ML20215A982
| ML20215A982 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 06/04/1987 |
| From: | Branch M, Brooks C, Carroll R, Harmon P, Jenison K, David Loveless, Mccoy F, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), NRC OFFICE OF SPECIAL PROJECTS |
| To: | |
| Shared Package | |
| ML20215A952 | List: |
| References | |
| 50-327-87-24, 50-328-87-24, IEB-79-22, IEC-79-06, IEC-79-07, IEC-79-6, IEC-79-7, NUDOCS 8706170171 | |
| Download: ML20215A982 (19) | |
See also: IR 05000327/1987024
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STRE ET, N.W,'
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ATLANTA, G EORGI A 30323
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/ Report Nos.:
50-327/87-24 and 50-328/87-24
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Licensee:
Tennessee Valley Authority
500A Chestnut Street-
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Chattanooga, TN -37401
Docket Nos.:
50-327 and 50-328
License Nos.: DPR-77 and'DpR-79
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Facility Name:
Seq'uoyah. Units 1 and 2
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Inspection Conducted: April 6, 1987 thru May 5, 1987
Inspectors: WY$
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K.M.Jenison,seniorRfdeynspe'ctor
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P.E.Harmon, Resident [sppo'r -
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Date Signed
M. W. BrancTi, startup Coo [k
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R. E. Carrol' , Project Engheer
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Approved by:
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F. R.'McCoy, Chief TVA Proieg s( Section 1
Dsti Sighed
Office of Special Projects
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SUMMARY
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Scope: This routine, announced inspection involved inspection onsite by the
Resident Inspectors in the areas of:
operational safety verification
(including operations performance, system lineups, radiation protection,
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= safeguards and housekeeping inspections); review of previous inspection
findings; followup of events; review of licensee identified items; review of IE
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Information Notices; and review of inspector followup items. This inspection
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also involved special review of drawing control, the operability look back
B706170173 870604
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ADOCK 05000327
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. program, : recent .. reactor coolant spill- events, and the new employee concern
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program.
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- Results: One violation'was identified:
327, 328/87-24-03, Failure to notify the NRC of the April '29,1987 ' reactor
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coolant system spill event, paragraph 10.
-ThreeLunresolved' items were identified:
.327,328/87-24-01, Adequacy of primary and critical- drawing lists,
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paragraph 14.
327,328/87-24-02, Control of temporary changes to drawings,
paragraph 14.
327, 328/87-24-04, Inadequacies in procedures and procedural implementa-
tion, causing concerns over control in the areas of system and
equipment status, procedural changes,-and testing, paragraph 10.
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REPORT DETAILS
1.
Licensee Employees Contacted
H. L. Abercrombie, Site Director
J. T. La Point, Deputy Site Director
- L. M. Nobles, Plant Manager
- B. Willis, Operations and Engineering Superintendent
- B. M. Patterson, Maintenance Superintendent
R. J. Prince, Radiological Control Superintendent
M. R. Harding, Licensing Group Manager
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L. E. Martin, Site Quality Manager
D. W. Wilson, Project Engineer
R. W. Olson, Modifications Branch Manager-
J. M.' Anthony, Operations Group Supervisor
- R. V. Pierce, Mechanical Maintenance Supervisor
M. A. Scarzinski, Electrical Maintenance Supervisor
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- H. D. Elkins, Instrument Maintenance Group Manager
J. T. Crittenden, Public Safety Service Chief
- R. W. Fortenberry, Technical Support Supervisor
- G. B. Kirk, Compliance Supervisor
- J. H. Sullivan, Regulatory Engineering Supervisor
- J. L. Hamilton, Quality Engineering Manager
- H. R. Rogers, Plant Operations Review Staff
- R. H. Buchholz,.Sequoyah Site Representative
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- M. A. Cooper, Compliance Licensing Engineer .
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- A. M. Qualls, Plant Manager Bellefonte
- T. M. Galbreath, Employee Concerns Program Supervisor
- T. A. F11ppo, Quality Surveillance Supervisor
- T. L. Howard, Quality Assurance Manager
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- E. K. Sliger, Manager, Employee Concerns Program
- J. E. Boyles, Employee Concerns Program
- W. R. Simonds, Employee Concerns Program
- G. R. Mark, Employee Concerns Program
- J. E. Maddox, Project Administration Supervisor
Other licensee employees contacted included technicians, operators, shift
engineers, security force members, engineers and maintenance personnel.
- Attended exit interview.
2.
Exit Interviews
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The inspection scope and findings (including those discussed during the
April 24, 1987 drawing control exit and the May 1,1987 operability look
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back exit) were summarized with the Plant Manager and members of his staff
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on May 5, 1987. No violations or deviations were discussed at this exit.
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The licensee acknowledged the two unresolved items in the drawing control
area.
A supplemental exit was held on May 29, 1987, to discuss recent reactor
coolant spills identified in paragraph 10 and associated Violation
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327,328/87-24-03 and Unresolved Item 327,328/87-24-04. The licensee was
not in full agreement with the findings as presented at this supplemental
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exit. The NRC was represented by the Section Chief for the Sequoyah site
and the Senior Resident Inspector. The licensee was represented by Deputy
Site Director, Plant Manager and Site Licensing Manager among others who
made the following paraphrased comments:
1.
