ML20150B943
| ML20150B943 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 02/11/1988 |
| From: | Brooks C, Christnot E, Ignatonis A, Andrea Johnson, Patterson C, Paulk G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20150B926 | List: |
| References | |
| 50-259-87-46, 50-260-87-46, 50-296-87-46, IEIN-86-039, IEIN-86-39, NUDOCS 8803170200 | |
| Download: ML20150B943 (28) | |
See also: IR 05000259/1987046
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UNITED STATES
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NUCLE R REGULATORY COMMISSION
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REGION 11
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101 M ARIETTA STHEET. N.W.
ATLANTA. GEORGI A 3o323
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. Report Nos.:
50-259/87-46, 50-260/87-46, and 50-296/87-46
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Licensee: Tennessee Valley Authority
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6N 38A Lookout Place
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1101 Market Street'
Chattanooga, TN 37402-2801
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Docket Nos.:
50-259, 50-260, & 50-296
License
Nos.:
& DPR-68
Facility Name:
Browns Ferry 1, 2, and 3
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Inspection Conducted: December 1-31, 1987
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Inspectors:
G. L. P(ulk, Senior RgidentvInspector
Date Signed
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C 7 . Pct {erson, Reside 6t 16spector
Date Signed
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C. R. Brogks, Resident Inspegtor'
Date' Signed
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E. F. 'Chrfstnot, Resid6n1PInspgetor
Date~ Signed
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A. H. Jbhnson, Project Ensineer
Date Signed
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NRC Contractor Assistance:
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David B. Waters, Previous Enforcement Matters
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Gary W. Bethke, Previous Enforcement Matters
Approved by:
(7. /) Mmob
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A. J. Ig G tonisl Jection Chief
Date S'ign'4d
TVA Projects Division
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SUMMARY
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Scope:
This routine inspection was in the areas of previous enforcement
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matters, multi plant action item, "war room" meeting, operational safety,
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maintenance observation, informacion notice review, surveillance observation,
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reportable occurrences, cold weather preparations, restart testing, and emer-
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gency procedures.
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8803170200 880226
ADOCK 05000259
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Results: A violation of Technical Specification 4.7.B.2.a involved failure to
properly test the Standby Gas Treatment System following the fire in the Unit 2
drywell on Novemt:r 2, 1987.
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REPORT DETAILS
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1.
Licensee Employees Contacted
H. C.~Pomrehn, Site Director
- J. G. Walker, Plant Manager
P. J Speidel, Project Engineer
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- J. D. Martin,-Assistant to the Plant Manager
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R. M. McKeon, Superintendent - Unit 2
- S. Olsen, Superintendent - Units 1 and 3
T. F. Ziegler, Superintendent - Maintenance
D. C. Mims, Technical Services Supervisor
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J. G. Turner, Manager - Site Quality Assurance
M. J. May, Manager - Site Licensing
- J. A. Savage, Compliance Supervisor
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A. W. Sorrell, Health Physics Supervisor
R. M. Tuttle, Site Security Manager
J. R. Kern, Fire Protection Supervisor
D. A. Pulien, Office of Nuclear Power, Site Representative
Other licens ee employees contacted included licensed reactor operators,
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auxiliary operators, craftsmen, technicians, public safety officers,
quality assurance, design and engineering personnel.
- Attended exit interview
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2.
Exit Interview (30703)
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The inspection scope and findings were summarized on December 18, 1987,
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and January 8,1998, with the Plant Manager and/or Superintendents and
other members of his staff.
The following new items were identified
during this inspection.
a.
Violation 259,260,296/87-46-03.
Failure to conduct test per desig-
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nated ANSI standard (Paragraph 11, Section a).
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b.
Unresolved Item 260/87-46-04.
Licensee's followup on generic
implications of heat tracing CAQR disposition (Paragraph 13).
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c.
Inspector Followup Item 259,260,296/87-46-01.
Independent review
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of substitute material data for RB equipment access door seals
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(Paragraph 9, Section a).
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d.
Inspector Followup Item 259,250,296/87-46-02.
Review of RHR pump
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wear ring raaterial by specialist (Paragraph 9, Section b).
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Inspector
Followup
Item
259,260,296/87-46-05.
Correction
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deficiencies in Emergency Plans Manual (Paragraph 15).
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The licensee acknowledged the findings and took no exceptions,
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The licensee did not identify as proprietary any of the materials provided
to or reviewed by the inspectors during this inspection.
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3.
Licensee Action on Previous Enforcement Matters (92702)
(OPEN) Deviation (259,260,296/87-20-01), This item concerns the anchoring
of control room panels in a manner not consistent with the seismic capa-
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bility demonstrations described in the FSAR. As opposed to being floor
mounted with 5/8 inch bolts in all mounting holes or a similar fashion as
justified by analysis, the as-constructed panels were tack welded at
intervals to fasten in place atop embedded plates.
This issue was first raised as an unresolved item in Inspection Report
86-25 (URI 259,260,296/86-25-04).
The licensee investigated several
specific control room panels applying techniques under development by the
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Seismic Qualifications Users Group (SQUG) and determined that the weld
attachments were satisfactory. However, further licensee review of other
control room panels found that the method of fastening by welding was not
an adequate means of mounting.
In response to the deviation, TVA has performed a seismic review of the
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main control room vertical bench board panels and freestanding control
panels and has determined an appropriate mounting arrangement. The design
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consists of an "L" shaped steel bracket secured to the concrete floor with
anchor bolts and running the length of the panels.
The panels are then
secured to the brackets at 4 inch intervals by rivets.
Tne engineering
calculation number is CD-Q0009-871685 and utilizes standard analytical
techniques.
Design Change Notices B00019A, B00020A and B00021A have been
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issued for modification required for Units 1, 2, and 3 respectively.
The
licensee has committed to install the modification by February 27, 1988.
This item remains open pending completion of the modifications.
(OPEN) Violation (259,260,296/86-43-03), This violation resulted from
inspector review of NCRs, SCRs and Problem Identification Reports (PIRs)
for determination of generic applicability, justification for considering
items not generic, adequacy and timeliness of Potential Generic Conditions
Evaluations (PGCEs) and adequacy and timeliness of PGCE replies by the
various TVA sites. At the time of the inspection, the corrective action
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program had not been updated to the program currently in effect, namely
Nuclear Quality Assurance Manual (NQAM) Part 1, Section 2.16, "Corrective
Action". The inspectors noted several examples of untimely responses as
the basis for the violation.
The current corrective action program differs in several respects from the
the earlier programs.
The requirements for the conduct and timir.g of
generic reviews has been made more controlled and centralized by requiring
that the organization responsible for determining corrective action
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initially review the Condition Adverse to Quality Report (CAQR) for its
potential
generic
impact on other TVA facilities.
Subsequently,
significant CAQRs and nonsignificant but potentially generic CAQRs shall
be forwarded to eir.her the Division of Nuclear Safety and Licensing or
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Division of Nuclear Engineering - Engineering Assurance for further review
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as to the potential for generic implications.
These organizations will
document justification that the CAQ is not generic or issue a . request to
perform a generic- review by other potentially affected organizations.
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These organizations in turn are to provide a response which indicates
whether or not they are affected and the justification if they are not
affected.
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The timing associated with these actions are as follows:
(1) Within 30
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calendar days from CAQR origination date, the 7 responsible organization
determines remedial corrective action; root cause and recurrence control,
if required; scheduled completion dates for remedial corrective action and
recurrence control,
if required; and whether a review for generic
implications is needed; (2) CAQs reviewed for potential generic implica-
tions by DNSL or DNE-EA 40 calendar days from CAQR origination date;
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(3) potentially affected organizations shall review CAQRs for generic
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implications - 70 calendar days from CAQR origination date.
