present AOPs.
During the detailed review of A0P-001 and A0P-002, the inspectors noted
some specific problems.
A0P-001, which addresses failure of a control bank to move during
an increase or decrease in turbine load, should include stopping
the turbine ramp in the immediate actions to mitigate the
consequences of any possible transient.
A0P-001, which addresses continuous insertion of a control bank,
listed as a symptom, an annunciator (Delta Flux Warning / Status
Light) which does not exist on the licensee's control board. This
problem would have been identified if the procedure had been
adequately walked through in the control room. There is a high
flux deviation alarm located on the control board; however, it
was not included in the procedure.
A0P-002 does not include the use of the manual emergency borate
valve as a possible means of adding boric acid in either the
immediate action or the follow-up action.
During the detailed review of A0P-004, the inspectors walked through
the centrol room inaccessibility portion of the procedure and
encountered several problems.
The procedure contained no immediate action although a statement
for tripping the reactor was included in the first step.
Attempting to trip the reactor from the control board should be
identified as an immediate action and other immediate actions
should be evaluated.
.
...
.
.
21
,
Following the tripping of the reactor the procedure directed the
operator to step 3.2 which begins with several notes. 'The last
note states that procedure steps may be performed out ofl sequence
or simultaneously at the discretion of the senior contro.1 operator
(SCO). In many cases the steps in the procedure must be performed
in order and in some cases steps done o,ut of sequence could lead
to placing the plant in an unsafe condition. There are several
steps that may be completed in accordance with the note; however,
the inspectors consider that the use of this note should be
limited to those specific areas of the procedure and not utilized
as a general note.
As written, the procedure transfers control to the auxiliary
control panel (ACP) prior to verifying the reactor is, in fact,
,
tripped. The licensee infornied the inspectors that this is done
because the transfer inputs a trip to the reactor trip shunt
coils. The inspectors consider that this is relying on non-safety
related automatic features too heavily and the operators should
attempt to verify the reactor trip locally from the reactor trip
breakers or rod drive MG set breakers.
The inspectors noted
further that the same operator who transfers control also verifies
the trip of the reactor. The inspectors consider that the balance
of plant operator, identified as R0-2 in the procedure, could
verify the reactor trip prior to going to the diesel building.
A0P-004, step 3.2.29 directs the operator to cooldown the reactor
below 350F. The step offers no guidance as to how far below 350F
the plant should be cooled even though step 3.2.34 requires the
racking out of charging pump breakers prior to temperature
decreasing below 335F.
Step 3.2.30 directs the operator to
depressurize the reactor to less than 363 psig using a pressurizer
power operated relief valve.
Again no lower limit has been
established and no caution has been given as to the possibility of
reaching saturation conditions.
The use of annunciator panel procedures (APPs) and operations work
procedures (0WPs) were also reviewed during this inspection.
During
simulator excercises, the inspectors noted a reluctance on the part
of some operators to utilize the APPs to identify causes for alarms
and the action needed to resolve the problem. The operators instead
referred to the 0WPs directly. The inspectors questioned the relation-
ship between the APPs and the OWPs and were informed by the licensee
that the operator was to use the APP first and the APP would direct the
operator to the appropriate OWP. The inspectors reviewed several APPs
and discovered that there were inconsistencies in the way the APPs were
written.
Some simply referred generally to OWPs and did not identify
the specific OWP to be used.
Other APPs had no references to the
appropriate OWP for the operator to follow but simply instructed the
operator to repair the instrument.
Additionally, the APPs did not
provide reference to the appropriate Technical Specification section in
all cases.
_
_
_
_
_
_-.
_
_
-.
22
The problems noted with A0Ps, 0WPs and APPs were discussed with the
licensee's operations management who stated that they had planned for
l
the licensed operator group to perform a full review and walkdown of
all AOPs and OWPs.
Additionally the licensee stated that it was
j
planned for APPs to be reviewed for consistency, proper direction to
DWPs, and proper referencing of technical specifications by the
licensed operator group. At the exit interview, the licensee committed
to complete these reviews prior to Mode 1 operations.
Completion of
these reviews, as well as resolution of specific concerns noted by the
inspectors, is identified as an inspector followup item (400/86-76-11).
i
l
'
8.
Review Of Maintenance Procedures
This inspection supplemented the maintenance program inspection conducted
,
June 9-13, 1986, and reported in NRC inspection report 50-400/86-48. The
I
inspectors reviewed the following procedures:
CM-M0046
Limitorque Valve Actuator SMC-00 thru SMC-2 Disassembly
and Maintenance
CM-M0048
Limitorque Valve Actuator SMC-03 Disassembly and
Maintenance
CM-M0050
Limitorque Valve Actuator Size SMB-000 Disassembly and
Maintenance
CM-M0051
Limitorque Valve Actuator SB/SMB-000 Disassembly and
Maintenance
CM-M0052
Limitorque Valve Actuator SMB-0 through SMB4T and SB-0
through SB-4 Disassembly and Maintenance
CM-M0053
Limitorque Valve Actuator SMB-5 and SMB-ST Disassembly
and Maintenance
CM-M054
Valve
Actuator
HBC-0
through
HBC-10
Disassembly and Maintenarce
CM-M0055
Limitorque Valve Actuator SMC-04 Disassembly and
Maintenance,
CM-M0056
Limitorque Valve Actuator SMB-5XT Disassembly and
Maintenance
CM-IO002
Limitorque Calibration Check and Stroking
PM-M0014
Limitorque Inspection and Lubrication (Annual)
MTE-080
ITT Barton Indication Calibration
MTE-086
Trans Data Model 10PS501 Voltage Transducer
.
23
MTE-511
Outside
Micrometer
with
Interchangeable
Anvil
Calibration
J
MTE-512
Dial Caliper Calibration Check
The licensee's limitorque procedures appear to be general guidelines
for performing maintenance activities on limitorque actuators.
,
Discussions with the licensee determined that they rely heavily on the
I
skill of the craft when performing maintenance activities on limitorque
l
actuators.
The inspectors informed the licensee that they should
review the limitorque maintenance procedures to incorporate more
specific guidance and acceptance criteria and that this area would be
inspected further during review of their response to IE Bulletin 85-03.
The licensee's maintenance procedures for calibration of measuring and
test equipment were considered to be complete and easy to understand.
Plant Operating Manual, MMM-006, was referenced in the procedures for
actions to be taken when actual error was less than allowable error, in
l
which case the tool would be recertified and calibrated.
When the
equipment had an actual error exceeding the allowable error, MMM-006
l
outlined instructions for the disposition of damaged inaccurate tools.
The procedure required the calibration lab to enact a trace of all of
the calibrations that were performed by the tool, notify the personnel
who would have used the tool, and alert maintenance that any
calibrations performed with the tool were not valid. A walkthrough of
,
!
the calibration lab was conducted with lab personnel demonstrating the
traceabiitty of the equipment and the records kept on each specific
tool.
The inspector noted the overall condition of the lab to be
,
i
acceptable and that personnel were able to obtain specific records for
l
randomly selected tools with case.
Equipment logs were legible and
complete.
Personnel demonstrated to the inspector the actions that
they would take should a tool be outside the allowable error. The file
would be examined to determine which personnel had used the tool and
its identification number would be communicated to the maintenance
department.
The maintenance department would then employ their
automated maintenance management system to determine what plant
equipment was calibrated with the tool and proceed to process work
requests to have the plant equipment recalibrated.
Overall, the
inspectors found the control over the calibration of measuring and test
equipment and the procedures governing those controls to be well
established.
9.
Review Of Surveillance Test Procedures
This inspection supplemented the inspection conducted of surveillance test
procedures on July 14-18, 1986, and reported in NRC inspection report
50-400/86-57.
,
24
In NRC Inspection Report 50-400/86-57, the inspectors noted seven actions
which were considered necessary to be completed prior to NRC reinspection in
this area. These items and the status of their completion at the time of
this inspection are noted below.
a.