The use of 10 CFR 50.72.b.21 in Violation 327,328/87-24-03 is con-
sidered by the licensee to be a. misapplication.
2.
The licensee was not given sufficient notice prior to this supple-
mental exit to ensure that the appropriate licensee personnel could
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attend this meeting and/or properly brief Sequoyah management. The
NRC acknowledged this comment, however, because of the importance of
these events coupled with other recent events it was necessary to
conduct the exit on an impromptu basis in order to ensure that there
was proper communication between the NRC and the licensee at the
appropriate level of management.
The licensee did not identify as proprietary any of the material reviewed
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by the inspectors during this inspection.
During the reporting period,
frequent discussions were held with the Site Director, Plant Manager, and
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other managers concerning inspection findings.
Inspection findings
concerning drawing control and the operability look back review program
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are presented in paragraphs 14 and 15, respectively.
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3.
Licensee Action on Previous Inspection Findings (92702)
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(Closed) Violation 328/84-21-01, Failure to have adequate procedures for
air compressor maintenance. This item was reviewed in Inspection Report
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84-35 during the closure of Violation 327/84-20-01. Based on this review
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Violation 328/84-21-01 is closed.
4,
Unresolved Items
Unresolved items are matters about which more information is required to
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determine whether they are acceptable or may involve violations or devia-
tions. Three unresolved items were identified during this inspection, and
are identified in paragraphs 10 and 14.
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5.
Operational Safety Verification (71707)
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a,
plant Tours
The inspectors observed control room operations, reviewed applicable
logs, conducted discussions with control room operators, observed
shift turnovers, and confirmed operability of instrumentation.
The
inspectors verified the operability of selected emergency systems,
and verified compliance with Technical Specification (TS) Limiting
Conditions for Operation (LCO).
The inspectors verified that main-
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tenance work orders had been submitted as required and that followup
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activities and prioritization of work was accomplished by the
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licensee.
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Tours of the diesel generator, auxiliary, control, and turbine
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buildings, and containment were conducted to observe plant equipment
conditions, including potential fire hazards, fluid leaks, excessive
vibrations, and plant housekeeping / cleanliness conditions,
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No violations or deviations were identified.
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b.
Safeguards Inspection
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In the course of the monthly activities, the inspectors included a-
review of the licensee's physical security program. The performance
of various shifts of the security force was observed in the conduct
of daily activities including protected and vital area access
controls; searching of _ personnel and package's; badge issuance and
retrieval; patrols and compensatory posts; and escorting of visitors.
In addition, the inspectors observed protected area lighting, protec-
ted and vital areas barrier integrity.
The inspectors verified an
interface between the security organization and operations or main-
tenance.
Specifically, the resident inspectors inspected security
during outages, reviewed licensee security event reports, and
verified protection of safeguards information.
No violations or deviations were identified.
c.
Radiation Protection
The inspectors observed health physics (HP) practices and verified
implementation of radiation protection control. On a regular basis,
radiation work permits (RWPs) were reviewed and specific work
activities were monitored to ensure the activities were being con-
ducted in accordance with applicable RWPs.
Selected radiation
protection instruments were verified operable and calibration
frequencies were reviewed.
No violations or deviations were identified.
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6.
Engineered Safety Features Walkdown (71710)
Module 71710 wts not performed during this inspection period as a result
of the augmented inspection program being implemented.
7.
Monthly Surveillance Observations (61726)
The inspectors observed / reviewed TS required surveillance testing and
verified that testing was performed in accordance with adequate
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procedures; that test instrumentation was calibrated; that LCOs were met;
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that test results met acceptance criteria requirements and were reviewed
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by personnel other than the individual directing the test; that
deficiencies were identified, as appropriate, and that any deficiencies
identified during the testing were properly reviewed and resolved by
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management- personnel; and that system restoration was . adequate.
For
complete tests, .the inspector verified that testing frequencies were met
and tests.were performed by qualified' individuals.
The ' resident and .0ffice of Special Programs inspectors are currently
reviewing post-modification and post-maintenance functional testing on
site. This review includes preparation, performance, procedures, review,
and' paperwork involved with functional testing. Testing observations will
continue throughout the month of May.
Summaries of testing observed and
additional comments will appear.in inspection report 327, 328/87-28.
8.
Monthly' Maintenance Observations'(62703)
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a.
Station maintenance activities of safety-related systems and com-
ponents were observed / reviewed to ascertain that they were conducted
in accordance with approved procedures, regulatory guides, industry
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codes and standards, and in conformance with TS.
The following itens were considered as ancillary issues to an
extended functional testing inspection which is ' described in
paragraph 7 of this report:
LCOs were met while components or
systems were removed from service; redundant components were
operable; approvals ' were obtained- prior to initiating the work;
activities were accomplished using approved procedures and were
inspected as. applicable; procedures used were adequate to control'the
activity; troubleshooting activities. were controlled and the repair -
record accurately reflected what actually took place; functional
testing and/or calibrations were performed prior to returning
components or systems to service; quality control records were
maintained; activities were accomplished by qualified personnel;
parts and materials used were properly certified; radiological
controls were implemented; QC ' hold -points were established where
required and were
observed;
fire
prevention . controls were
implemented; outside contractor force activities were controlled in
accordance with the approved Quality Assurance ' (QA) program; and
housekeeping was actively pursued. The following work request (WR),
work plan (WP) and preventive' maintenance (PM) procedures were
reviewed.