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In order to asse'ss the effectiveness of the new corrective action prsgram
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in providing timely reviews of CAQRs for potential generic implications,
the inspector obtained from the licensee a listing of CAQRs generated by
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Bellefonte, Saquoyah, and Watts Bar which required a review for potential
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generic implications by Browns Ferry between August 1,
1987, and
November 30, 1987
Out of the 65 items listed, only 5 had been closed
prior to the required due date; 10 were closed between 30 to 60 days after
the due date and 5 were closed greater than 60 days after the due date.
Of greater concern are those which remain unclosed and are substantially
late. In this category, 11 are unclosed and are 30-60 days after the,due
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date, 14 are unclosed and are 60-90 days af ter the due date, and 2 are -
unclosed and greater than 90 days after the due date.
The lateness of
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these reviews may not totally be the result of Browns Ferry organizations
facility to take timely action; but rather a combination of several other
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factors including the receipt of timely inputs from other site organiza-
tions.
The report reviewed by the inspector does not indicate the date
when assignment was made to a Browns Ferry organization.
The current corrective action program has several mechanisms for reporting
status of CAQRs and informing management of problem areas.
While the
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mechanism of CAQR processing by different licensee organizations appears
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to be acceptable, no noticeable improvement was observed for timely
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review and closecut of CAQRs for potential generic implication.
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overall corrective action program remains open pending further review to
determine if required action times and organizational support of the
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program are adequate to make the program truly effective.
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4.
Followup of Open Inspection Items (92701)
(CLOSED) Unresolved Item (253,260,296/86-05-01), FSAR Updates Without
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Justification. This unresolved item was opened when inspectors determined
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that several original FSAR commitments had been deleted or modified in
Amendment 1 to the FSAR without documented justification or safety
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evaluation. TVA reviewed other changes to the FSAR and either provided
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safety evaluations or returned the wording to original wording in the 1986
FSAR update. This action corrected the specific unresolved item 86-05-01
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FSAR word change problems. bring an August 1987 NRC inspection, similar
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problems were discovered noting that TVA made changes to the FSAR in
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Amendment 5 dated July 22, 1987, which were not formally evaluated or
- documented for review.
TVA has responded i.o the resulting Deviation
87-30-04 with a letter dated November 17, 1987.
TVA commitments made in_the November 17, 1987 letter are scheduled for
completion by June 22, 1988.
The inspectors will followup ~ on this
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concern by reviewing TVA's response to Deviation No. 87-30-04.
This
Unresolved Item is closed.
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(OPEN) Inspector Followup Item (259,260,296/86-25-02),- Control Room
Emergency Ventilation Walkdown Deficiencies.
This IFI was opened as a
result of numerous deficiencies discovered during an inspector walkdown of
the CREV system. Most of the deficiencies were hardware oriented and have
been corrected by TVA personnel.
The following individual parts of the
IFI are considered closed, with corrective action noted:
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Several FCO-31-150 series dampers were not labeled or were labeled
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incorrectly:
The completed January 28, 1987, Maintenance Request
(MR) to install damper labels was reviewed and found to be
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acceptable.
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The system operating instruction, 01-31 "Air Conditioning System",
did not contain dampers FCO-31-150 B, D, E and F in the valve check-
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list: The October 1987 Revision to 01-31 was reviewed to verify that
these dampers were included.
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The CREV A Backdraft damper was found stuck open: The initial MR
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which fixed the problem in January 1987 was reviewed.
TVA has also
initiated a preventive maintenance, biweekly cleaning of the CREV
Backdraf t dampers effective September 1987.
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An air line compression fitting near damper FCO-31-150 0 was found
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leaking:
The completed March 1,1987 MR which replaced the fitting
was reviewed and found to be acceptable.
The CREV B heater control setpoint adjustment knob was found broken:
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The completed October 30, 1986, MR which replaced the knob was
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reviewed and found to be acceptable,
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Final closure of this IFI is dependent on two remaining deficiencies which
were not addressed in the TVA closure package.
These deficiencies are:
Reactor Operators (R0s) and Senior Reactor Operators (SR0s) took an
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excessive amount of time to search for and locate the dampers which
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must be manually shut, per 01-31, in the event of failure to close
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automatically.
The closure package did not address how TVA has
upgraded R0 and SR0 knowledge on the'CREV system component locations.
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Dampers FC0-31-150 F is one of the dampers which may need to be
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manually shut by operators. The damper is located about 6 feet above
the Unit 3 Control Room ceiling panels and is extremely difficult to
access for manual operation. The closure package did not contain any-
discussion of an evaluation by TVA to determine if the subject damper
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needs to have a remote operating aid attached (e.g., a reach rod).
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As of December 15, 1987, TVA may consider the scope of this IFI reduced to
the two items noted above (operator familiarization with CREV and possible
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need for a remote operating tid for FCO-31-150 F).
These two items will
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continue to be tracked under IFI 86-25-02.-
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(CLOSED)
Inspector Followup Item (259,260,296/86-02-03),
Operability
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Evaluation due to Froblems Identified During Licensee's Field Inspection
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of Anchor Bolt Verification.
This IFI was opened as the result _ of a
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Seismic Cable Tray Support Anchor Bolt Sampling Program which - was
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initiated by TVA to resolve Unresolved Item 85-41-01, "Verification of
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Installed Concrete Anchor Bolts for Cable Tray Supports". The sampling
program showed that seismic cable tray supports have self-drilling anchor
bolts (Phillips Redhead) installed versus the three unit threaded cinch
anchor bolts specified in some older construction drawings.
The sample
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program results closed item 85-41-03, but revealed several new concerns
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relating to the installation of seismic cable tray supports.
Concerns
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included:
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Two support locations called for six bolt pattern plates and only
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fcsr bolt pattern plates were installed.
Poles in she plate were consistently oversized.
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Gaps between the bottom of the plate and the concrete surface were
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excessive.
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The recess between the top of the anchor bolt shell and the top of
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the concrete surface was excessive.
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Thread engagement was less than minimum requirement.
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Orawings 48N1100, 48N1104, 48N1101, and 48N1105 have been revised and
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reissued to properly indicate the as-built 4 bolt pattern plates (where
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6 bolt patterns were originally indicated).
DNE calculation package
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822860213101, sheet ld shows the composite affects of hole oversizing,
base plate gaps, anchor bolt shell recess, and thread engagement for 4
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bolt pattern plates,
These calculations show that the subject supports
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are adequate for interim qualification under general design criteria
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BFN-50-795 (I). This interim qualification is the near term resolution of
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anchor bolt questions at BFNP.
The long term TVA resolution of anchor
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bolt questions is planned to be accomplished by the licensee's involvement
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with the Seismic Qualification Utility Group (SQUG).
TVA intend to
participate in the walkdown of the Generic Implementation Procedure (GIP)
at Nine Mile Point during February and March 1988.
The GIP has been
developed as a means for older plants to resolve the seismic
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qualification issues raised by IEEE-344, Unresolved Safety Issue A-46,
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Generic Letter 87-02, NUREG 1030, and NUREG 1211.
Furthermore, TVAs
overall plan for addressing seismic qualification issues is outlined in
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Volume 3 of the BFNP Nuclear Performance Plan.
(CLOSED) Inspector Followup Item (259,260,296/86-05-10), Protection of
Control Bay Ventilation Towers from Tornad Generated Missiles. This IFI
was closed during inspection 86-14 based upon the submission of undocketed
PRA data to NRC by TVA. The subject issue was re-opened in inspection
86-40 because it was determined that the PRA data was an unreviewed draft
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from which no meaningful conclusions could be drawn. The TVA assessment
of the probability of a tornado missile striking ventilation tower equip-
ment is contained in LER 86-06-02 and is now being tracked by the NRC
under IFI 86-40-09.
(CLOSED) Unresolved Item (259/85-25-08), Rod Worth Minimizer Program Alarm
Message Table Missing. This item was opened when it was discovered that a
portion of the Unit 3 RWM Alarm Message Table (0CTAL CODE) was missing
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from the write only portion of the process computer memory. The missing
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section of the code has been loaded into the Unit 3 process computer
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memory. The octal code sheets have been compared for a match with Units 1
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and 2.