All procedures which implemented surveillance requirements that were
required to support operations encompassed by the license should be
approved and ready for use. This was confirmed to be approximately 95%
complete during the inspection of October 6-10, 1986. Adequate manage-
ment control was in place to assure completion of remaining procedures.
b.
Proper acceptance criteria and scaling and setpoint data should be
prescribed within surveillance test procedures and instrumentation
should be set to the proper setpoint parameters. This element was not
satisfied during the inspection of October 6-10, 1986, and was later
evaluated during the week of November 3-7,
1986, as discussed in
paragraph 10 of this report.
c.
Surveillance test procedures should be satisfactorily completed in the
field at least once without problem and following establishment of
acceptance criteria.
Where plant conditions prohibit this, the
procedure should be walked down satisfactorily without problem. This
was confirmed to be approximately 80% complete during the inspection of
October 6-10, 1986. Also adequate management control was in place to
assure completion of remaining work.
d.
The surveillance test tracking system data base should be verified by
the licensee to ensure that it is complete with respect to capturing
all surveillance requirements for all required frequencies.
This was
confirmed to be complete during the inspection of October 6-10, 1986.
e.
The licensee should adequately establish programs for condition
dependent and mode dependent surveillances. This was confirmed to be
complete during the inspection of October 6-10, 1986.
f.
The licensee should implement a formal mechanism to ensure control of
changes to preliminary and final draft Technical Specifications. This
is to ensure that the surveillance test tracking system will be up to
date at the time of licensing.
This was confirmed to be complete
during the inspection of ^1tober 6-10, 1986.
g.
The licensee's QA surveillance of surveillance testing, which was in
progress at the time of this inspection, should be completed and
documented, with all concerns satisfactorily resolved.
Based on a
review of QA surveillance report 86-217 and interviews with the
cognizant QA auditors, this was determined to be essentially complete
during the inspection of October 6-10, with one finding remaining to be
<
e-se,
ma
=c
25
~
resolved.
This finding concerned the need to adequately verify the
accuracy of source information used to revise the surveillance test
tracking system data base. Appropriate management controls appeared to
be in place to assure resolution of this item.
In order to assess the adequacy of these actior.s, the inspectors reviewed
and walked down surveillance test procedures to ascertain technical adequacy
in fulfillin; Technical Specification surveillance requirements. Portions
of the follofing procedures were reviewed:
OST 1807
Containment Spray ESF Response Time
s
OST 1812
Aux Feedwater Isolation ESF Response Time
OST 1011
Aux Feedwater Pump 1A-SA Operability Test
OST 1111
Aux Feedwater Pump IX-SAB Operability Test
OST 1119
Containment Spray Operability - Quarterly Interval
Modes 1, 2, 3, and 4
OST 1015
ESW System Operability, Monthly Interval
OST 1215
ESW System Operability, Quarterly Interval
OST 1308
Main Steam Isolation:
ESF Response Time
OST 1325
Safety Injection:
ESF Response Time, Train A,
18 month Interval
Pressurizer Heater KW Verification
OST-1216
CCW System Operability, Quarterly Interval
OST 1007
CVCS/SI System Operability, Quarterly Interval,
Mode ; 1, 2, 3, and 4
EST-301
Engineered Safety Feature Response Time Evaluation
Containment Spray Additive Tank Level Calibration
RWST Level Channel 1 Operational Test
Main Steam Line Pressure Loop 1 Set II Calibration
Pressurizer Level Set II Calibration
Steam Line Press Response Time Test for Protection
Set II Sensors
26
OST-1021
Daily Surveillance Requirements, Daily Interval, Mode 1
and 2
GP-004
Reactor Startup (Modes 3 to Mode 2)
EST-700
Core Reactivity Balance
EST-701
Shutdown Margin Calculation Mode 2
EST-720
Normalization of Boron Letdown Curve
EST-702
Moderator Temperature Coefficient E0L
EST-703
Moderator Temperature Coefficient Measurement BOL After
Each Refueling
EST-708
Monthly RCS Flow Determination
EST-710
Hot Channel Factor Tests
Reactor
Coolant
Loop 2
Flow
Instrument
( F-426)
Protection Set III Calibration
Nuclear
Instrumentation
System
Power
Range
N41
Operational Test
Nuclear
Instrumentation
System
Power
Range
N42
Operational Test
Nuclear
Instrumentation
System
Power
Range
N43
Operational Test
Calibration of Nuclear Instrumentation System Power
Range N41
Power Range N41 Detector Plateau Curve Verification
Power Range N42 Detector Plateau Curve Verification
Delta T - Tavg (T-0412) Protection Set 1 Operational
Delta T - Tavg Loop (T-0412) Calibration
EST-300
Reactor Trip Response Time Fvaluation
Group 1 of 3 Channel RTS and ESFAS Response Time Test
MST-I+'03
Steam Generator 1A Narrow Range Level Loop (L-474)
Protection Set I Calibration
27
Steam Generator Level Response Time test for Protection
Set I Sensors (LT-0484, LT-0494)
Train A Solid State Protection System Actuation Logic
and Master Relay Test
Reactor Coolant Pump (IC-SN) Undervoltage Relay
(NGV 138) Channel Calibration
Reactor Coolant Pump (IA-SN) Underfrequency Relay (KF)
Channel Calibration
OST-1067
Reactor Coolant Pump C Undervoltage and Underfrequency
Trip Actuating Device Operational Test, Quarterly,
Modes 1-2-3-4-5
MSTE-0010
1E Battery Weekly Test
MSTE-0011
1E Battery Quarterly Test
MSTE-0012
1E Battery 18 Month Test
MSTE-0048
RCP 1A-SN Current Relay (s) Calibration
MSTE-0052
Reactor Coolant Pump Breaker 1B-SN Integrated Test
OST-1023
Offsite Power Availability Verification Weekly Test
OST-1824
1BSB Emergency Diesel Generator 18 Month Operability
Test, Modes 5 and 6
OST-1826
Safety Injection Engineered Safety Features Response
Time Test - Train B
EST-722
Control Rod Position Determination Via Incore Instru-
mentation
OST-1005
Control Rod and Rod Position Indicator Exercise,
Modes 1-2, Monthly Internal
OST-1019
Reactor Coolant Pump (s) Operability Verification
Weekly Internal, Modes 3 and 4
OST-1022
Daily Surveillance Requirements, Daily Interval,
.
Modes 3 and 4
OST-1033
Daily Surveillance Requirements, Daily Interval,
Modes 5 and 6
OST-1039
Calculation of Quadrant Power Tilt Ratio, Mode 1,
Above 50% Rated Thermal Power
-
. .
_
_ _ .
_
_
_
_.
_
B
28
.
GP-001
Reactor Coolant System Fill and Vent, Mode 5
GP-002
Normal Plant Heatup From Cold Solid to Hot Subcritical
Mode 3
GP-007
Normal Plant Cooldown (Mode 3 to Mode 5)
RST-201
Boron Concentration Surveillance of the Boric Acid and
I
Refueling Water Storage Tanks
RST-204
Reactor Coolant System Chemistry and Radiochemistry
Surveillance
OST-1071
RHR Hot Leg Suction Valve Interlock Test,18 Month
Interval Test, Modes 5 and 6
Reactor Ccolant Loop 2 Hot Leg Temperature Instrument
(T-0423) Frotection Set I Calibration
Loop Calibration of Auxiliary Feedwater Flow (F-2050B)
to Steam Generator B
Accumulator Tank C Level Loop (L-0928) Calibration
Condensate Storage Tank Level Loop (L-9010A)
Calibration
Accumulator Tank C Pres:ure Loop (P-0929) Calibration
Steam Generator A Wide Range Level Loop (L-0477)
Calibration
OST-1809
Switchover To Recirculation Sumps:
ESF Response Time,
18 Month Interval, Modes 5 or 6
Additionally, the following procedures were reviewed in a less extensive
manner in order to confirm that the Technical Specification surveillance
requirements cross referenced to the procedures in the surveillance test
tracking system were in fact addressed by the procedures.