WR B233555, Check out diesel generator setups with vendor
WP 1285-8721, UHI level switch modification
PM 1897-087, UHI accumulator isolation valve low level activation
level switches
PM 756-410, Door interlock system
No violations or deviations were identified.
9.
Licensee Event Report (LER) Followup (92700)
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The following LERs were reviewed and closed. The inspector verified that:
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reporting requirement.
ad been met; causes had been identified; correc-
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tive actions appeared appropriate; generic applicability had been
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considered; the LER forms were complete; the licensee had reviewed the
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event; no unreviewed safety questions were involved; and no violations of
regulations or Technical Specification conditions had been identified.
LERs Unit 1
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327/84-54, Reactor . trip due to loss of relay rack 1-R-15.
The licensee
determined that the initiating trip signal resulted from relay rack 1-R-15
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breaker tripping which resulted in the closure of steam generator (SG) #1
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main feedwater regulating valve and a reactor trip from flow mismatch in
conjunction with low SG 1evel.
The licensee's corrective actions appear
to be acceptable.
327/86-26, Standby diesel generator start when sudden pressure relay
failed on common station service transformer (CSST) D.
Due to the loss of
CSST D and the resulting undervoltage condition sensed on the shutdown
boards, all four standby diesel generators received a start signal. Power
was returned to the shutdown boards prior to the diesels loading onto the
boards. The licensee's corrective actions appear to be acceptable.
10. Event Followup (93702, 62703)
During the inspection period, an investigation was conducted of three
separate events that have occurred at Sequoyah.
Eaca of the events
involve the leakage of primary coolant from the Reactor Coolant System
(RCS).
Each of these events was investigated in depth by two separate
review committees appointed by the licensee. The on-site review committee
was appointed by the site director and consisted of inter-disciplinary
members that were headed by the supervisor of the plant operations review
staff (PORS). The resultant report by that group is referred to as the
PORS report.
A second, independent review group was appointed by the
Manager of Nuclear Power, and consisted primarily of individuals assigned
to the nuclear manager's review group (NMRG). Both review groups used TVA
personnel as well as consultants to assist in their investigations. The
NRC investigation effort encompassed an independent investigation of the
three events as well as a review of the scope, methodology, and results of
the TVA investigations.
The first two events occurred on January 28,
1987, and February 1, 1987. Both review groups were chartered to perform
investigations into the events after the second one occurred. The third
event took place on April 29, 1987, and was investigated by a third group
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consisting primarily of P0RS personnel,
a.
The first event occurred while the RCS was partially drained to allow
for steam generator (SG) primary side maintenance.
The sight glass
used to determine RCS level became plugged by debris and corrosion
products. The unit operator (V0) was unable to determine the exact
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level by use of an installed TV camera and monitor, and sent an
Auxiliary Unit Operator into containment to verify level in the sight
glass. The AU0 reported that level was 11 inches higher than the
previous recorded level.
The U0 decided to lower the level in the
RCS back to the normal control level. This was accomplished over the
next 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> by increasing the letdown flow rate while holding the
charging rate constant. The U0 did not realize that the sight glass
was plugged and was not responding properly.
The observed level
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decrease over this period was only 2 inches in the sight glass while
the' actual RCS level decreased approximately 18 inches. The level
decrease was terminated when the RHR pump displayed signs of cavita-
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tion and loss of flow, indicating that the actual level dropped below
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the minimum for adequate RHR pump suction. When this occurred, the
U0 stopped the running RHR pump, and began increasing level to gain
RHR shutdown cooling to the core.
His primary concern at that time
was to restore adequate level to enable the resumption of RHR flow.
The UO realized that the sight glass indication was misleading, but
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nevertheless continued to increase level based on that indication.
Personnel monitoring' the SG work by a separate TV monitor observed
the RCS level beginning to rise in the primary channel head through
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the open manway door.
They phoned the control room and told the UO
of the imminent spill of water out the manway. The U0 secured from
increasing the level, but the water continued to rise for approxi-
mately 3 minutes after the charging stopped.
This resulted in
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approximately 500 gallons of RCS water being spilled out the open
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manway. There were no personnel injuries or contamination associated
with this event.
b.
The second event occurred while the RCS was still partially drained
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and open at the primary side manway for SG repairs. The U0 on shift
was stroke-time testing valves on a scheduled surveillance interval.
The surveillance instruction in use for this evolution was SI-166.3,
Full Stroking of Category
"A"
and "B" Valves during Cold Shutdown.
The list of valves included FCV-63-1, the refueling water storage
tank (RWST) isolation valve. This valve isolates the RHR pumps from
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the RWST, and is shut while the RHR system is aligned to the RCS for
With the RCS depressurized, opening this valve
would result in RWST water filling the RCS through the RHR suction
line connected to RCS loop 4, due to elevation head differences.
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The inspector interviewed the U0, shift engineer (SE) and assistant
shift engineer (ASE). As as result of these interviews, the inspec-
tor determined that the U0 knew that this potential for flooding the
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RCS existed, and that the procedure used did not include the appro-
priate isolation of the RWST from the RCS prior to opening FCV-63-1.
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Additionally, administrative instructions associated with hold orders
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were not utilized to assure proper isolation of the RWST from the
drained opened steam generator.