The revised RWM and RSCS Functional Test for Startup (August 1987)
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and RWM Program Verification (August 1987) procedures have been reviewed
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for completeness. The RWM Program Verification Procedure (SI-4.3.B.3.b.3)
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is a new procedure and requires two man verification of the RWM program
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during reactor startup.
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(CLOSED)
Inspector Followup Item (259,260,296/86-32-10), This item
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concerns the adequacy of MMI-34, Refueling Platform Inspection and Repair,
in specifying the correct mechanism for performing corrective maintenance
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when the need is discovered during the performance of other routine
maintenance activities. The licensee had recognized the need for improve-
ments in MMI-34 in order to ensure proper maintenance history records that
can be used to accurately trend recurring defects, and committed to review
and make necessary changes to MMI-34 to satisfy the concerns of this item.
The licensee provided Commitment Closure Summary SLT 861087003 which
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included Revision 3 to MMI-34. Revision 2 to IMSI-3014, Troubleshooting
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and Maintenance Instruction (for instrumentation maintenance), Revision 1
to EMI-lob, Troubleshooting, Wirelif ts and/or Reterminations (for elec-
trical maintenance) and new procedure 50SP 7.6, Maintenance Request and
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Tracking.
The revision to MMI-34 includes a statement that requires an
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approved MR per SDSP-7.6 for all corrective maintenance activities such as
repairs o
parts replacement.
IMSI-3014 and EMI-106 require the use of
MRs to perform troubleshooting, repairs or additional corrective action
outside of the specific requirements of the MR controlling the work
activity.
The revision to MMI-34 and the requirements of the other
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procedures are adequate to ensure that corrective actions are controlled
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by the MR process.
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Discussions were held with the licensee on other MMI procedures where the
problems encountered in MMI-34 might also potentially exist. The licensee
responded that other MMI procedures . did not contain a statement on
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corrective maintenance activities similar to the one provided in MMI-34,
thus creating the possibility that repairs or parts replacement could be
conducted on other plant equipment without being documented through the MR
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process.
The licensee proposed that a statement be included in SDSP-6.2,
Preventive Maintenance Program, to address the concern on an overall basis
in a controlling document and avoid the need to make revisions to numerous
procedures.
The inspector concurred with this approach and with the
proposed revision to SDSP 6.2.
PMI-6.2, Conduct of Maintenance, already
contains a satisfactory statement on corrective maintenance activities.
This item is closed.
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(OPEN) NRC Inspection Report (259,260,296/86-35, Sample No. 6), This item
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addresses reanalysis of high energy lines at Sequoyah where the licensee
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requested relief from the requirements of Regulatory Guide 1.46 to
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relocate high energy line break (HELB) protective devices for arbitrary
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intermediate break locations based on the reanalysis being performed.
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Based on verbal approval from NRR, the licensee revised plant design
criteria documents to incorporate this exception to RG 1.46, but did not
reflect this exception in the Sequoyah Nuclear Plant updated FSAR.
The
concern was that comparable documentation deficiencies may exist at Browns
Ferry and should be corrected,
The licensee provided Ccmmitment Closure Summary NCO 870096021 containing
a copy of the TVA response to Sample No. 6, the Sequoyah information
related to the reanalysis issue addressed in Sample No. 6 a copy of
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Generic Letter 87-11, which relaxes arbitrary intermediate pipe rupture
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requirements, and an internal memorandum addressing the applicability of
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this item to Browns Ferry.
The licensee stated that they had reviewed the applicable portion of the
Browns Ferry FSAR and concluded that the issue addressed in Sample 6 is
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not specifically addressed. Analyses of high energy lines were conducted
based on NRC requests following issuance of the FSAR and thus requirements
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and results of analyses were never specifically incorporated into the
document. There is, therefore, no documentation conflict and no revision
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required to the FSAR f or Browns Ferry.
However, since the NRC has
recently relaxed the regulatory requirements for high energy line break
considerations and deleted the requirement for postulation of arbitrary
intermediate pipe breaks, the licensee plans to update their analytical
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proceoures and criteria and prepare FSAR changes to take advantage of this
relaxation.
This item will remain open pending completion of the FSAR
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revision.
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(CLOSED)
Inspector Followup Item (259,260,296/86-43-01),
This item
addresses concerns arising from the review of the licensee's corrective
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action program as set forth in the Nuclear Quality Assurance Manual, Part
1, Section 2.16, Rev. 1, "Corrective Action". The concerns were: (1) the
procedure does not contain clear requirements on immediate notification of
appropriate personnel upon identification of Conditions Adverse to Quality
(CAQs) which could affect safety in an operating plant, (2) qualification
requirements were not referenced for personnel evaluating CAQs, and
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(3) provisions were not included to provide for disposition ar.d justifi-
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cation by other units at the same site of CAQs where the issue was
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determined to be generic.
The licensee provided Commitment Closure Summary SLT870051001' which
contains Revision 3 to NAQM Part 1, - Section 2.16; SOSP-3.7, Corrective
Action, Revision 2, which is the Browns- Ferry implementing procedure for
NQAM Part 1, Section 2.16; and a listing of the qualified CAQR management
reviewers.
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In response to concern (1), the licensee -added a note to the Section on
CAQR processing (Section 7.0 of NQAM Section 2.16 and -Section 6.2 of
SOSP-3.7) that provides guidance for immediate transmittal of CAQRs that
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potential.y affect plant operability to the PORS section of the affected
plant, immediately notifying the affected nuclear site director of CAQRs
that adversely affect the health and safety of the public and plant
employees, and immediately transmitting to P0RS any CAQR that is poten-
tially reportable for a determination of reportability.
This provides
assurance that operability problems can be effectively communicated to the
appropriate personnel during off hours, weekends and holidays.
In response to concern (2), the licensee indicated that training programs
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have been conducted for personnel initiating and processing CAQRs as well
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as those personnel designated as management reviewers who are responsible
under Paragraph 6.2.2 of 50$P-3.7 for reviewing the CAQR for legibility,
clarity, completeness and validity. Site QA maintains a current list of
qualified management reviewers to ensure that the reviews are only
conducted by designated personnel.
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In response to concern (3), the licensee revised the corporate and site
corrective action programs to require that if a review for potential
generic implications is not required or an organization determines that it
is not affected by a potentially generic CAQ, then a justification is
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provided and a management supervisor approves the justification.
The
approved justification becomes part of the CAQR package. Additionally,
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the program requires that an acceptable response to the corrective action
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plan developed by the responsible organization shall consider any possible
generic implications of the CAQ within the organization (division or site)
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where the CAQ was identified.
If a CAQ is determined to have generic implications, then each potentially
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affected organization receives a request for generic review, and is
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required to provide an internally single coordinated response as to
whether or not they are affected. If affected, the identification number
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of any resulting CAQR shall be included with the response.
If not
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affected, the response shall include a justification which has been
approved by the supervisor of the reviewer. Affected organizations are
directed to communicate with each other in the development of corrective
action plans for generic CAQs to ensure that, when appropriate, such plans
are consistent.
The above program changes satisfactorily address the concerns noted in
this item.
This item is closed.
(CLOSED) Inspector Followup Item (50/260/87-30-05), Surveillance Instruc-
tion Upgrade Deficiencies. This IFI was opened following inspector review
of the evaluation documentation and sis associated with the licensee's SI
evaluation program being conducted under SDSP-2.14,
"Surveillance
Instruction Evaluation". The IFI consists of three subparts in the *.reas
of (1) Independent verification and special tools (thermometers) relating
to four station battery sis (2-SI-4.9. A.2 series), (2) Qualification and
Certification of NDE Level 1 personnel performing Containment Local Leak
Rate sis (2-SI-4.7. A.2.g series), and (3) Method of Conducting Standby
Liquid Control System flow tests per Technical Specification 4.4.A.2.b
(2-SI-4.4.A.2).
Corrective actions taken by TVA in each of these areas
(respectively) is discussed below:
a.