Accumulator Tank A Level Loop (L-0920) Calibration
Test
Accumulator Tank A Level Loop (L-0922) Calibration
Accumulatcr Tank B Level Loop (L-0924) Calibration
Accumulator Tank B Level Loop (L-0926) Calibration
Accumulator Tank C Level Loop (L-0930) Calibration
,
i
1
..
- ,,-
_ , , ,
_
. . , -- .
,. . . . . . _ .
.
-
29
Reactor Coolant Loop 1 Hot Leg Temperature Instrument
(T-0413) Protection Set I Calibration
.
Reactor Coolant Loop 1 Cold Leg Temperature Instrument
(T-0410) Protection Set I Calibration
Reactor Coolant Loop 2 Cold Leg Temperature Instrument
(T-0420) Protective Set II Calibration
Actuation Channel Calibration Loop (P-0445)
Pressurizer Level Loop (L-0459) Protection Set I
Calibration
Main Steam Line Pressure Loop 2 (P-0484) Protection
Set II - Channel Calibration
Steam Generator B Wide Range Level Loop (L-0487)
Calibration
Residual Heat Exchanger IB Bypass Flow Loop (F-0605 B)
Calibration
Residual Heat Exchanger IA Bypass Flow Loop (F-0605 A)
Calibration
Loop Calibration of Auxiliary Feedwater Flow (F-2050A)
Loop Calibration of Reactor Coolant System Wide Range
Pressure (P-0402) - Loop C Protection Set I
Locp Calibration of Reactor Coolant Systen. Wide Range
Pressure (P-0403) - Loop A Protection Set IV
Condensate Storage Tank Liquid Level Loop (L-90108)
Calibration
Loop (F-0122) Calibration of Charging Header Flow
Loop Calibration of Auxiliary Feedwater Turbine
Differential Pressure (PD-2180)
Auxiliary Feedwater Pump C Speed Instrumentation Loop
(SP-2180) Calibration
Boric Acid Tank Liquid Level Loop (L-0161) Calibration
1
<
-,
,y
-
.,
--
.
.---,.-,w--,-
,.
,-.
--ym
...-
- --,,, -,
-
30
OST-1029
Containment Penetration Outside Isolation Valve
Verification
OST-1069
Containment Building Penetration Inside Manual Isolation
Valve Verification
OST-1082
Air Lock Door Interlock Verification 6 Month Interval
Modes 14
OST-1028
Containment Isolation Valve Operability Post Maintenance
Interval, Modes 1-2-3-4-5-6
OST-1825
Safety Injection:
ESF Response Time, Train A, 19 Month
Interval, Modes 5-6
OST-1055
Containment Pre-entry Purge and Exhaust Valve Inservice
Inspection
>
OST-1056
Containment Ventilation Isolation Valve Inservice
Inspection Modes 1-2-3-4-5-6
OST-1079
Containment Isolation Valves, Inservice Inspection
Test, Quarterly Interval, Mode 5
OST-1106
CVCS/SI System Operability, Quarterly Interval,
Mode 4-5-6
OST-1813
Remote Shutdown System Operability 18 Month Interval,
Modes 5 and 6
4
OST-1006
Boration System Operability, Monthly Interval,
Modes 1-2-3-4-5-6
OST-1008
RHR Pump Operability Quarterly Interval, Modes 1-2-3
OST-1107
ECCS Flow Path and Piping Filled Verification, Monthly
Interval, Modes 1-2-3-4
OST-1081
Containment Visual Inspection Prior to Establishing
Containment Integrity and After Each Containment Entry
When Containment Integrity Is Established (All Modes)
RHR Pump Operability Quarterly Interval, Mode 4
OST-1803
Containment Sump Visual Inspection 18 Month Interval,
Mode 5
OST-1801
ECCS Throttle Valve, CSIP and Check Valve Verification,
18 Month Interval, Mode 6
,
_ _ , . --
_
- - - -
. -
.-
..
. -,
_
. - - -
._.
_ _ _ _ _ _ - _ _ _
31
OST-1828
ESF Response Time: Containment Ventilation Isolation
on High Radiation, 18 Month Interval, Modes 5 or 6
EST-206
ECCS Flow Balance
EST-205
RHR System Flow Test
EST-209
Type B Local Leak Rate Tests
OST-1020
Remote Shutdown Monitoring and Accident Monitoring
Instrumentation Channel Check Monthly Interval,
Modes 1-2-3
Accumulator Tank A Pressure Loop (P-0921) Calibration
Pressurizer Pressure P-0455 Protection Set I
j
Accumulator Tank A Pressure Loop (P-923) Calibration
Accumulator Tank B Pressure Loop (P-925) Calibration
Accumulator Tank B Pressure Loop (P-927) Calibration
Accumulator Tank C Pressure Loop (P-931) Calibration
OST-1027
ECCS Accumulator Valve Breaker Verification Monthly
Intervals, Mode 1-2-3
The inspector had the folicwing comments with respect to surveillance test
procedures:
Technical Specification 4.4.3.2 requires that the capacity of at least
two of the four groups of pressurizer heaters be verified by energizing
l
the heaters and measuring circuit power at least once per 92 days.
l
This surveillance requirement is satisfied by MST-E0023, Pressurizer
Heater KW Verification. Clarification is needed in that the data sheet
associated with backup Group D voltage and current readings does not
>
reflect the fact that heater group D differs from the other higher
capacity heater groups and only has one electrical cable per phase.
The data sheet has blanks entering current readings for two cables per
phase.
The licensee stated that this clarification would be
incorporated by change to the procedure.
Technical Specification 4.6.2.1.C.2 requires that each containment
spray pump be demonstrated capable of developing a differential
pressure of greater than or equal to 170 psig on an indicated
recirculation flow of at least 1500 gpm when tested pursuant to
specification 4.0.5.
However, OST-1807, Containment Spray System: ESF
Response Time 18-month Interval,
acceptance criteria specifies
2229 psig discharge pressure and OST-1119, Rev.1, Containment Spray
Operability Quarterly Interval, acceptance criteria specifies 2229 psig
_ - _ _ _ - _ _ _ _ _ _ _
_
32
and 22150 gpm respectively. The licensee stated that the inconsistency
was due to issuance of a recent Technical Specification change and that
this situation would be corrected by change to the procedures cs part
of their normal program for updatinn procedures to Technical Specifica-
tions. Resolution of this concern, as well as other technical concerns
identified in paragraph 9 of this report, is identified as an inspector
followup item (400/86-76-12).
Additionally, the inspectors noted,
while walking down OST-1119 on the associated main control room panel
that the scale for the associated flow indicators, FI-7132A and
FI-71328, did not indicate above 2000 gpm (top of scale).
The
inspectors determined from discussions with license
employees that
Rev. I to OST 1119 was part of the 20% of procedures which had not yet
been performed or field verified.
Technical Specification 4.3.2.2 requires that the Engineered Safety
Features response time for main steam line isolation on low steam line
pressure, hi containment pressure, and negative steam line pressure
rate to be demonstrated to be less than or equal to deven seconds
during performance of the specified 18 month surveillance requirement.
The acceptance criteria in OST-1808, Main Steam Isolation:
Response Time 18-Month Interval, was specified to be less than or equal
to 12 seconds.
The licensee stated that the problem was due to
issuance of a recent Technical Specification and that this situation
would be corrected as part of their normal program for updating
procedures to Technical Specifications. Resolution of this concern is
identified as a part of inspector followup item 400/86-76-12.
Technical Specification 4.3.2.2 requires that the Engineered Safety
Features response time for safety injection on main steamline pressure
to be demonstrated to be less than or equal to 12 seconds with offsite
power and less than or equal to 22 seconds without offsite power during
performance of the specified 18 month surveillance requirement.