The UO knew the procedure was
inadequate in that all valves required for isolating the RCS from the
RWST were not included in the procedure, but did not stop the test as
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required and get the procedure corrected. Instead, the U0 informally
changed the procedure by closing what was thought to be the appropri-
ate isolation valves.
The U0 did not refer to a flow diagram, but
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relied on memory alone to construct a lineup.
Neither of the two
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series RCS suction isolation valves were included in the isolation
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process. As a result, there was a direct flow path from the RWST to
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the open depressurized ECS when FCV-63-1 was opened during the stroke
test.
The RCS was imnediately filled, and water began flowing
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rapidly from the open ranways. The event was terminated by reclosing
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FCV-63-1.
Approxir..s i.e ly 3000 gallons of water was spilled and
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"several workers in - containment were wetted down.
No injuries
occurred and no personnel contaminations were identified.
SI-166.3 ' was not~ adequately established in that changes to the
instruction were necessary for the conditions in effect at the time
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of the test to prevent draining the RWST to the open steam generator.
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The instruction was nevertheless used by the operator to perform the
stroke-time testing of valve 1-FCV-63-1.
The operator attempted to
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make the instruction usable by performing an informal, unreviewed
change to the instruction in the form of additional valves that were
repositioned in an attempt to isolate the RCS from RWST. Changes and
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revisions to plant instructions are controlled by Administrative
Instruction (AI)-4, " Preparation, Review, Approval and Use of Plant
Instructions."
The operator did not implement this instruction.
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Instead, an improper uncontrolled change was implemented to modify
SI-166.3.
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c.
The third event on April 29 1987, was a result of valve misalignment
of a normal system configuration that did not get entered on the
configuration log as a deviation from normal position. Prior to this
RCS spill, the operators were refilling the RCS after the SG work had
been completed.
The refill was to be followed by pressurizing the
RCS to 325 psig, the minimum pressure for RCS pump operation. The
reason the pumps were to be run, was to " sweep" air and gasses
through the system to allow thorough venting.
The operators had
checked the configuration log for deviaitons from the normal RCS
lineup, but one valve (68-594, the pressurizer spray line drain
isolation valve) was open which was not listed as a deviation in the
configuration log. As water level in the RCS was raised, air and
gasses were being vented through a power operated relief valve
(PORV). When water began flowing through the PORV, the operator shut
it and continued charging water to raise RCS pressure to 325 psig.
When the RCS pressure began rising, water flowed out the open 68-594
valve, through an attached hose, onto the side of the pressurizer,
and down onto the containment floor.
There was no indication of
leakage until an auxiliary reactor building floor and equipment drain
sump level alarm occurred.
This sump receives water from floor
drains, among several other sources. The operators checked the sump
level indicators, found level above normal, but thought that the
source of water to the sump was probably instrument sense line
leakage, and continued the pressure increase.
After reaching 325
psig, the operators began matching charging and indicated letdown
flow rates to stabilize RCS pressure. When this was done, however,
pressure began decreasing immediately, because of the unidentified
leakage out of valve 68-594.
Several attempts at matching charging
and letdown yielded the same result.
This was postulated as a
calibration error on the charging line flow rate instrument, which
had a work request written on it for recalibration. Approximately 30
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minutes later, a high containment moisture alarm occurred. At this
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point the operators realized a leak existed. They immediately began
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depressurizing the RCS and investigating the location of the leak.
Water was observed streaming from the hose attached to valve 68-594.
An operator shut the valve and terminated the leak. Approximately
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5000 gallons had spilled onto the containment floor. No personnel
injury or contamination occurred.
10 CFR 50.72, Immediate notification requirements for operating
nuclear power reactors, states in section b.2.(1) that the licensee
shall notify the NRC as soon as practical and in all cases within
four hours of the occurrence of any event found while shut down,
that, had it been found while the reactor was in operation, would
have resulted in the nuclear power plant, including its principal
safety barriers, being seriously degraded or being in an unanalyzed
condition that significantly compromises plant safety.
In this
specific example, the leak event would have been classified as a
small-break loss of coolant accident (LOCA).
If an equivalent leak
had occurred at operating conditions, it would have also exceeded TS 3.4.6.2 allowance for unidentified RCS leakage.
In this instance,
the " event" is the leak itself, not the precursor of a misaligned
valve.
10 CFR 50.72 states in section b.2.(vi) that four-hour reports shall
be made for any event or situation, related to the health and safety
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of the public or onsite personnel, or protection of the environment,
for which a news release is planned or notification to other govern-
ment agencies has been or will be made. Information related to this
event was made available for release to the news media by the
licensee in the form of an input to the licensee's wire service
(referred to by the licensee, as the " Knoxville News Tape"). This is
considered to constitute planning for a news release and necessitates
reporting the event under this section of 10 CFR 50.72 as well.
Contrary to the above requirements, no report was made to the NRC
within the time frame specified.
This is a violation (VIO) 327,
328/87-24-03.
An NRC review to determine if these three events shared common root causes
was conducted. It was determined that all three events, along with others
which have been identified during the time frame of inspection report
327,328/87-30, resulted from inadequate or unimplemented procedures.
Areas of concern include valve alignment, configuration log use, procedure
change control, hold order and and caution order use, and testing control.
This wil be followed as unresolved item 327,328/87-24-04.
11.
IE Information Notices a'nd IE Circulars (92701)
The inspector reviewed the following IE Circulars, determined that they
are not applicable to Sequoyah, and closed them.