The electrical section had realized the lack of independence in
SOSP-2.14 reviews before the date of the inspections which opened
this IFI.
Their improved, independent evaluation results were
apparently not available for the inspector.
The independent review
and walkdown documentation for the four battery procedures have bsen
reviewed and found satisfactory.
Section 5.0 "Special Tools and Equipment" of each of the four subject
procedures specifies a METTLER/PAAR DMA 35 Specific Gravity Meter,
which incorporates a built-in therraometer.
These findings and reviews resolve subpart 1 of the IFI,
b.
The Containment Leak Rate sis reference procedure SDSP 17.1, "Primary
Containment Leak Rate Requirements" for personnel cualifications.
SDSP 17.1 has been revised to state that "qualification is only
achieved by certification under Area Plan 0202.14, Qualification and
Certification
Program
for
Nondestructive
Examination".
This
procedure modification resolves subpart 2 of the IFI.
c.
The BFNP Technical Specifications, section 4.4. A.2.b were in the
process of being modified at the time this IFI was opened.
The
August 21, 1987, revision to section 4.4. A.2.b now reads in part,
"Verify minimum pump flow rate of 39 GPM against a system head of
1275 PSIG by pumping demineralized water through the Standby Liquid
Control Test Tank".
This Technical Specification revision resolves
subpart 3 of the IFI.
Based on the discussion above, this IFI is closed.
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(CLOSED) IE Bulletinn 86-01, Minimum Flow Logic Problems That Could
_;
4
Disable RHR Pumps.
The licensee's response indicated the condition
~
,
does not exist at Browns Ferry.
This item is closed.
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(CLOSED) Inspector Followup Item (259,260,296/86-32-05), Basis For
Low Scram Air Pressure Trip States That SDIV Instrument Response Time
j
May Be Inadequate. This IFI was based on the inspector's concern in
that TS Nendment Number 125, Section 3.1, Bases, provides unclear
i
information on the function of low scram pilot air header pressure
l
trip.
Review of licensee's correspondence, a letter from TVA
(L. M. Mills) to NRC (H. R. Denton), dated June 27, 1984, and the
-
April 29, 1986 TS amendment request clarified the matter.
The
concern that the SDIV instrument response time may be inadequate as
stated in the TS Bases most likely referred to the Magnetrol float
type of detectors which have been operationally observed to actuate
about 20 seconds after the FCI switches as the Instrument Volume
filled during actual scrams. 'The FCI RTD detectors- are a backup to
,
the Magnetrol detectors for high water level detection, and are not
l
I
mentioned in the subject TS Bases. TVA's real reason for leaving the
-,
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low pressure switches in service is to provide additional redundancy
and diversity in initiating a scram during the fast fill event. This
item is closed.
,
I
(OPEN) Inspector Followup Item (87-13-01), Review of Section XI
'
Surveillance Procedure to Verify SDV Vent and Drain Valve Timing
'
,
Limits are Included.
The inspector reviewed copies of the TVA
Section XI Surveillance Procedures (ISI Pump and Valve testing
program). The October 1987 re-submission of this program to NRC does
,
1
contain all eight SDV vent and drain valves, but does not include
j '
acceptance criteria such as a stroke time limit.
This IFI will
J
remain open until TVA has received approval from NRC on the
Section XI procedure and has developed valve specific acceptance
criteria (i.e., timing limits).
I
(CLOSED) Inspection Report (259,260,296/83-15 Item a), This item
addresses concerns with management control of commitments and
i
assurance of compliance.
The licensee committed to improving their
,
computerized commitment tracking system to provide a program matrices
4
j
system tnat takes an overall, systematic approach to controlling
i
commitments made and implemented in division procedures and instruc-
1
tion, and also provide indicators in plant procedures to identify
steps resulting from NRC commitments and thus preclude the possi-
3
bility of removing commitment items in subsequent revisions.
Review
of the computerized commitment tracking system that the licensee
4
currently employs determined that it is adequate to meet the concerns
l
raised in Inspection Report 83-15.
This item is closed.
5.
Unresolved Items *
i
One new unresolved item was ident;fied in paragraph 13 relating to cold
weather preparation.
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- An Unresolved Item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation or deviation.
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6.
Multi-Plant Action Item B-58, Scram Discharge Volume Capability (TI
2515/90)
The inspector reviewed licensee's actions in response to the scram
discharge volume capacity concern.
Specifically, the inspector audited
licensee compliance with selected criteria taken from the generic Safety
Evaluation Report of December 1, 1980.
Eleven items were reviewed and
its status is provided below.
The presented information is based on
interviews of cognizant TVA personnel, reviews of drawings, procedures and
Technical Specifications, and reviews of related open items.
The status
of related open inspection items 86-32-05 and 87-13-01 is provided in
paragraph 4 of this report.
The items are prefixed with 04 number for
NRC tracking purpose only.
04.01 SCRAM OISCHARGE HEADER SIZE
(OPEN) The inspector reviewed all analysis performed by TVA,
discussed the subject with several system engineers, and had several
calls to Knoxville Division of Nuclear Engineering initiated in an
n tempt to verify adequate Scram Discharge Volume (SOV) system sizing
and proper hydraulic coupling of the SOV header to the Instrument
Volumes (IVs). As of December 18, 1987, TVA was unable to provide a
concise statement or calculations to demonstrate that these criterion
of TI 2515/90 have been met by the re-designed SOV system with its
present scram setpoints on IV level.
Pending receipt of this
information from TVA this item will remain open. NRC review of this
analysis will need to be completed prior to startup of BFNP Unit 2.
04.02 AUTOMATIC SCRAM ON HIGH SOV LEVEL
(OPEN)
Eight high water level instruments are installed, four on
each of the two 50V IVs. Of the four instruments on each IV, two are
magnetrol float type and two are FCI RTO bridge type.
These eight
high level instruments are inputs A - H to the RPS logic and function
in the standard G.E. one out of two taken twice logic. Technical
Specifications Tables 3.1. A and 4.1. A document the East and hest
Scram Discharge Volume High Water Level Scrams.
Although the
criterion for instrumentation is met, the 50 gallon scram setpcint
may need to be re-evaluated as a result of analysis to be perfoimed
with respect to criterion 04.01 (Sizing and Coupling of the SOV
system).
This item will remain open pending re-evaluation of the
scram setpoint.
04.03 INSTRUMENT TAPS NOT ON CONNECTED PIPING
(CLOSED) Each of the four high level instruments described in 04.02
1
above on each IV are on a separate standpipe.
The standpipes
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penetrate the IV and do not directly communicate with the SDV to IV
drain lines.
The "Rod Block" and "Not Drained" instruments are
served by these same standpipes.
This criterion is met.
04.04 DETECTION OF WATER IN THE IV
(CLOSED)
This criterion, as written, applies only to the scram
instrumentation,
not
to
the
Rod
Block
and
Not Drained
instrumentation. Single line plugging would only preclude 1 of the 8
instruments from providing an input to the 1 out of 2 taken twice RPS
logic. The instrumentation connected to each IV is diverse, with 2
FCI RTD type and 2 magnetrol float type detectors.
Power supplies
for the 8 instruments are also diverse.
The RPS channel, detector
type and power supplies are show in the matrix below:
WEST SDV
POWER SUPPLY
DETECTOR TYPE
A
Al
C
A2
B
B1
D
B2
EAST SDV
POWER SUPPLY
DETECTOR TYPE
E
Al
MAGNETRDL
G
A2
F
B1
PAGNETROL
H
B2
Loss of one RPS Power Supply (A or B) to the SOV instruments would
give a half scram signal, leaving the surviving instruments in a 1
out of 2 logic to initiate a scram.
Browns Ferry has the added
redundancy of 4 scram air header low pressure switches which will
initiate a scram in a 1 out of 2 taken twice logic. These RPS inputs
are actuated at 50 PSIG (or greater) air pressure in the header.