However, the acceptance criteria in EST-301, Engineered Safety Feature
Response Time Evaluation, Safety Injection, Attachment III, page 17 of
20, was specified to be less than or equal to 27 seconds without
offsite power.
The licensee stated that the problem was due to a
typographical error which had been identified by the licensee and
corrected in a change dated October 2, 1986.
The inspectors determined that the plant curve book, which contains
reactor physics information and tank curves had not been finalized.
The curves needed for shutdown margin calculations, had with the
exception of a few curves, been completed and approved but not placed
in the plant curve book. The licensee stated at the exit meeting that
in response to the concern action had been taken such that all curves
had now been approved and the plant curve book assembled and placed in
the control room.
l
33
The following example of failure to properly implement Technical
Specification surveillance requirements was noted during the review of
procedure OST-1036, Shutdown Margin Calculation. Step 4.1 of OST-1036
cautions the operator to emergency borate if the shutdown margin is
less than 1770 pcm in Modes 3 or 4 or less than 2000 pcm in Mode 5.
Technical Specification 3.1.1.1 requires emergency boration if the
shutdown margin is less than 1770 pcm in Modes 1, 2, 3 and 4.
The
requirement for emergency boration in modes 1 and 2 had not been
included in the procedure. Resolution of this concern is identified as
a part of inspector followup item 400/86-76-12.
Step 7.1.8.d of Attachment 1 to OST-1036 requires entry of data on the
reactivity worth of shutdown or control rods known to be immovable or
untrippable.
This information was not directly available from the
plant curve book and no reference was provided for obtaining the
information. Step 7.3.1.c and d required entry of the total worth of
all control banks and shutdown banks. These steps reference control
rod worth curves that are for beginning of life hot zero power. WCAP
10781 indicates that at end of life the total control and shutdown bank
rod worth is approximately 500 pcm less than at beginning of life. The
inspectors requested that the licensee confirm that the curves utilized
were appropriate for all cases.
The inspectors also noted that
references to other paragraphs througnout OST-1036 did not include the
major paragraph number.
For example, paragraph 7.3.1.j would be
referred to as paragraph 3.1.j.
In addition, several typographical
errors were brought to the attention of the licensee.
The licensee
drafted a revision to OST-1036 prior to completion of the inspection.
The inspectors reviewed the procedure and determined that the concerns
noted above were satisfactorily addressed. With regard to control rod
worth data, the licensee intends to provide cycle dependent specific
values for the rod worth of contrel and shutdown banks. The data will
be updated prior to startup after each refueling.
This revision will
simplify the calculations made by the operator.
Resolution of this
concern is identified as a part of inspector followup item 400/
86-76-12.
With regard to surveillance test procedures associated with the reactor
trip system, the procedures reviewed appeared to be technically correct
and formatted logically.
The inspectors observed, that MST-IO186,
0187, 0188 and 0189 contained reference to overpower delta temperature
(0PDT) alarms and switches. Inputs to OPDT from the nuclear instrumec-
tation is no longer provided and therefore these references should be
deleted.
These procedures had not yet been field verified by the
licensee, and since these references had been deleted from the nuclear
instrumentation calibration procedures, the inspectors believe the
licensee would have identified the errors during field verification.
The licensee stated that the procedures would be revised to delete
these references. Resolution of this concern is identified as a part
of inspector followup item 400/86-76-12.
34
During the review of MST-E0028 and MST-E0039, which contain reactor -
coolant pump (RCP) underfrequency and undervoltage calibration
instructions, the inspector noted that references to various control
knobs, adjusting screws, contacts,
etc.,
were
not adequately
identified.
The inspectors reviewed the procedure, drawings and
vendor's manual with a member of the licensee's electrical procedure
writing group. In many cases the instrument knobs, screws and contacts
required to be adjusted or blocked could not be identified on the
drawings or in the vendor's manual by the name used in the procedure.
The licensee agreed to review these procedures for the RCP undervoltage
and underfrequency calibration and provide drawings and/or appropriate
instrument designations to readily identify the instrument controls to
be used to perform the procedures.
Resolution of this concern is
identified as a part of inspector followup item 400/86-76-12.
Inspection
Report
50-400/86-57 had
previously
identified
two
inadequacies in reactor trip system testing.
The operational test of
the turbine trip inputs to the reactor protection system required by
Technical Specification 4.3.1.17 had not been covered in the
procedure / Technical Specification cross reference list. The inspector
verified that the list had been corrected to include procedure GP-05 as
the implementing procedure.
In addition, all channel sensors for
response time testing of the Overtemperature Delta Temperature (0 TDT)
trip function had not been included in maintenance procedures
MST-IO644, 0645 and 0646. The inspector reviewed these procedures and
verified that the five channel sensors which provide input to the OTDT
trip have now been included in the procedures.
MST-E0010, step 1 of section 6.0 refers to meeting tolerances. It is
unclear as to whether tolerances as identified in the procedure, meant
ranges or allowable limits, as identified in Technical Specifications
and procedure ' data sheets. Additionally, steps 4 and 4a of the data
sheet did not provide for the allowance of Technical Specifications
that specific gravities less than 1.200 are acceptable if charging
amperage is less than 2.0 amps.
In MST-E0011 two minor deviations from Technical Specifications were
noted.
The note preceding step 7 in section 7.1 allowed the use of
individual cell temperatures if using the average cell temperature
causes any cell's individual cell voltage (ICV) to be below 2.13 VDC.
Technical Specifications do not contain this provision and allow for
the use of average cell (electrolyte) temperature only. Additionally
note 2 states that specific gravity less than 1.195 is acceptable if
charging current is less than 2.0 amps. Technical Specifications do
not allow this during the category B quarterly surveillance testing.
It is noted that Technical Specifications do allow this provision
during Category A weekly surveillance testing.
Resolution of these
concerns is identified as a part of inspector followup item
400/86-76-12.
s
35
MST-E0011 was noted to have other discrepancies which did not involve
inadequate implementation- of Technical Specification surveillance
requirement.
For example, Technical Specifications state that the
average temperature of ten cells should be greater than 70 degrees F.
The data sheet does not specify which ten should be used. The data
sheet does have eleven cells marked as pilot cells. They are used in
computing average cell temperature.
Furthermore, the allowable limit
as stated under the note, part
a., makes no mention of the word
average.
Technical Specifications state that the average corrected
specific gravity of all connected cells must be greater than 1.205.
Furthermore, Technical Specifications allows the specific gravity to be
as low as 1.195 provided it is restored to greater than 1.205 within
seven days. MST-E0011 did not provide for this allowance. Step 7 of
section 7.1 calls for measuring and recording (on the data sheet) the
ICV for each cell.
Step 7 needs to state specifically corrected ICV.
Section 7.2 refers to acceptance criteria (step 9).
The acceptance
criteria are not labeled as such.
Instead, the terms allowable limit
or allowable range are used.
It is unclear as to which of these two
terms constitute acceptance criteria.
MST-E0012 had two vague statements.
Step 1 of section 6.0 refers to
meeting tolerances. Whether this means limits or ranges is unclear.
Also, step 1.b of section 7.3 calls for measuring from the nearest
cell post....
The term nearest is unclear.
Additionally, step 1 of section 7.5 specified initial torquing values
of 120 IN-LB nominal.
If the personnel performing the torquing were
to accidentally torque the bolts to 125 IN-LB (with the belief that
this value is nominally 120 IN-LB), then the 125 IN-LB criteria
called for to be met in the presence of QA personnel would be exceeded.
It is considered that torquing to 120 IN-LB (MAX) would be better
terminology.
The text of MST-E0048 requires the test personnel to record specific
values using a specific terminology.
The data sheet space for the
particular value in question, however, is not labeled using the same
terminology.
Examples of this are found in sections 7.2.4 (step 9a)
and 7.2.5 (step 9a). Additionally, in section 7.2.3, step 17 should
precede step 16. Resolution of these concerns is identified as a part
of inspector followup item 400/86-76-12.