IEC 79-01-06, Failure to use syringe and bottle shields in nuclear
medicine
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IEC 79-CI-07, Unexpected speed increase of recirculation pump MG set
resulted in power increase
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12.
IE Bulletins (92701)
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IE Bulletins are documents issued by the NRC which require certain
specific actions of the addressee.
The inspector reviewed the following
IE bulletin, determined that it was not applicable to Sequoyah, and closed
it.
IEB 79-80-22, Possible leakage of tritium gas used in time pieces for
luminosity
Based on discussions with Region technical personnel and the fact that IEB
77-BU-07 (Containment electrical penetration assemblies at nuclear power
plants under construction) was closed for unit 2, IEB 77-BU-06 (potential
problems with containment electrical penetration assemblies) is also con-
sidered to be closed for Unit 2.
13.
New Employee Concerns Program
The New Employee Concerns Program was commenced by the licensee on
February 1,
1986, in order to address all employee concerns identified
after that date.
Employee-raised concerns about safety and quality have
been determined by the licensee and the NRC to be issues that need to be
evaluated prior to the startup of either unit.
The scope of this inspection was limited to the New Employee Concerns
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Program as implemented at Sequoyah, and did not address in any detailed
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manner the Watts Bar Special Program or the New Employee Concerns Program
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(NECP) as implemented at other TVA sites. The inspectors did ubserve that
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generic and/or Sequoyah specific concerns generated in the NECP at sites
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other than Sequoyah, did get evaluated in the Sequoyah NECP.
The
inspectors reviewed the following NECP procedures to determine the
adequacy of the licensee's New Employee Concerns Programs.
ECP-SR Procedure 1, Revision 5 - Site Representative Procedure
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ECP-SR Procedfre 4, Revision 1 - Identification of Employee
Concerns that are Potential Restart Items (Sequoyah)
In addition to the above procedures, a memo dated March 13, 1987, Restart
Requirement Criteria, and an Office of Inspector General (OIG) audit of
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September 1986 were reviewed. The inspectors were also briefed by the
licensee on an anticipated change to the NECP scope and administrative
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process that will be incorporated into the NECP in response to the above
mentioned OIG audit and NRC inspection report 327, 328/86-52.
The inspectors reviewed the following NECP concerns and open files. The
licensee has defined an open file to be "an issue brought to the attention
of the NECP which can be resolved informally and is not an employee
concern." These open files generally fall into the category of an issue
that has been referred back to the line organization for resolution with
the full support of the person who originally brought the issue to the
NECP. An open file will be tracked to various stages of completion by the
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NECP depending, on the. complexity and scope' of the open file.- Approx-
-imately.~ 1,000 concerns and open files exist, of which approximately 120
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are concern files.
CONCERNS'
OPEN FILES
ECP-86-SQ-015-01
ECP-86-SQ-060 through 065
ECP-86-SQ-044-01
ECP-86-SQ-070
ECP-86-SQ-111-01
ECP-86-SQ-291
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ECP-86-SQ-125-05
ECP-86-SQ-420
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ECP-86-SQ-046-01
ECP-86-SQ-514
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ECP-86-SQ-252-01
ECP-86-SQ-638-
'ECP-86-SQ-441-01
ECP-87-SQ-097
ECP-86-SQ-496-01
ECP-87-SQ-149
ECP-86-SQ-554-01
ECP-87-SQ-153
ECP-86-SQ-709-03
ECP-86-SQ-254 01
ECP-86-SQ-303-01
ECP-87-SQ-135-01
ECP-86-SQ-258-01
Neither the licensee nor the inspectors identified any concern fi;1e items
which appeared to require corrective action prior to the startup of either
unit. The licensee identified two startup related. items that originated .
at another TVA site and were incorporated in Sequoyah site open files.
The two startup related items were identified in open files ECP-87-SQ-241'
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and ECP-86-SQ-350, .and concerned seismic loading on conduits and 6.9 KV
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electrical calculations 'respectively.
The licensee has included the
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resolution 'of these items' in the condition : adverse to quality (CAQR)
system identified as SQT870626 (SAL 0164).
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The inspectors rev'iewed previous NRC inspection [ completed' on the NECP.
The following reports were reviewed to determine if the 1Neensee had
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addressed previously identified NRC open items.and comments.
50-327, 328/86-29
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50-390/86-15-
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50-327, 328/86-52
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The following open items are considered closed.
(Closed) Inspector Followup Item (IFI) 327, 328/86-52-01, Confidentiality
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(Closed) IFI 327, 328/86-52-02, Resolution of generic issues
(Closed) IFI 327, 328/86-52-03, Justification for non generic items
(Closed) Inspector comment 327, 328/86-29, Linkage between'the NECP and
the Watts Bar'special program
The NECP appears to be well run and adequately staffed. The facilities
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and staff support appeared to meet the needs of the NECP staff.
The
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inspectors identified no NECP items or issues which would prevent the
startup.of either units.
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14. Drawing' Control Inspection
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A special inspection.:of plant' drawings was conducted to verify accuracy,
usability, control' and distribution of plant drawings and changes to the
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drawings' ~~ Inadequate drawing control in the p'ast caused the licensee to
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ins.titute a short term corrective action program as a startup prerequisite
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and a long, term program for total resolution of the problem.