These switches are intended to prevent a single failure of one of the
RTD sensors in conjunction with a fast fill event from causing the
SDV to have inadequate free volume to handle the scram.
This
criterion is met.
04.05 VENT AND DRAIN VALVE INTERFACES
(CLOSED) Both of the vent lines on each unit's SDV have high point
vacuum breakers installed. Both the vent and drain lines are routed
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13
to open sumps on the 519 foot level, precluding a pressurized
backfill of the SOV. The inspector reviewed mechanical drains and
embedded piping drawing 47W481-9 to verify that the vent and drain
lines communicate (converge) in their embedded runs.
Therefore the
vacuum breakers serve both the vent and drain lines and preclude
syphoning action from filling the SDV,
This criterion
is
satisfactorily met.
04.06 VENT AND DRAIN VALVES CLOSE ON LOSS OF AIR
(CLOSED) The vent and drain valves are all air operated. They will
close on loss of air pressure (air to open, spring to close) or loss
of control power. A review of Drawing No. 730E915 shows that vent
and drain valve position indication in the control room is from limit
switches, thereby providing actual position indication (versus demand
signal).
This criterion is cet.
04.07 OP9RATOR AID
(CLOSED)
Each of the two IVs has one "NOT DRAINED" and one "ROD
BLOCK" instrument which annunciate in the control room.
These two
instruments (4 total) provide early indication that the IV is
fill' m.
Alarm Response Procedures (BFARPs) Nos. XA-55-6A and
XA-55-Gv
necifv operator actions for alarms associated with these
instruments.
'his criterion is met.
1
04.08 ACTIVE FAILURE IN VENT AND DRAIN LINES
(CLOSED) The current BFNP configuration for vent and drain valves is
as follows:
Each of the two (West and East) IVs has a drain .ine
with two valves in series; thus there are two drain paths, each
having redundant stop valves.
The vent lines tap off the two sides
(east and west) of the SDV (versus off the IV). Each of the two vent
lines has two valves in series.
While a failure of a single vent
valve could isolate (remove) the venting capability of a vent line,
it would not interfere with the isolation function.
04.09 PERIODIC TESTING OF VENT AND DRAIN VALVES
(OPEN) The definitinn of "0PERABLE" under TS 4.3.F does not contain
a quantitative closure time of 30 seconds. The OPERABILITY Surveil-
lance test is performed using BF SI-4.3.F.1.b.
Step A of this SI
only requires the vent and drain valves to be manually cycled (Steps
A.2 and A.3), with no accompanying timing specification (as
recommended by GE).
TVA should consider adding the timing specifi-
cation to the TS (4.3 F'
and the SI (BF SI-4.3.F.I.b).
This
criterion is not fully met because of the lack of a quantitative
timing specification in the TS. The TVA submission to NRC on Section
XI Pump and Valve ISI testing of these valves also contains no
acceptance criteria,
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04.10 PERIODIC TESTING OT LEVEL DETECTION' INSTRUMENTATION
(CLC Ttu,
Browns terry Surveillance Instructions BF SI 4.1. A ' . 8.FT
(#unctional test) and BF SI 4~.1. A - 8 CAL (calibration) test and
calibrate the high water leve! scram, Rod Block and 'Not Drained
instruments on the IVs.
The FT actually tests the float type
switches by filling the float chamber with demineralized water. The-
FT for the RTD type switches injects a test signal to the instrument
loop and does not directly test the sensors. The CAL test for the
float type switches is similer to the FT in that the float chamber is
filled with water and the switch actually cycled. The CAL test for
the RTD type switches includes de-energizing the RTD heater (to
!
verify RTD balance) and filling the standpipe to actually test the.
RTD bridge response. Both the FT and CAL tests have steps to restore
the valve lineups and circuitry to operational mode.
The testing
procram for the level instruments is therefore satisfactory.
This
criterion is met.
04.11 PERIODIC TESTING OPERABILITY OF THE ENTIRE SYSTEM
(OPEN)
Section 4.1.3.1.4
of
the
Standard
Technical
Specifications is where the surveillance requirement relating to this
criterion is addressed.
TVA has not included. this surveillance
(observing vent and drain valve operation and timing during a manual scram) in the equivalent section 4.3.F of the BFNP Technical-
Specifications. Observations of the response time during actual past
scrams _has shown that the magnetrol switches respond about 20 seconds
after the RTO switches. Although TVA has not met this criterion,
consideration is being given to the possible conflict between this
criterion and the current attempts by GE owners to reduce manual scrams.
The final report has not been issued by the BWR Owner's
Group Committee on the Scram Reduction Program. - This item remains
open pending the receipt of the final report and furthcr review by
the inspector.
7.
"War Room" Neeting (30900)
The inspector attended and observed a meeting of Senior Browns Ferry TVA
Managers, Bechtel Managers, Stone and Webster Managers and Ebasco Managers
in what is referred to as the "War Room."
The topics of discussion
involved the inputs from the various contractors into the "P2" planning
and scheduling system, the day to day workings of the "War Room" committee
and the preparation and content of the Level One reports to be sent to the
Director, Nuclear Power Office, and TVA.
The various planning and
scheduling groups arrived to participate in the meeting midway through the
initial discussions.
A free flowing exchange of ideas, information and
questions then took place with each person present being asked by the
Senior Browns Ferry Manager to participate. Numerous items were discussed
as a result of the various topics and comments made by the participants.
Additional War Room committee meetings will be held on a continuous' basis,
and the inspector will attend periodically.
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8.
Operational Safety (71707,71710)
The . inspectors were kept informed of the overall plant- status and any.
significant safety matters related to plant operations. Daily discussions
were held with plant management and various memoers of the plant operating
staff.
l
i
The inspectors made routine visits to the control rooms when an inspector
I
was on site.
Observations included instrument readings, setpoints and
(
recordings; status of operating systems; . status and alignments of
l
emergency standby systems;
onsite and of fsite emergency power sources
available for automatic operation; purpose of temporary tags on equipment
I
controls and switches; annunciator alarm status; adherence to procedures;
adherence to limiting conditions for operations; nuclear instruments
operable; temporary alterations in effect; daily journals and logs; stack
monitor recorder traces; and control room manning. This inspection
3
activity also included numerous informal discussions with operators and
their supervisors.
General plant tours were conducted on at least a weekly basis. Portions of
!
the turbine building, each reactor building and outside areas were
l
visited.
Observations included valve positions and system alignment;
l
snubber and hanger enditions; containment isolation alignments; instru-
'
ment readings; housekeeping; proper power supply and breaker; alignments;
radiation area controls; tag controls on equipment; work activities in
i
progress; and radiation protection controls.
Informai discussions were
,
held with selected plant personnel in their functional areas during these
l
tours.
'
1
In the course of the monthly activities, the inspectors included a review
of the licensee's physical security program.
The performance of various
l
shif ts of the security force was observed in the conduct of daily
activities to include; protected and vital areas access controls,
searching of personnel, packages and vehicles, badge issuance and
retrieval, escorting of visitors, patrols and compensatory. posts.
In
addition, the inspectors observed protected area lighting, potected and
vital areas barrier integrity.
9.
Maintenance Observation (62703)
Plant maintenance activities of selected safety-related systems and
components were observed / reviewed to ascertain that they were conducted in
accordance with requirements. The following items were considered during
this review: the limiting conditions for operations were met; activities
were accomplished using approved procedures; functional testing and/or
calibrations were performed prior to returning components or system to
I
service; quality control records were maintained; activities were accomp-
lished by qualified personnel; parts and materials used were properly
certified; proper tagout clearance procedures were ed.ared to; Technical
Specification adherence; and radiological controls were implemented as
required.
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Maintenance request:, were reviewed to determine status of outstanding jobs
and to assure that priority was assigned to safety-related equipment
maintenance which might affect plant safety. The inspectors observed the
below listed maintenance activities during this report period:
a.
Secondary Containment Inflatable Seals
The inspector reviewed activities involved in the replacement of
inflatable seals ' on the reactor building equipment access . doors.