Step 16 of section 7.1 of MST-E0052 referred to terminal number 1.
Contrcl Wiring Program 68401, Sheet 111, does not have the terminal
labeled.
-
,
36
OST-1023 contained many typographical errors.
Additionally some
instructions were considered to be confusing. For example, step 7.2.1
calls for verifying that breaker 101 is racked in and operational.
Furthermore, this step calls for verification on Attachment I.
However, the attachment requires verification that the breaker is
closed, racked in, and operational. Step 7.3.1 had a similar problem.
Attachment I, A train, step 2 references step 7.2.1 for acceptance
criteria. Acceptance criteria was noted to be in another section of
the procedure.
Attachment I, step 1 of B train incorrectly references section 6.4 for
acceptance criteria. The reference should be section 6.5.
Step 7 of
section 6.0 appears to be redundant with steps 1 through 6.
Step 2 of
section 7.2 refers to breakers 104 and 105. Step 3 addresses breaker
105; thus step 2 should refer to breaker 104 only. The note under the
7.2 heading should be repeated under the 7.3 heading. The verification
criteria that the note provides apply to both the A and B trains.
OST-1023 appears to be unique in that it uses the term verify in a
different sense. Verify means to check the status of and/or properly
position the breaker, if necessary.
However, OST-1023 specifically
states in section 4.0 that no breakers are to be repositioned during
the conduct of this test.
Consideration should be given to use of
another word rather than verify. Resolution of concerns with OST-1023
is' identified as a part of inspector followup item 400/86-76-12.
OST-1824 had typographical errors and procedural errors. Examples are
as follows:
In the note after the heading for section 7.2,
step
should read steps.
In step 2a of section 7.3, breaker 104 should
read 124.
Also, in step 2d of section 7.3, zero and should read
zero the.
Additionally, in Attachment III, an initial block is needed after
Item lb and the reference to section 7.5.6 in item 10 should refer, to
section 7.5.5.
Step 1 of section 7.3 calls for recording a value
before calling for the parameter to be adjusted.
In section 7.6, a
procedural step is needed to install the jumper prior to performing the
actions of step 3.
Furthermore +.he note prior to step 3 should call
for an operator to be standing by the HCB to actuate breaker 125. The
references to the column number on data sheet 2 (Attachment II) were
confusing.
Resolution of concerns with OST-1824 is identified as a
part of inspector followup item 400/86-76-12.
The inspectors reviewed the applicants surveillance test tracking system by
reviewing a selected sample of approximately 200 implementing procedure as
delineated in the Technical Specification cross reference index, PG0-031,
dated October 1,
1986, and comparing these surveillance requirements to
those corresponding revised final draft Technical Specifications require-
ments.
No deficiencies were noted.
The inspectors noted that inspector
37
followup item 400/86-53-09 identified previous concerns with the completion
of a Techni al Specification surveillance schedule.
Specifically, the
schedule matdx had not yet been completed to accurately reflect the
surveillances required by Technical Specifications. Based on this review of
the surveillance test tracking system cross reference list, review of the
licensee's quality assurance surveillance report 86-217 findings and status
of resolutior in this area, inspector followup item 400/86-53-09 is
considered closed.
An inspector reviewed selected portions of completed data packages from
licensee files associated with the following surveillance procedures:
Containment Spray Additive Tank Level Calibration
RWST Level Channel 1 Operational Test
Main Steamline Pressure Loop 1 Set II Calibration
Pressurizer Level Set II Calibration
No deficiencies were noted.
An inspector reviewed EST-301, against MST-IO611 to deteroine if time
response data could be extracted from the MST procedure data sheets. The
inspector noted that the data required to be recorded on the EST procedure
data sheet was readily identifiable from the MST data sheet.
An inspector reviewed the status of action associated with inspector
followup item 400/86-57-01 concerning surveillance testing of motor operated
"
valve bypass circuitry.
The inspector noted that Technical Specification
<
4.8.4.2 had been revised to require an 18 month rather than quarterly
frequency. MST-IO267 had been revised to test actuation of contacts which
place the bypasses in effect for each valve, and EST-316 and 317 tested the
initiation circuitry.
Based on these actions, inspector followup item
400/86-57-01 is considered closed.
10. Establishment Of Acceptance Criteria In Surveillance Test Procedures
During the inspection of July 14-18, 1986, reported in NRC inspection report
50-400/86-57, the inspectors noted numerous examples where acceptance
criteria, alert values, and action range values had not been incorporated
into surveillance test procedures for equipment which is required to be
tested pursuant to ASME Code Section XI.
The licensee stated that
acceptance criteria would be established subsequent to first performance of
the surveillance test by the inservice inspection group.
The inspectors
were concerned that running the procedure to determine equipment acceptance
criteria may not necessarily be adequate unless proper engineering
evaluations of the data were performed.
The licensee informed the
inspectors that the data taken from the first run of the procedure would
receive an engineering evaluation against the systems design basis and the
preoperational test data to determine adequate acceptance criteria values.
The inspectors informed the licensee that subsequent NRC review of the
engineering evaluations to determine that adequate acceptance criteria for
..
-#
,
-
m---
38
surveillance procedures had been accomplished would be identified as
inspector
followup
item 400/86-57-02.
During
the
inspection
of
October 6-10, 1986, it was noted that many procedures still had not been
revised to include acceptance criteria. Upon request, the licensee provided
data that reflected that 37 mode 6 procedures required changes to
incorporate acceptance criteria and of these 17 required operation of
subject components to obtain the baseline data for establishing acceptance
criteria. In review of one proposed advanced change to OST-1104 which was
prescribing the stroke time test acceptance criteria for valve MS-83, the
inspectors noted that the proposed change prescribed a 13.56 second closure
time based on Section XI allowable value determination.
The inspectors
noted that this was inconsistent and nonconservative with the Technical
Specification required closure time of less than 10 seconds.
Since the
procedure had been through only the first technical review it is not known
whether or not the remainder of the licensee's review process would have
identified and resolved this deficiency.
In response to the inspectors'
,
concern, the licensee corrected this deficiency.
During the week of November 3-7,
1986, the inspectors reinspected
incorporation of acceptance criteria into selected surveillance test
'
procedures.
Additionally, the inspectors reviewed selected surveillance
requirements which were baselined using preoperational test data and
observed performance of one surveillance test.
In reviewing incorporation of acceptance criteria into procedures the
inspectors reviewed the following procedures:
OST-1057
Equipment Protection Room HVAC Inservice Inspection
Test, Quarterly Interval, Modes 1-6
OST-1104
Containment Isolation Inservice Inspection Valve Test,
Quarterly Interval, Modes 1-6
Component Cooling Water Inservice Inspection Valve Test,
18-Month Interval, Mode 6
OST-1215
Emergency Service Water System Operability
OST-1108
RHR Pump Operability, Quarterly Interval, Mode 4
OST-1131
Control Room Area HVAC System Inservice Inspection Test,
Quarterly Interval, Modes At All Times
OST-1804
RHR Remote Position Indication and Timing Test, 18-Month
Interval, Modes 5 and 6
OST-1216
Component Cooling Water System Operability (IA-SA and
IB-SB pump in service) Quarterly Interval Modes 1-4
OST-1043
Reactor Coolant System Vent Isolation Valve, Operability
Test
39
OST-1017
Pressurizer Power Operated Relief Valve Test
OST-1056
Containment Ventilation Isolation Valve Inservice
Inspection Modes 1-6
OST-1050
Fuel Handling Building Emergency Exhaust System
OST-1055
Containment Pre-entry Purge and Exhaust Valve Inservice
Inspection
OST-1077
Auxiliary Feedwater System Valve Operability Test,
Quarterly Interval
OST-1809
Switchover to Recirculation Sump:
ESF Response Time
Based on the review of this sample of procedures, the inspectors concluded
that the licensee's evaluation of baseline data and incorporation of
acceptance criteria into surveillance test procedures was being adequately
implemented.