The short term commitments' for. restart are described in a December 12,
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1986 -letter ' from R. ' L Gridley (TVA) to J. N. Grace (NRC). - This program -
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was to correct. legibility and accuracy problems for a group of drawings'
the licensee . selected as required for startup and operation of Unit 2.
The inspector was unable to determine the criteria used to select this set
of drawings. .. The drawings were selected by operations personnel using
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their ' judgement with no documented guidelines or other criteria. For the
selected drawings the licensee has completed such corrective actions as
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restoration .of' illegible sections, removal of extraneous markings, and -
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integration of .the Unit 1 'and Unit 2 drawings into single as-constructed
drawings.that'are applicable to both Units. It is the licensee's position
that the restart commitment for drawings has therefore been completed. .In
the absence of some documented criteria for . selection of the list of .
drawings to'be repaired, the . inspector cannot conclude that the program .is
currently satisfactory for restart.
The licensee's continuing drawing
restoration program should complete the upgrading activities for all
primary drawings by mid summer 1987 and consequently should precede the
currently scheduled restart date.
The scope of primary ' drawings is
described below.
The inspectors consider that repair of all primary
drawings prior to restart will provide for adequate drawings during the
restart evolution.
Primary drawings are defined in Administrative Instruction (AI)-25,
Part I, " Drawing Control" as all drawings which are necessary to startup,
operate, and shutdown the plant.
Drawings for both emergency and normal
shutdown are to be included.. Primary drawings are located in the unit
control rooms and are referred to during daily operation of the plant. A
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list of these drawings is included as an attachment to AI-25. The opera-
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tions superintendent maintains control over which drawings can be added or
deleted from the list.
As part of the restart drawing program, many
drawings previously included on the primary drawing list were removed and
the drawings were physically removed from the control room. While these
removed drawings are still available to the operators, (being located just
outside the control room), availability to the Technical Support Center
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(TSC) and the Chattanooga Emergency Control Center (CECC) is a concern.
This relates to the licensee's category of critical drawings.
Critical
drawings are also identified in'AI-25 and are drawings depicting features
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which are used by the plant TSC and the CECC to determine system operation
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and function.
These drawings are for use in an emergency to analyze
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problems and make recommendations for the mitigation of an accident. The
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types of drawings to be maintained as critical drawings includes
schematics, electrical, control and logic, flow, structural, and equipment
arrangement drawings. Critical drawings are a subset of primary drawings.
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In other words, c'f the list of primary drawings contained in AI-25, a
sn211 fraction of these are identified as critical drawings.
This makes
- t/ mandatory that the definition of primary drawings include critical
drawings ut a subset.
The question arises as . to whether the recent
nduction$ in primary drawings also removed some critical drawings. Since
the Emerde'ncy Preparedness Group within the Division of Nuclear Services
is retpgnsible -for the list of critical drawings, coordination between
this group and Plant Operations is essential. An apparent weakness was
detectec in 61s area by the inspector during a tour of the CECC. The
CECC is maintaining 47W200 Series of drawings, which are equipment
arrangement drawings.
The set maintained by CECC was not controlled and
was in fact, stamped "This drawing expires after December 14, 1986."
The inspector became aware of a licensee finding that questions the
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adequacy of the primary and critical drawing list.
This finding was
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identffied in TVA Employee Concern Special Program Report Number 206.1(B)
Revision 1.
Finding f states that "it appears to the evaluation team that
the primary and critical drawings listed in the drawing control instruc-
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tions do not meet the as-built drawing criteria of NUREG 0737 Supplement 1
or of NUREG 0696".
The issue was judged to be beyond the scope of the
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report, which was not prepared to evaluate TVA's compliance with
regulatory requirements for emergency response capability. The licensee's
compliance organization stated that this adverse finding was not trans-
ferred to any other program for resolution.
The inspector informed
licensee _ management during the exit meeting that this would be an
Unre wlad Item (URI 327,328/87-24-01) pending resolution of the apparent
noncompliance with the Order Confirming Licensee Commitments on Emergency
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Response Capability issued January 15, 1984.
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In the, area of management control, another apparent inconsistency should
be addressed by the licensee.
In TVA's Corporate Nuclear Performance
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Plan, one of the contributing causes of the management breakdown is
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identified as a failure to implement the overall nuclear program on a
consistent basis. This was due to the division of authority and respon-
sibility throughout many groups with autonomous organizations.
restructured itself to provic'e strong central leadership and control, yet
in the area of drawing control Brown's Ferry (BFN) and Sequoyah (SQN)
plants are heading in totally opposite directions prior to restart. At
SQN, drawings which were previously unitized (a drawing applicable for
Unit 1 and a separate draw hg applicable for Unit 2) are being combined (a
single drawing applicable to both units). At BFN, drawings which were
previously combined are being unitized.
Discussions with engineering
representatives (DNE) at SQN indicated that in the long term, SQN would
eventually revert back to unitized drawings in a new Configuration Control
Drawing (CCD) system. However, this was not formally documented on any of
the drawing ccqtrol program plans.
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Of the drawings repaired and re-issued by the licensee for restart, two
areas of concern were detected. First, the problem inherent to combining
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drawings is that when mit specific differences exist in the as-built
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systems, the drawing ret accurately depict the difference.
Several
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examples were found in, which neither the inspector nor operators could
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ascertain the difference, This comes from the practice of using an arrow
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with a note that indicates that a particular feature or component only
exists on' one unit and not the other.