These seals provide a boundary against secondary containment
in-leakage and were discovered inoperable by a restart test performed
several months ago.
New seals were drawn from Power Stores and
installed.
Procurement documentation was reviewed to assess the
qualification of the seals.
The. replacement seals were ordored and
received in late 1985.
Since the original vendor was not able to
supply the seals at that time, a substitution was obtained and
evaluated.
As part of the evaluation of this substitution, the
design organization evaluated the physical properties and radiation
resistance of the ethylene propylene rubber (EPDM E603) and concluded
that they exceeded the properties of the original neoprene seals.
This conclusion was documented in a memo contained in the contract
files (B22 '85 1213 027).
No further data or references could be
found in the file that would allow an independent review of the
properties such that the conclusion could be confirmed.
The
inspector learned that no further documentation existed elsewhere in
the licenste's files that would substantiate the conclusion.
A
licensee representative stated that they would regenerate the
necessary data and add it to the file.
This will be tracked as an
Inspector Followup Item pending independent review of the data
(259,260,296-87-46-01).
b.
RHR Pump Wear Ring
The inspector reviewed maintenance activitics associated with removal
and replacement of the Residual Heat Removal (RHR) System pump wear
rings on Unit 1, pump B.
Pump failures due to wear ring cracks were
reported in IE Information Notice 86-39.
TVA activities associated
with this problem are documented in LER 86-06 and the Browns Ferry
Nuclear Performance Plan, section 111,7.3.S.
In summary all of the
wear rings on the four Unit 2 pumps have been inspected and replaced
with the original 410 sta nless steel. Wear ring replacements for
the Units 1 and 3 pumps are being made with materiai having lower
hardness.
Mechanical
Main'..>. ance Instruction 16-B, Residual Heat
Removal Pump Rotating Asser % Removal and Replacement, contains the
work instructions.
This procedure was found to be suitable for the
job; however, it did not contain any references to I.E. Notice 86-39,
LER 86-06 or any special notes or precautions which would focus
special attention on the inspection of wear rings for cracking.
The pump manufacturer recommended replacement of the pump impeller
with one having an integral wear ring (one that has a martensitic
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stainless steel wear ring cast integral to the impeller) as a long
term solution to the cracking problem. The licensee considers the
softer wear rings being installed on the Units 1 and 3 pumps to be an
acceptable long term solution and-~ asked the. pump manufacturer to
evaluate this approach.
The ' manufacturer responded that in their
opinion the. softer wear rings would only be acceptable as an interim
fix.
The manuf acturer's response did not change the licensee's
position but plans are being developed to perform a one time
inspection on a single pump after two' operating cycles of operation.
Provided no evidence of cracking is detected on that sample, only
routine pump maintenance would be performed thereafter. Although the
design organization evaluated both the integral wear ring and the
softer wear ring as acceptable alternatives, they pointed out that
several features of the integral wear ring design made it more
desirable than the sof ter ring design.
The plant opted for the
softer wear ring due to the cost advantage and ease of installation ~.
An inspector ' followup item will be opened to track review of this
item by a material specialist in the Office of Special Projects
(259,260,296/87-46-02).
No violations or deviations were observed in this area.
10.
Information Notice 86-81 Review - Main Steam Isolation Valve Springs
(92701)
The inspectors reviewed the results of the licensee program conducted to
determine generic concerns of Atwood Morrill Main Steam Isolation Valve
(MSIV) Helper Springs as noted in I.E. Information Notice 86-81.
During an inspection of all Unit 1 closing assist springs on main steam
isolation valves, an inner spring on 1-FCV-1-38 (Maintenance Request
A 80817) and 1-FCV-1-52 (Maintenance Request A 808823) were found broken.
General Electric Service Information Letter 422 flagged this problem
occurring at other facilities who had Atwood and Morrill supplied main
steam isolation valves. Nuclear Regulatory Commission Information Notice 86-81 also addressed this problem referencing the General Electric Service
Information Letter 422.
Browns Ferry generated a significant condition
report BFN MEB 8606 identifying the problem and committing Browns Ferry to
the visual inspection recommended by General Electric. The inspection
which found the brcken springs was performed to support this commitment.
The spring failure mechanism was quench cracking, which is a brittle
fcilure mechanism expected to occur early in spring life.
In all
likelihood, although unable to be verified, these identified spring
failures occurred early in Unit 1 plant life.
The Unit 1 main steam
isolation valves have mot required closure times and leak rate testing in
accordance with Browns Ferry Technical Specifications throughout the
Unit 1 operating history. A TVA letter dated July 25, 1987, stated that
the inner springs cumulatively contribute 10% of the closing force. Also,
Engineering Report BFN MEB 8606 notes that it would take all 8 inner-
springs to break to aad 1 second to valve closure times, and that an
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isolated spring failure has a negligible effect on valve leak tightness.
Although an isolated inner spring failure represents a degradation in main
steam isolation valve operation, the magnitude .of the safety degradation
has been indistinguishable over time and analytically appears small.
The
General Electric Service Information Letter 422. states if all spring force
was lost, main steam isolation valve closing time .is estimated to- remain
below 10 seconds and for a Mair 3 team Line break unisolated for 10 seconds
offsite radiation doses will still remain below 10 percent of that allowed
by 10 CFR 100.
Unit 2 MS'V inspections have not been conducted to date, but will be
conducted prior to unit startup.
Unit 3 MSIV springs were visually
inspected with no deficiencies noted.
11.
Surveillance Observation (61726)
The inspectors observed and/or reviewed the below listed surveillance
procedures.
The inspection consisted.of a review of the procedures for
technical adequacy, conformance to technical specifications, verification
of test instrument calibration, observation on the conduct of the test,
removal from service and return to service of the system, a review of test
data, limiting condition for operation met, testing accomplished by
qualified personnel, and that the surveillance was completed at the
required frequency.
a.
Standby Gas Treatment System (SGTS)
The inspector reviewed the results of Standby Gas Treatment System
(SGTS) testing required by technical specification 4.7.B.2.a
following the Unit 2 drywell fire of November 2, 1987.
These tests
involved 00P removal testing of the HEPA filter banks; halogenated
hydrocarbon (freon) removal testing of the charcoal filter banks; and
radioactive methyl iodide removal testing of the charcoal filter
banks. The tests were all conducted and evaluated as satisfactory by
the licensee except for the methyl iodide testing which is to be done
by an of f-site laboratory.
The inspector's review of the data
associated with freon testing on SGTS train B conducted on
November 25, 1987, and documented on SI
4.7.B.5,
SGTS Charcoal
Halogenated Hydrocarbon Testing, detected several problems which
invalidate the test. Technical specifications require the test to be
performed in accordance with ANSI N510-1975.
l
This standard requires that the upstream freon concentration be
held at
20 percent of the preset value.
The test conducted on
November 27, 1987, varied up to +240% of the preset value. The ANSI
i
standard further requires that the upstream concentration of freon
tracer gas should be no greater than 20 ppm.
During the test of
train B filters the upstream concentration went as high as 34 ppm and
during the test on train C the concentration went up to 40 ppm. The
inability to hold the tracer gas to 120 percent lead to anomalous
data that fit a parabolic curve as opposed to a normal linear
.
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response.
Failure to conduct the test per' the designated ANSI
Standard is a violation of Technical Specification 4.7.B.2.a
(259,260,296-87-46-03).
b.
As part of the Restart Test Program (RTP) various Surveillance
Instructions (SI) were performed as stipulated in the System Test
Specifications (STS).