Consequently
inspector followup item 400/86-57-02 is
considered closed. The inspectors noted that, in some cases, actual valve
stroke timing during baseline operation exceeded required acceptance
criteria (examples included containment spray sump suction and RWST suction
valves CT-102, CT-71, CT-105, and CT-26 and pre-entry purge and exhaust
valves CPB4 and CPB8). The inspectors noted that in each case the licensee
had properly identified the condition through the work request system and
appeared to be initiating appropriate actions to resolve the problems.
NRC
review of the licensee's resolution of the stroke time of valves identified
above is identified as an inspector followup item (400/86-76-13).
The inspectors requested information regarding which Technical Specification
surveillance requirements were to be baselined using preoperational test
data rather than data from performance of the surveillance test procedure.
The licensee identified 28 surveillance test procedures for which
preoperational test data would be used to baseline the Technical
Specification surveillance requirement. Affected activities included ASME
hydrostatic testing, code safety valve testing, integrated and local leak
rate testing, reactor trip and engineered safety features response time
evaluations, seismic monitori.ig instrumentation calibration, containment
spray nozzle and additive tank flow testing, motor operated valve overload
bypass testing, reactor coolant pump fly wheel integrity testing, and RHR
flow testing.
The inspectors reviewed one engineered safety features
response time test evaluation procedure and the RHR flow test procedure to
ascertain if the test results and methodology were consistent and compatible
with the corresponding surveillance test procedures and Technical Specifica-
tion surveillance requirements. One problem was noted with the RHR flow
.
test procedure. Technical Specification surveillance requirement 4.5.1.h.2
requires that, following modifications that can affect flow characteristics,
a flow balance: test be performed during shutoown that verifies, with one
RHR pump running, that the sum on injecticn line flow rates is a minimum of
3663 gallons per minutes. The licensee had developed EST 205 to implement
this surveillance requirement.
This procedure measured flow rate while
j
40
circulating reactor coolant from hot leg to cold leg, as would be expected
during shutdown conditions.
Rather than perform EST-205 to baseline the
surveillance requirement, the licensee credited performance of preopera-
tional test procedure 1-2085-P-03 for initial accomplishment of this
surveillance requirement.
A review of preoperational test procedure
,
1-2085-P-03 reflected that the test was performed by drawing suction from
the RWST and discharging into an empty reactor vessel. The inspectors noted
that flow would be more restricted using the surveillance test procedure,
EST-205, and consequently considered that preoperational test procedure
1-2085-P-03 was not equivalent to the surveillance test procedure. During
the exit interview the licensee committed to perform the RHR flow test in
accordance with EST-205.
Pending review of the results of this test, this
concern is identified as an unresolved item (400/86-76-14). The inspectors
expressed concern that this example of nonequivalency of test methodology
could have generic implications and questioned, generally, the evaluations
that are accomplished by the licensee to credit surveillance requirement
accomplishment with preoperational test data. The licensee committed at the
exit interview to reevaluate all surveillance requirements which are to
be baselined with preoperational test data to confirm the equivalency of
test methodology and acceptance criteria between the surveillance test
procedures and preoperational test procedures.
Completion of this action
is identified as an inspector followup item (400/86-76-15).
During review of EST-205 and preoperational test procedure 1-2085-P-03, the
inspectors noted that EST-205 did not provide for temperature compensation
of indicated flow and yet the preoperational test procedure did.
When
questioned on this observation, the licensee stated that the flow element is
calibrated to a specific temperature (approximately 300 F in this case) and
if water temperature varies from this value it is necessary to temperature
compensate indicated flow in order to establish an accurate actual flow
rate. The licensee stated that EST-205 would be revised to assure accuracy
of actual flow rates.
In discussion with the licensee it was noted OST-1108
uses the same flow element as used in EST-205 and again flow is not
temperature compensated.
In the case of this test the RHR pumps draw
suction from the RWST and recirculate ambient RWST water back to the RWST.
Flow is established at greater than 3663 gallons per minute and pump
differential pressure is required to be a minimum of 100 psid. With water
temperature of approximately 80 F actual flow would be less than indicated
flow by approximately 230 gallons per minute.
Review of baseline data run
on October 22, 1986 for the RHR pumps reflected that indicated flow was 3750
gallons per minute for pump A and 3720 gallons per minute for pump B.
In
each case actual flow was less than the minimum flow required by Technical
,
Specifications for test performance. Additionally the measured differential
pressure at this flow was 115 psid for pump A and 103 psid for pump B,
indicating a potential for pump B to be outside test acceptance criteria if
run at the proper flow rate. The inspectcrs questioned the validity of this
test data to demonstrate operability of the RHR pumps.
In response to this
concern the licensee committed to rerun OST-1108 for RHR pumps A and 8 at
the required actual flow rate and, if necessary, with increased instrument
accuracy.
Pending review of the results of this retest, this item is
identified as an unresolved item (400/86-76-16).
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41
The inspectors observed the operability test of the 1A-SA emergency diesel
generator (EDG) using OST-1085. The procedure required the EDG to achieve
rated speed, frequency, and voltage within ten seconds from EDG starting, be
loaded to 6200-6400 KW electrically, and complete a loaded run of 60
minutes. During the first attempt to collect this data a spike was received
on the frequency meter in the control room. This spike caused the operator
who was timing frequency from that meter to record an erroneous time. This
required CST-1085 to be rerun, requiring the EDG to be secured and
restarted.
The inspectors observed that there were no clear provisions
addressed in OST-1085 to allow for a restart which caused confusion of the
part of the operators participating in the test as to the best course of
action.
It was unclear to the inspectors that a carefully thought out
course of action was identified prior to the securing of the 1A-SA EDG and
no written direction was, in-fact, followed.
During securing of the EDG,
the following observations were made by the inspectors:
a.
The EDG test, OST-1085, did contain steps for the securing of the EDG
upon completion of the operability test; however, these steps were not
consulted during the actual shutdown of the EDG.
b.
The EDG was secured without first checking that cylinder exhaust
temperatures were below 500 F as required by step 30 of OST-1085. The
inspectors note that the EDG has not been loaded when the decision to
secure it was reached. One of the NRC inspectors had observed that the
highest EDG cylinder exhaust temperate
was 446 F.
This parameter,
however, was not verified t,y licensee
annel.
c.
There was confusion as to whether the normal start /stop switch in the
control room could be used to secure the EDG.
d.
Personnel unsuccessfully attempted to reset ECCS valves which had
realigned during the test initiation. This was attempted prior to the
resetting of the safeguards slave relay which prevented the valves from
being repositioned.
Completion of steps 7.2.m and 7.2.n would have
corrected this difficulty and allowed for the valve repositioning.
e.
Various plant personnel not associated with the running of OST-1085
were in the EDG local control room.
This coupled with the fact that
these personnel were opening and closing the panels in the room added
confusion to the atmosphere of the test and could contribute to
problems due to interference if such a practice continues.
'
f.
The operators encountered several mechanical and electrical problems
that were documented but not common knowledge to the operators.
Uncovering these discrepancies while conducting the test produced
delays and confusion which could have been avoided.
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42
The inspectors consider that many of the problems encountered in the running
of OST-1085 are the result of the licensee undergoing the~ transition from a
construction / testing mode to an operating mode.
However, failure of the
operators to complete required actions during the shutdown of the EDG could
have serious consequences.
The failure to check the required operating
parameters prior to securing the EDG is considered a violation for failure
to follow procedure (400/86-76-17).
11.
Review Of Administrative Procedures And Activities Associated With Control
Room Operation And Procedure Review Process
a.
l.og Maintenance
The inspectors reviewed various control room logs for shift activities
and the administrative controls associated with these logs.