The boundary is not clearly
depicted, such that how much of the feature or how many ' components the
note is applicable to is readily apparent. The second problem relates toc
the interim process of marking up control room drawings with red or green
markers following a modification to the system. These marked up drawings
are made available to the op rator until. permanent changes are completed.
Numerous errors were detected in this " red-line" process by the
inspectors. Additionally,,the inspectors noted that no independent review
was conducted by the licensee of this drawing change process.
This
appears to be contrary to 10 CFR 50, Appendix B, Criteria VI. Information
made available to the inspectors just prior to the inspection exit meeting
indicates this issue may be licensee identified.. Until that is deter-
mined, this item ~ will be tracked as an Unresolved Item (URI 327, 328/
87-24-02) as a _ potential violation of 10 CFR 50 Appendix B, Criteria VI,--
Document Control.
Resolution of this deficiency is considered by the-
inspectors to be required prior to restart.
Examples of errors in the red-line process were found on the following
drawings:
1.
47W839-1, Flow Diagram, Diesel Starting Air
2.
47W813-1, Flow Diagram, Reactor Coolant System
3.
47W809-1, Flow Diagram, Chemical and Volume Control System
4.
47W810-1, Flow, Diagram, Residual Heat Removal System
5.
47W610-26-3, Mechanical Control, High Pressure Fire Protection
-System
6.
.45N772-4, 480-V, MCC Wiring Diagram
7.
47W610-30-4&8, Mechanical Control, Containment Ventilation
8.
47W610-31-9, Post Accident Sampling HVAC
Examples of unclear depiction of the differences between units were found
on the following drawings:
1.
47W804-2, Flow Diagram, Condensate System
2.
47W813-1, Flow Diagram, Reactor Coolant System
3.
47W812-1, Flow Diagram, Containment Spray
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4.
45N765-11, 6.9 KV Shutdown Auxiliary Power Wiring Diagram
Additional miscellaneous drawing problems observed during the inspection
are listed below:
1.
One drawing (recently issued) was found with legibility problems
caused by the reproduction process (35N711-1 R9).
2.
Spurious red and orange markings were -found on 47W809-3. This
could be confused with the red-line process.
3.
Drawing 47W809-5 (Unit 2) shows Temporary Alternation number
84-2002-62 installed. No such alteration could be located. The
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correct number was determined to be 84-2004-62.
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Uncontrolled paper copies of . drawing 45N772-4 and 47W610-26-3
'were found~in the control room mylar drawing. set.
5.
Between 25% and 40% of the drawings reviewed in the CECC had
. legibility problems.
In particular, drawing 47W812-1 Rev.11,
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Flow Diagram For Containment Spray, was completely unusable.
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The. root cause ' appears to be serial reproduction.
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6.
A perfunctory check of the TSC' drawing set revealed some missing
drawings in the 45N703 series.
.The inspectors consider that these deficiencies require correction prior
to restart.
The inspectors reviewed and closed the following IFIs based on review of
the short-term (interim) drawing control process now in place at Sequoyah:
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(Closed)
IFI 327,328/86-20-06, Accura'cy of Control
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Drawings.
(Closed) IFI 327,328/86-37-07, Drawing Control
(Closed) IFI 327,328/86-49-04, Review Problems Caused By Main-
taining Unitized-Prints When They Show The Same Equipment.
15.
Sequoyah Operability Look Back Review
As a result of violations identified in Inspection Reports 50-327,
328/85-45 and 50-327,328/86-37 regarding the adequacy and timeliness of
corrective actions for repetitive equipment failures and out-of-tolerance
conditions, Sequoyah recently implemented a tracking and trending program.
From conception, this new tracking and trending program was geared towards
identifying present and . future deficiencies.
Consequently, during an
October.29, 1986 meeting with TVA, a discussion took place involving
previously expressed NRC concerns over potential operability questions
resulting from past undetected repetitive failures.
This resulted in a
TVA commitment to establish and submit their plans for an operability
"look back" review.
Under the control of the Technical Assessment Group of the Plant Opera-
tions Review Staff (PORS), the Sequoyah ' operability' look back review was
conducted from December 1,1986, through March 19, 1986, and involved the
expenditure of approximately 7,500 man-hours by its 30 person staff.
It
was designed to identify adverse conditions associated with equipment
operability, evaluate the conditions for significance with respect to
safety, document the existence and effectiveness of corrective actions,
and propose additional or modified corrective actions where necessary.
.This was accomplished by analyzing data and information collected from:
(1) units 1 and 2 maintenance related potentially reportable occurrences
(PR0s) from 1980 through 1986 which fell under cause codes
"B" (Design,
Manufacturing, Construction / Installation),
"E"
(Component Failure), and
"X" (Other); and (2) interviews' of senior plant engineers from operations,
maintenance, and PORS.
There were 132 plant employees interviewed,
identifying 355 conditions associated with equipment operability problems.
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In addition, there were 1,917 PR0s examined, of which 1,569 were asso-
ciated with equipment operability, and were therefore assessed during this
review effort.
The review process identified and evaluated 651 equipment operability
issues involving 62 separate plant systems and 9 generic equipment groups
(i.e.,ASCO,Foxboro,etc.....). An individual issue summary package was
prepared for those plant systems and generic equipment groups involved.