The inspector observed- the performance and
reviewed portions of these sis when they were performed as part of
the RTP. The STS 2-BFN-STS-057-1, "125 VDC System," Section 5.5.1,
and Section 5.1 of test 2-BFN-RTP-057-1 require that SI-4.9.A.2.c "DG
Battery Discharge Test" be performed; the STS 2-BFN-STS-057-5, "4.16
KV Distribution," Section 5.5.5.1 and Sections 5.27 through 5.36 of
Test 2-BFN-RTP-057-5 requi res . that SI-4.9.A.3.a "Common Accident
Signal Logic" be performed; in addition, the STS/RTP-082 "Standby
Diesel Generators" require that SI-4.9.A.1.d, "Diesel Generator
Annual Inspection", and SI-4.9. A.4.b, "4-KV Shutdown Board Under-
voltage Start of Diesel Generator" be performed. As a part of the
RTP Test Instructions, each completed SI is to be attached as
appendices to their respective t'ests.
,
No violation or deviations were found in this area.
12.
Reportable Occurrences (90712,92700)
The below listed licensee events reports (LERs) were reviewed to determine
if the information provided met NRC requirements. The determination
included: adequacy of event description, verification of compliance with
technical specifications and regulatory requirements, corrective action
taken, existence of potential generic problems, reporting requirements
satisfied, and the relative safety significance of each event. Additional
ir-plant reviews and discussion with plant personnel, as appropriate were
conducted. The following licensee event reports are closed:
LER N0.
DATE
EVENT
259/83-16, Rev. 3
3-9-83
CREV Charcoal
Sample Efficiency Less
Than Required
259/84-12, Rev. 1 and 2
2-14-84
System Not Available Due
To Valve Failure to Open
259/87-13
7-12-87
Improper
Application of-Radiation
Monitor Detector
Causes Actuation of
Engineered Safety
Features
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LER NO.
DATE
EVENT'
259/87-16
7-11-87
Breached Without
. Required Compensatory
Measure
259/87-18
- 8-7-87
Spurious Actuation
of Reactor Protection
System Circuit
Protector Causes ESF
Actuation
259/87-19
8-6-87
Incomplete
Surveillance
Results in a Condition
Prohibited by Technical
Specification
260/87-08
8-26-87
Personnel Error
Causes Engineered
Safety Features (ESF)
.
Actuation
296/86-11
10-23-86
Technical Specification
Violation From Low
Pressure Coolant
Injection Motor
Generator Set
Coupling Failure
The cause of the CREV charcoal (LER 259/83-16) reduced removal efficiency
was degradation of the stored charcoal prior to use. Replacement charcoal
trays are now filled and sealed by a vendor and come with certification
papers.
The charcoal shelf life is now controlled by procedure TI-80,
Charcoal Shelf Life and Inventory Program.
The Electrical Maintenance Instruction 18, limit and Torque Switch Adjust-
ment for CSSC Motor-Operated Valves (LER 259/84-12), was revised to
improve recording and review of acceptance criteria and data recording of
torque switch settings.
",
_ The radiation monitor detector (LER 259/87-13) was replaced and no further
problems have been encountered.
The electrical maintenance foreman (LER 259/87-16) involved was counseled
on the proper method and responsibility for initiating the breach,of a
The other maintenance foremen were briefed and trained on
1
the above.
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A review of operational events did not identify any condition that could
have actuated the circuit protector (LER 259/87-18).
The event was
attributed to a spurious actuation of the _ circuit protector, and no
further corrective action was planned.
The defective fire hydrant (LER 259/87-19) was replaced and the
surveillance was completed on August 20, 1987.
Personnel error during installation of jumpers (LER 260/87-08) caused a
relay to deenergize and initiate the engineered safety features.
The
personnel involved were counseled on using more caution when performing
similar work in the future.
Restart test personnel received training to
emphasize the identification of potential system actuations in procedures
and in the pretest briefing.
Improper motor to generator shaft alignments and improper coupling gaps
(LER 296/86-11) resulted in motor generator set coupling problems.
Plant
maintenance instruction revisions have been initiated to incorporate the
latest coupling information.
No violations or deviations were found in this area.
13.
Cold Weather Preparations (71714)
The inspectors reviewed the licensee program to protect plant safety-
related equipment from cold weather conditions.
The intake pumping structure which houses the RHRSW/EECW systems piping is
essentially an open structure and therefore subject to the prevailing
'
weather conditions of the area. Design calculations document that during
,
severe weather, freezing, rupture, and subsequent loss of flow could occur
in the stagnant instrument and vent lines located off the RHRSW/EECW
j
system piping. Therefore, some type of protection is required to prevent
this from occurring. As a result, heat tracing and temperature annon-
i
ciation in the control room have been installed.
'
The RHRSW/EECW systems are safety-related as defined in FSAR Sections
10.9.1 and 10.10.1.
Heat tracing is installed in accordance with design
drawings for the pumping station RHRSW/EECW systems to preclude freezing
of the EECW strainer instrument lines and pump discharge cross-connect
-j
lines. The heat tracing receives its emergency backup power Lfrom the
Class 1E 480V Diesel Auxiliary Boards and its failure is annunciated in
the plant control room.
The heat tracing is intended to enhance the
operational reliability of the RHRSW/EECW systens in the sense that the
i
function it performs must be provided or other operational actions must be
taken to prevent imminent freezing should the heat tracing fail during
severe weather.
Additionally, in response to IE Bulletin 79-24 the licensee committe'd to
have the process, instrument, and sampling lines for the EECW/RHRSW
systems at the intake structure and the diesel generator EECW cooling
water lines in the diesel generator building cold weather protected by
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heat trace systems. An annual maintenance program (Electrical Maintenance
Instruction 46) has been implemented to verify system operability.
During an Environmental Qualification walkdown by a licensee Performance
Action Team in January 1987,
the licensee
identified significant
deficiencies Condition Adverse to Quality Report (CAQR) BF 870018 related
to the RHRSW/EECW heat trace systems.
The FSAR safety design basis for the RHRSW system (section 10.9.2, para-
graph 3) and the EECW system (sectio, 10.10.2, paragraph 2) indicates that
this system is safety-related.
Additionally, drawing 37W205-60 RA
illustrates the loss of heat trace can render these systems inoperable,
indicating that the heat trace is important to safety.
The CAQR written by the licensee inspection team noted the following
specific heat trace system (eficiencies:
a.
Splices were made with wire nuts.
b.
Heat trace cables were not terminated.
c.
Conductors were cut.
d.
Cable and conduit had no identification.
e.
Flex conduit had been removed or cut off.
f.
Junction boxes were badly rusted and corroded, and had water standing
in them.
g.
Terminal blocks were badly corroded.
h.
Bend radii of conductors was in question.
1.
Ground conductors were left free.
J.
Terminations were not supported,
k.
Flex conduit was not sealed.
1.
Conductors were terminated without lugs and with oversized lugs,
m.
TVA Management Review Indicated the heat trace system was installed
as a non-critical system; therefore, there was not enougn quality
requirements specified on the design output documents to maintain the
system.
As a result, a general degradation of the system has
occurred over time. EMI - 46, Freeze Protection Program has a lack
of quality acceptance criteria due to the lack of quality standards
in the design output documents resulting in the system being poorly
maintained.
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Corrective action on the above CAQR deficiencies have not been fully
evaluated to date by the licensee.
The inspector conducted a walkdown of the "A"
RHRSW/EECW pump room at the
intake structure and noted an additional heat trace system deficiency not
previously identified.
Plant drawing 37W205-60 requires that each pump discharge heat trace
circuit shall cover the common piping portions. The inspector's walkdown
revealed that for' the "A" pump room the common discharge RHRSW pipe was
not protected by redundant circuits as required by plant design. Other
pump rom.s could not be assessed due to insulation installed or room
accese not available.
This item will remain unresolved pending completion of the licensee
followup evaluation and generic implications as identified by the
inspector (260/87-46-04).
14.
Restart Testing
During this inspection period the inspector attended the 6:30 a.m. Restart
Test Program status meetings on a continuous basis. The inspector closely
monitored the following tests which are currently in progress:
2-BFN-RTP-024 (RTP-024) Raw Cooling Water System
1
2-BFN-RTP-032 (RTP-032) Control Air System
2-BFN-RTP-082 (RTP-082) Standby Diesel Generators
a.