The
following control room logs were reviewed:
'
(1) Control Operator Log
(2) Shift Foreman Log
(3) Clearance Log
(4) Temporary Jumper Log
(5) Equipment Inoperable Log
(6) Caution Tag Log
(7) Key Control Log
4
(8) Night Order Log
The licensee has provided administrative controls for the maintenance
of the above logs which describe the method of logging information,
content of entries and required reviews of log documentation.
The
inspectors' review of control room logs indicate that required logs are
being maintained in accordance with administrative procedures.
During the review of the key control log, the inspectors noted that
missing sign-ins and entry errors were lined through with no initials
or notes of explanation. A review of OMM-001, Conduct of Operations,
section 5.1.16, revealed that the administrative controls provided for
key control and the maintenance of the key control log do not specify
the proper method of correcting log discrepancies.
The inspector
considers that the adequate control of key logging requires a
documented method of discrepancy resolution.
During interviews with the shift foreman concerning key control, the
inspector also noted that the shift foreman was unaware that a master
key for locked high radiation areas is available in the key cuntrol
cabinet for emergency use only as specified in OMM-001, step 5.1.16.5.
The licensee should ensure that this knowledge deficiency is not a
generic problem.
i
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)
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-- .
. -.
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43
b.
Operations Staffing and Responsibilities
Procedure '0MM-001, Conduct of Operations, specifies the requirements
for shift complement, the function and responsibility of the operations
staff, and overtime scheduling restrictions.
Whenever fuel is . loaded in the reactor vessel, the minimum shift crew
will be comprised of operations' personnel in accordance with the
following table:
Operating Status
Minimum Shift Crew
Operating *
1 SF
1 SRO-
2 R0
4 A0
1 STA
Shut Down
1 SF
1 R0
1 A0
Shift Foreman with a senior reactor operator's license
SF
-
SR0 -
licensed senior reactor operator
-
licensed reactor operator
-
-
auxiliary operator
- Modes 1 through 4
The required placement of operations staff and operations staff
complements as specified in OMM-001 meet or exceed the minimum
requirements of Technical Specifications and regulatory guidance.
The licensee's administrative restrictions on overtime also meet
technical
specification requirements.
Excluding recent training
problems, the licensee has provided adequate operating personnel to
preclude the routine use of overtime.
OMM-01 specifies the following
overtime restrictions:
. _ .
._
_ _ ______ _____ _______ ________________ _
%
44
l
(1) An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />
straight (excluding shift turnover time).
(2) An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />
l
!
in any 24-hour period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour
period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven day period, all
excluding shift turnover time. (Due to the unique shift rotation
schedule, STAS will be allowed to work a maximum of 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> in
any seven day period, excluding shift turnover time.)
(3) A break of at least eight hours should be allowed between work
periods, including shift turnover time.
(4) Except during extended shutdown periods, the use of overtime
,
should be considered on an individual basis and not for the entire
1
'
l
staff on shift.
1
(5)
If circumstances arise requiring deviation from the above
j
guidelines, such deviation shall be authorized and documented by
the Plant General Manager.
Operations staff functions and responsibilities are clearly delineated
in administrative procedures.
During the review of shift for m n
responsibilities the inspector noted that the shift foreman appeared to
have been inundated by maintenance control responsibilities.
Lessons Learned Task Force Short Term Recommendations (Section 2.2.1.a)
provided regulatory guidance that the administrative functions that
detract from or are subordinate to the management responsibility of the
shift supervisor for assuring the safe operation of the plant shall be
delegated to other operations personnel not on duty in the control
room.
The licensee plans to provide a second shift foreman on day shifts and
a senior clerk on each shift to alleviate excessive administrative
duties of the shift foreman on duty.
c.
Shift Turnover
i
Procedure OMM-022, Shift Turnover Package, is used to verify the
availability of LCO equipment and the provide guidelines to ensure
adequate shift turnover. OMM-002 provides turnover checklists for the
positions of Shift Foreman, Senior Control Room Operator and Control
Room Operator.
Administrative controls for shift turnover of the
Auxiliary Operator and Shift Technical Advisor positions were not
identified by the inspectors. The inspector consider that administra-
tive controls for the shift turnover of these positions should be
established to ensure that oncoming personnel are made aware of plant
status under their purview.
I
E
45
The inspectors observed a shift turnover of the control room operator
and shift foreman positions. The turnover was conducted in a thorough
and professional manner with adequate attention to critical details.
A review of the minimum equipment list (MEL) used to verify the
alignment and operability of critical plant components during shift
turnover indicates that the MEL does not fully meet regulatory guidance
in this area.
NRR Lessons Learned Task Force Short Term Recommenda-
tions (Section 2.2.1.c.) states that the plant procedure for shift and
relief turnover shall provide assurance of the availability and proper
alignment of all systems essential to the prevention and mitigation of
operational transients and accidents by a check of the control console
(what to check and criteria for acceptable status shall be included in
a checklist).
The MEL provides a general listing of technical
specification required equipment and does not ensure the proper
alignment of all systems essential to the prevention and mitigation of
operational transients and accidents pursuant to the above regulatory
guidance. The licensee stated that an evaluation of shift turnover
controls would be performed to determine and resolve apparent
inadequacies.
Resolution of this concern will be identified as
inspector followup item (400/86-76-18).
d.
Control Room Conduct and Access
Requirements and responsibilities regarding control room conduct and
access are specified in procedure OMM-001, Conduct of Operations. A
review of these activities indicates that the licensee has disallowed
distracting activities in the control room, maintained professional
atmosphere in the control room conducive to licensed control room
operator activities and established access control for personnel other
than the shift complement such that control room traffic does not
impact plant operation,
e.
Control Room References, Drawings and Procedures
OMf1-001, Conduct of Operations, provides administrative controls for
the maintenance of control room references.
A specific reference
information list has been established to delineate required reference
materials as follows:
(1) Operating Manual
(2) Final Safety Analysis Report
(3) Selected Tech Manuals
(4) Technical Specifications
(5)
10 CFRs
(6) Selected Prints
(7) Emergency Plan
(8) Setpoints Document
(9) Steam Tables
(10) Curve Book
46
A review of selected control room copies of the above references,
including plant drawings indicates that the current revisions were
available in the control room.
f.
Plant Configuration Control
,
The inspectors reviewed the licensees administrative provisions for the
control of plant equipment and system configurations. The following
procedures were reviewed:
AP-020
Clearance Procedure
AP-021
Caution Tag Procedure
AP-024
Temporary Bypass, Jumper and Wire Removal Control
PLP-702
Independent Verification
OMM-002
Equipment Inoperability Record
OMM-005
Operations Work Procedures
OMM-011
Control of Locked Valves
Though somewhat cumbersome to use, the licensee's overall program for
configuration control appears to be adequate to ensure that operations
can determine the status of equipment and systems and that abnormal
aligrment and equipment out-of-service are documented and controlled.
The inspectors reviewed selected items under configuration control to
determine if they were adequately incorporated into the licensee's
configuration control program. No major discrepancies were identified,
however, the inspectors noted discrepancies on the tagout sheets
themselves.
Each tagout sheet has a section for a Technical
Specification evaluation relating to the equipment or systems being
tagged out. This section is to be filled out and signed by the Shift
Foreman.
On several occasions the section was simply marked not
applicable and in one example not filled in at all. The licensee, when
informed of this deficiency, showed the inspectors Night Order 49 which
addressed the problem. The licensee also informed the inspectors that
,
all Shift Foreman will be further instructed in proper completion of
the tagout sheets. The inspectors consider that this action on the
part of the licensee will effectively address and correct this problem.
The inspectors noted that the requirement for independent verification
primarily included only equipment and systems addressed in the facility
Technical Specifications.
NUREG 0737, item I.C.6, includes equipment
important to safety in the requirements for independent verification.
The inspector consider that the licensee should evaluate this larger
subset of equipment and systems for inclusions in the independent
verification program. Resolution of this concern is identified as a
part of inspector followup item 400/86-76-10.
.
.
.
_
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47
g.
Procedure Review Process
The inspectors reviewed the following administrative procedures
associated with procedure preparation, review, and approval:
.