Of the 587 issues involving safety-related equipment, 135 concerned
conditions where no corrective action had been previously identified, or
additional corrective action was recommended. There were 72 issues found
to have corrective actions identified, but not yet completed. From these
207 issues, 44 conditions, with corrective action recommendations, were
identified to plant management for resolution prior to restart. These
issues involved:
condenser vacuum exhaust flow; upper head injection
(UHI) instrumentation and valves; ice condenser "I" beam seismic qualifi-
cation; instruments plugged into wrong plug molds; adequacy of RHR bypass
flow analysis; electric board room and main control room cooler valves;
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defective or missing penetration room cooler dampers; containment hydrogen
analyzers; reactor coolant pump sealwater injection lines; replacement of
specific Foxboro transmitters; essential raw cooling water (ERCW) and
component cooling system (CCS) containment isolation check valves; diesel
generator (DG) governor connector plugs; steam generator (SG) blowdown
containment isolation valves; safety injection (SI) flow indicators; plant
electronic transmitters; EQ operators; SG power operated relief valves; GE
transmitters installed with vents on bottom and sense lines on top;
installation problems associated with compression fittings; air regulators
on auxiliary feedwater bypass level control valves; auxiliary air com-
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pressor failures; non-essential use of essential air system; seismic
qualification of auxiliary control air pressure switches; sticking sample
valves; ice condenser lower inlet door leakage; ERCW supply valves to
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diesel generators; CCS flow balance; CCS cavitation problems; radiation
monitoring pump failures; auxiliary feedwater level control valves;
motor-driven auxiliary feedwater pump bearings; auxiliary feedwater (AFW)
flow modifier calibration problems; AFW steam supply swapover pressure
switches; high pressure cold leg accumulator pressure switch; agastat
relays; emergency gas treatment system (EGTS) damper response times;
shield and auxiliary building stack flowrate monitor transmitter;
auxiliary building gas treatment system flow controllers; pressurizer loop
seal heat trace; EGTS cooldown valves; radiation monitor vacuum switch
calibration problems; unit I condensate reservoir; pressurizer level
transmitter; and chemical volume control recirculation flow control valve
timing.
The NRC inspection and assessment of the Sequoyah operability look back
review program was performed during the week of April 27, 1987.
This
assessment involved a detailed review of the issue summary packages that
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were prepared for systems 87 (UHI) and 67 (ERCW). Selected reviews were
also conducted of issues contained in summary packages prepared for
systems 63 (SI), 82 (DG), and generic equipment (ASCO), as well as of the
44 restart items discussed above. Additionally, interviews were conducted
with lead review engineers (2 of 4), the project manager and his
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assistant, members of Sequoyah's restart task-force, and the tracking and
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trending program manager.
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Collectively, the inspection finding inputs indicated that the scope,-
guidelines, and implementation of the - Sequoyah operability look back
review program ~ satisfactorily accomplished its intended purpose.
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identification of existing equipment operability and reliability problems
re-emphasizes the need for the' newly implemented tracking and trending
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program. Operability issues identified by the 'look back' program which
involved safety injection relief valves and ~ containment isolation valves,
indicated that the sliding-window time span being used in the tracking and
trending program -to - detect repetitive equipment deficiencies was too
small.
The time. span has subsequently been , increased to assure the
tracking and trending program will identify such 1tems in the future.
Because the tracking and. trending program has been established to identify
future repetitive equipment failures 'and ~ the issues identified by the
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operability look back program are to be corrected and tracked to comple-
tion, the findings of the look back program are not being fed back into
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the' tracking and trending program.
Consequently, it was recommended to
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the licensee that the operability look back issue summary packages be made
readily available to those groups designated to ~ evaluate future deficien-
cies which are -identified by the tracking and trending program.
The
licensee' concurred.
With respect _to the implementation of the look back corrective action
recommendations for'the 207 issues involving safety related- equipment, the
corrective actions associated with the 44 restart issues have been
encompassed by line item 930 of the Sequoyah activities list (SAL), with
individual actions being tracked on the P-2 schedule. At the time of the
inspection, there was no formalized method established to ensure timely
disposition and completion of the remaining non-restart corrective action
recommendations.
The licensee indicated that 'such a program will be
established under the responsibility of the Technical Assessment Group of
PORS.
NRC's review of the identified issues also revealed that for some of the.
restart issues, as well as for several others, compensatory measures were
used .as interim corrective action to justify system operability for
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restart. NRC indicated to the licensee that such reliance on compensatory
measures may not be appropriate. A case in point, involves the use of an
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assigned watchstander to open and/or verify open the normal ERCW supply
valves to the emergency diesel generators to preclude further failures of
the valves to automatically open when the diesels are called upon to
start. . The look back recommendation identified valve operator replacement
prior to restart.
Seismic analysis of these larger, more powerful
limitorque operators has the potential to delay a July restart.
Therefore, the interim compensatory corrective action is specified for
restarting the unit.
It was also pointed out to the licensee that their
present restart criteria does not reflect the use of compensatory measures
to consider systems or equipment operable.
The inspector requested a
complete listing of issues where the restart evaluation was based on
compensatory measures and justifications for operation. This issue, along
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with the.: final' disposition . of the' non-restart issue recommendations will .
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.be. inspected at a'later date during the restart readiness inspection.
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- No violations or de'iations were' identified.
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