RTP-024 Paw Cooling Systems
The test is in the initial stages and several Maintenance Requests
(MRs) are outstanding involving items such as check valve overhauls.
The test director is performing check valve operability tests as the
MRs are completed.
No significant problems have been encountered.
b.
RTP-032 Control Air System
The test has been in progress for several months and the specific
area being monitored involves sectica 5.4.4 of the System Test
Specification, "Verify that the control air system provides control
air to the large equipment access lock seals at Unit 1."
The
licensee continued to have problems with leaks in solenoid valves,
pressure switches not set properly, and air pressure relief valves
malfunctioning.
The seven day (162 hour0.00188 days <br />0.045 hours <br />2.678571e-4 weeks <br />6.1641e-5 months <br />) test run, using the air
accumulators to keep the door seals adequately inflated was attempted
on several occasions. However, system leaks other than in the seals
themselves, were preventing a successful run. On December 17, 1987,
a successful 162 hour0.00188 days <br />0.045 hours <br />2.678571e-4 weeks <br />6.1641e-5 months <br /> test was completed on the outer doors.
The
'
inner doors continued to have leaks in the system and after repairs
to a solenoid valve a test was attempted starting on December 14,
1987. The seals were maintaining 7 psig or greater at the end of the
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24
test; however, the requirement that the seals be deflated and
reinflated at the end of the 162 hours0.00188 days <br />0.045 hours <br />2.678571e-4 weeks <br />6.1641e-5 months <br /> was not successful.
The
inspector observed the start of the retest for the inner doors
starting at 2:10 p.m.,
December 30, 1987. As a result of.the failure
to meet all the test criteria five (5) MRs were written and disposi-
tioned to repair the various leaks in the system. The new seals did
not indicate leakage. The inspector will monitor the progress of the
test on a continuous basis,
c.
RTP-082 Standby Diesel Generators (DG)
The inspector observed portions of the air start test of DG 3B.
After the coast down of the DG,~ it was observed that the over-voltage
relays appeared to pickup (energize), a start /stop switch malfunc-
tioned, and a kilo volt ampere reactive (KVAR) meter on shutdown
board 3EB did not indicate properly.
Tr.9 test director stopped
further testing of the DG, submitted MRs for the relays, switch, and
KVAR meter.
Testing was not resumed on DG 28 until the MRs were
adequately addressed.
A channel on the Measuring and Test Equipment beng used to monitor
the KVAR of _ DG 3A malfunctioned during the origina test and there-
fore the data obtained initially was not adequate for the Department
of Nuclear Engineering (DNE) to evaluate the results cf the test.
This retest was scheduled to be run on Saturday, Decemt.9r 5,1987;
however, operations personnel were not available to suppor' the test,
therefore the test was reschedu'ied and run on Saturday, December 12,
1987.
On December 29, 1987, the inspector observed the shutdown board 2 EB
Emergency Load Acceptance Test and the Full Load Reject Test of DG
38.
The load acceptance test involved tripping the normal feeder to
shutdown board 3 EB, allowing the DG 3B to start and feed 3 EB, and
verify that the Residual Heat Removal Service Water (RHRSW) Pump C3
was load shed and auto sequenced back on to the 3 EB board.
The DG
output breaker was then tripped af ter the system was allowed to
settle out. The DG output breaker was verified as reclosing with the
RHRSW breaker initially tripping with the DG breaker and reclosing
after the DG output breakers closed.
This test was documented on
Data Sheet 7.22, Pages 11 through 21 of 2-BFN-RTP-082.
The next
phase of the tests was the load rejection test, which involved
opening the output breaker of DG 3B at 2600 KW.
This test was
documented on Data Sheet 7.22, Pages 24 through 26 of RTP-082.
Initial review of all test data indicated that the tests were
satisfactorily conducted.
d.
Multiple Testing
On December 18, 1987, the inspector observed the performance of three
simultaneous tests performed by System Engineers, Operations
Personnel, Restart Test Personnel and additional personnel as needed.
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The tests involved Surveillance Instruction 0-SI-4.9. A.1.b-4, Diesel
Generator "D" Emergency Load Acceptance Test, Restart Test Program
(RTP) Instruction 2-BFN-RTP-082, Standby Diesel Generators, and
2-BFN-RTP-57-4, 480V Distribution System.
The specific section of
RTP-057-4 applicable to this testing was the load Shedding function
of Shutdown Board 2B and associated loads, and the section of RTP-082
was the paralleling of
"D" Diesel Generator with "30" Diesel
Generator.
The perforraance of the SI was observed at
"D"
DG and
portions of the RTPs were observed from the Unit 1 - 2 and Unit 3
,
control rooms. A detailed briefing was conducted in the Unit 1 and 2
'
control room attended by all personnel involved with the tc:t
(approximately thirty) four hours prior to the tests with a followup
briefing right before the test.
Both briefings were very thorough
and questions were solicited from the attendees. The tests appeared
to be successful and the initial review of the data appeared to
indicate that the test was adequate. Personnel involved displayed a
professional attitude about the test and appeared as a whole to have
a thorough knowledge of the tests and test requirements. While the D
and 30 DGs were operating in parallel / load sharing, an operator noted
that the Control Room Emergency Ventilation System (CREVS) was
running. This was initially reported as an inadvertent actuation.
However, on followup review it was determined that when power to
shutdown Board D was deenergized this should have caused the CREVS to
receive a start signal. It was noted that the CREVS were not part of
the SI or the RTP Tests. During the SI/RTP tests action was not
taken to note the status of the CREVS and this may be more of a
deficiency in test conduct and not one of. test acceptability.
As of the end of November,1987, a total of two RTPs, Standby Liquid
Control, and radiation monitoring have been completed; one test, Raw
Service Water was completed and the results were being prepared for
DNE review; two tests, Standby Diesel Generators and Control Air
System were ongoing; and eight tests were in the initial
stages or have been delayed due to equipment modifications, repair or
material availability.
15.
Emergency Procedures (82204)
The Browns Ferry Emergency Plans Manual (EPM) was reviewed. This manual
contains eight events some of which are potential emergencies for which
instructions are written per the Nuclear Quality Assurance Manual (NQAM)
Part II, Section 1.1,
Plant Operating Instructions, Section 3.2.3.3.
These EPM procedures deal with the following situations:
a.
Fire outside the protected area in warehouses.
b.
Oil and other chemical spills.
c.
Spill of radioactively contaminated liquids.
d.
Flood.
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e.
Control room operators threatened by toxic materials.
.f .
Control room abandonment,
g.
Breach of downstream dam.
h.
Four.of the procedures have had no review or revision since July 1983.
One of the procedures which has recently been revised and approved (EPM 2,
Oil and other chemical spills) was left with cutdated information after
the revision.
Emergency phone numbers contained in EPM 2 were wrong or
disconnected.
Responsibilities were assigned to organizational entities
which no longer exist following the rearganization of the Browns Ferry
site several years ago.
EPM 5, Control Room Operator Safety Threatened
by Release of Hazardous Chemicals, indicated that one of the methods
available for detection of toxic materials .was chlorine aetector
annunciation.
Browns Ferry has never had a chlorine monitoring system
for the control room.
EPM 8,
Earthquake Emergency Procedure contains
erroneous statements regarding the seismic qualification of reactor
building basement flood switches.
This procedure also prematurely
requires that the cooling tower vacuum breakers be opened following a low
level seismic event prior to performing a controlled plant shutdown and
even if no damage is sustained either onsite or offsite.
EPM 8 further
i
contains a requirement to perform an electrical check (EMI-90) on the
reactor building basement flood switches as part of the initial response
to a seismic event and this action is highlighted as an NRC commitment
made in LER 86-21.
This item was not committed to in LER 86-21.
These EPM deficiencies were discussed with site emergency preparedness
personnel who indicated that an immediate, thorough review would be
performed on the EPMs and necessary upgrades would be initiated.
Correction of these deficiencies will be tracked as an Inspector Followup
Item (259,260,296/87-46-05).
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