AP-005
Procedure Format and Preparation
'
AP-006
Procedure Review and Approval
AP-007
Temporary and Advanced Changes to Plant Procedures
AP-011
Safety Reviews
AP-014.
Criteria for Qualified Safety Reviewers
Additionally, the inspectors reviewed qualifications of selected
-procedure reviewers and reviewed comments and review checklists
associated with selected procedures.
The inspectors made the following observations:
Numerous examples were observed where one individual fulfilled the
role of procedure preparer, first technical reviewer and first
safety evaluator, and a second individual fulfilled the role of
second technical reviewer and second safety evaluator. Although
4
this specific practice is not explicitly addressed in either
administrative procedures or Technical Specifications, it appears
to be in compliance with the licensee's procedures and Technical
Specifications for technical reviews and safety evaluation review.
Technical Specification 6.5.1.2 requires that technical reviewers
'
be qualified and certified.
The licensee was not able to
demonstrate that qualification criteria had been established for
technical reviewers nor was the licensee able to formally identify
qualified
technical
reviewers.
Additionally,
Technical
i
Specification 6.5.1.3 and AP-014 state in part, that safety
reviewers have a baccalaureate degree or equivalent and two years
of experience.
AP-014 further defined the equivalency of the
degree to be four years of related experience. In discussion with
licensee staff personnel it was noted that for nondegreed
personnel qualified as safety evaluators the licensee considered
that the four years equivalency experience could include the two
years experience specified by the Technical Specifications and
consequently only four years total experience was considered
adequate rather than six years. The inspectors consider that this
,
practice is contrary to the proposed Technical Specifications. A
review of 16 resumes of qualified sr.fety reviewers did not reflect
'
any cases where personnel would not meet Technical Specification
j
requirements.
The licensee acknowledged the inspectors' concerns
3 .
in these areas and stated that procedure changes would be prepared
i
I
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. - . , . _ ,
7,_,,.3+
-
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. - , . - , - .
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,y,.
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,.#,,
,,-
- ,
48
-
to clarify actual requirements. In the case of safety reviewers,
ensee committed to complete a review to assure all current-
tk
ly a
- ified safety reviewers met proposed Technical Specification
requirements. Individuals found in noncompliance would have their
qualifications revoked.
Resolution of these concerns associated
with technical and safety evaluation reviewers is identified as
an inspector followup item (400/86-76-19).
During evaluation of checklists associated with review of
=
documents, the licensee presented the nuclear safety review
checklist for OP-137, Auxiliary Feedwater System, as an example
where a safety review properly identified a potential unreviewed
safety question for further Plant Nuclear Safety Committee (PNSC)
evaluation.
The specific concern raised by the safety reviewer
was that OP-137 did not provide for AFW system venting as required
by FSAR section 10.4 and that vents were not installed in the AFW
system as required by the FSAR. The purpose of the vents and
venting evolution was to minimize water hammer problems with the
i
system.
In order to followup on how the PNSC had dispositioned
this item, the inspectors reviewed PNSC minutes 86-12 for a PNSC
meeting dated September 5,1986 which delineated the results of
PNSC evaluation of this item. The PNSC minutes had dispositioned
this item as not constituting an unreviewed safety question and
recommended acceptance as is based on no experience with water
hammer in the system, existence of an extra checkvalve in the AFW
line to the steam generators, and existence of temperature
indication and alarms to indicate backleakage. The minutes also
noted that vents were to be added as a plant modification. The
inspectors had the following concerns with this disposition:
-
The licensee's basis for concluding that an unreviewed safety
question did not exist was inadequate in that there were no
extra checkvalves between the hot pressurized feedwater
bypass line and the ambient AFW system; there was only a
single check valve. Additionally, the temperature indicators
referenced in the PNSC minutes monitored for back leakage
from the steam generator to the main feedwater bypass line
and not the main feedwater bypass line to the AFW system.
Consequently monitoring for water hammer conditions as a
result of backleakage in the AFW system was not being
accomplished.
Finally the licensee did not have sufficient
hot operating experience to consider lack of water hammer
problems to date as a basis.
-
With regard to the notation that vents were to be added as a
plant modification,
the inspectors noted
that
plant
modification request, PCR-259, had been issued to install
high point vents in the AFW system; however, this was not
prioritized as a startup or mode related item nor was it
being tracked through the licensee's commitment or mode list
programs. Consequently, there was no assurance that the item
would be completed prior to Mode 4 operations.
m
f
49
During the course of evaluating this concern, the inspectors noted
that the licensee's onsite nuclear safety (ONS) group had also
addressed this same concern when plant staff had initially tried
to resolve the incongruency between A0P-137 and FSAR section 10.4
by proposing deletion of venting requirements from the FSAR. ONS
recommended that the proposed FSAR change be deleted and issued a
memorandum dated June 25, 1986, recommending that suitable high
point vents be installed in the six AFW discharge lines. ONS had
classified this item as a Category A (nuclear safety related)
recommendation and was tracking resolution of this item as a prior
to initial criticality open item. This memorandum resulted in the
plant issuing a plant change request, PCR-259, to install AFW high
point vents; however, as previously stated, this was not
adequately prioritized or scheduled by plant management.
The
inspectors consider that the ONS involvement with this item would
have eventually assured completion of the modification prior to
power operation and, if properly implemented, the licensee's
configuration control program should have assured that procedures
would be upgraded to reflect proper backleakage monitoring and
venting requirements.
The inspectors still considered that the
dispositioning of the potential unreviewed safety question was
inadequate and that plant management had not established proper
control to assure completion of the modification prior to the mode
requiring system operation.
Following discussion of these
concerns with licensee management, the licensee committed to the
following actions:
-
The licensee would review previous PNSC minutes to assure
similar occurrences have not occurred.
-
The licensee would complete PCR-259 prior to Mode 4 and
identify this as a mandatory work item through commitment and
Mode List programs. Procedure changes concerning venting and
checkvalve backleakage would be issued commensurate with the
modification.
The licensee would take actions to upgrade the formality of
-
handling and documenting of PNSC reviews of potential
unreviewed safety questions.
-
The licensee would review other safety systems to determine
if vent valve modifications would be required prior to
Mode 4.
Completion of these commitments was identified as an inspector
followup item (400/86-76-20).
_ _ - _ _ - - -
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_
50
During the inspection of October 6-10, 1986, the licensee provided
the inspector with a memorandum dated October 9,
1986, which
concluded that no similar occurrences existed with regard to PNSC
review of potential unieviewed safety questions and which
delineated corrective actions for the remaining conmitments. The
inspectors consider that proper implesentation of those corrective
actions should resolve the concerns identified in inspector
followup item 400/86-76-20 and will review implementation at a
later date.
12.
Review of Technical Specifications
The inspectors reviewed the licensee's program for developing and reviewing
,
Technical Specifications and resolving comments associated with these
!
reviews. The inspectors considered that this program was well controlled
l
to assure proper identification and resolution of deficiencies.
An evalua-
tion of licensee review comments reflected that reviews were conducted by
I
[
licensed operator candidates and that some meaningful technical comments
were provided by these personnel.
The licensee was not performing a final
certification review since they considered the developmental reviews to be
adequate in assuring accuracy of Technical Specifications. Final certifica-
tions letters from the vendors associated with technical specification
development were obtained by the licensee.
The inspectors reviewed selected portions of Technical Specifications
i
associated with the 7 systems identified in paragraph 7 of this report
I
to confirm gereral conformance of the as configured plant to Technical
Specifications.
No deficiencies were noted.
l
The inspectors reviewed selected Technical Specification surveillance
j
requirements associated with the surveillance test procedures reviewed in
NRC inspection report 50-400/86-57 and paragraph 9 of this report.
One
significant problem was identified with motor operated valve overload
bypass testing which was previously identified as inspector followup item
400/86-57-01, and confirmed to be corrected during this inspection.
l
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