ML20206F231
| ML20206F231 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 04/03/1987 |
| From: | Brooks C, Butcher R, Garner L, Ignatonis A, Andrea Johnson, Patterson C, Paulk G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), NRC OFFICE OF SPECIAL PROJECTS |
| To: | |
| Shared Package | |
| ML20206F193 | List: |
| References | |
| 50-259-87-09, 50-259-87-9, 50-260-87-09, 50-260-87-9, 50-296-87-09, 50-296-87-9, NUDOCS 8704140189 | |
| Download: ML20206F231 (29) | |
See also: IR 05000259/1987009
Text
UNITEj) STATES
>A RE!o('o
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NUCLEAR REGULATORY COMMISSION
j [ REGION ll
3 [j 101 MARIETTA STREET,N.W.
- * - ATLANTA. GEORGIA 30323
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Report Nos. 50-259/87-09, 50-260/87-09, and 50-296/87-09
Licensee: Tennessee Valley Authority
6N 38A Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
Docket Nos. 50-259, 50-260, and 50-296
License Nos. DPR-33, DPR-52, and DPR-68
Facility Name: Browns Ferry Nuclear Plant
Inspection at Browns Ferry Site near Decatur, Alabama
Inspection Conducted: . February 1-28, 1987
Inspectors: S/s OA- _ h or, s//t/o
D' ate Signed
G. L. PaQp, Senior Rydent) Inspector
Gk&d A
C. A. Pat $erson, Resitfent @spector
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Date(Signed
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D6te Signed
C.R.Br, ops,;Residentynspctor
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R. BQtchef, Inspector O
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L. Garnerg Inspector > ( Dhte Sign'ed
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- A. Johnso p Inspector. g D&te/ Signed
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Approve'd by: //d. Mo,7b 9/3/X '7
A. Ignatonis,'Sgttion Chief- Date Signed
Division of TVA Projects
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SUMMARY
Scope: This routine inspection was in the areas of operational safety, mainte-
nance observation, surveillance testing observation, reportable occurrences,
Unit 3 fuel off-load, Configuration Management Program, Operating Instructions
Review, and Commercial Grade Components.
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Results: One violation with three examples was identified for failure to i
adequately adhere to plant procedures. l
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REPORT DETAILS-
1. Licensee Employees Contacted:
H. G. Pomrehn, Site Director
- J. G. Walker,' Deputy. Site Director
G. T. Chapman, Project Engineer
- R. L. Lewis, Plant Manager
- J. D. Martin, Assistant.to the Plant Manager
- J. E. Swindell, Superintendent - Unit Three
- R. M. McKeon, Superintendent - Unit Two
- T. D. Cosby, Superintendent - Unit One
T. F. Ziegler, Superintendent - Maintenance
- D. C. Mims, Technical Services Supervisor
- J. G. Turner, Manager - Site Quality Assurance
- M. J. May, Manager - Site Licensing
- P. P. Carier, Compliance Supervisor
A. W. Sorrell, Health Physics Supervisor
R. E. Jackson, Chief Public Safety
Other licensee employees contacted included licensed reactor operators,
auxiliary operators, craftsmen, technicians, public safety officers,
quality assurance, design and engineering personnel.
- Attended exit interview
2. Exit-Interview (30703)
The inspection scope and findings were summarized on February 13, and 27,
1987, with the Plant Manager and/or Superintendents and other members of
his staff.
The licensee acknowledged the findings and took no exceptions. The
licensee did not identify as proprietary any of the materials provided to
or reviewed by the inspectors during this inspection.
3. Licensee Action on Previous Enforcement Matters (92702)
(Closed) Violation (260/85-25-03) This violation was for a failure to
follow the plant clearance procedure for removing electrical power from
equipment prior to maintenance. The inspectors observed alarm indication
lights illuminated for a motor-generator (MG) which was undergoing
maintenance. Another part of this violation was for having two hold
order tags reversed on the 20A and 2EN low pressure coolant injection
(LPCI) MG sets. The licensee denied the first part of the violation. The
cause of the lights' illumination was from a low voltage (18 volt)
thermistor power supply. The licensee stated it was common practice to
work on a low voltage system " hot". Also, the power supply supplied
another MG which was in service. After discussion with Regional
management, the licensee revised their response still disagreeing with the
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- vio1'ation but with a revision to the hold ' order procedure (BF.14.25). The
procedure was revised to provide a clear understanding of the limits of. a ' ,
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clearance and precautions for energized circuits.
- The licensee admitted the part of the violation for the reversed clearance' ;
tags. Both breakers were removed.at the same time-for testing with the
!. clearance tags . still'.in effect. The breakers- were . inadvertently
reinstalled in the wrong breaker compartments. An operations letter was
47 - issued ~ instructing plant operators not to allow any breaker maintenance on
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any breaker that is part of a clearance. The electrical department
a revised electrical _ maintenance instruction (EMI)-7 to provide second party
- verification for reinstalling breakers -removed from their compartment, i
Also, both of.these. items were discussed in training groups for operations
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and electrical maintenance personnel. The inspector reviewed the-
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appropriate procedure revisions and training attendance sheets. This_ item
i: is closed.
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(Closed) Violation (259, 260, 296/85-25-06) This violation was for failure .
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to adhere to battery surveillance instructions. A review by the inspector '
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- of. completed data sheets for the battery surveillance found that when the
!- acceptance criteria was not met no corrective action was taken, the pilot
- cell voltages and specific gravities were not taken as required, and the
incorrect comparison of battery cell voltages to the average battery cell
voltage -was not completed. The licensee admitted the violation and
determined the.cause to be failure to follow procedure and inattention to
- detail.- All electricians and cognizant reviewers were given training on
these errors. . The inspector reviewed the training attendance sheets -for
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these personnel. Copies of recent surveillance instructions performed - i
were provided and no errors noted. This item is closed, i
(Closed) Follow-up Item (259, 260, 296/84-48-01) This-item concerned
2- inconsistencies between the Technical Specification (TS) Table of Contents
j and Appendix A to Surveillance Instruction (SI)-1. The Table of Contents
E and 'SI-1 referenced Section 6.10, Integrity of Systems Outside
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Containment. This item was not addressed in TS. Amendment Number 78 to
i~ - Unit'3 TS deleted this reference. The licensee in Amendment 128 for Unit
i ~ 1 and Amendment 123 for Unit 2 deleted these references. SI-1 was revised
] to delete the reference to Section 6.10 of TS. This item is closed.
(0 pen) Unresolved Item (259, 260, 296/86-40-10) Control Room Habitability
During a Hazardous Chemical Release. Additional follow-up on this item -
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I identified that the licensee's Engineering Design organization performed ,
- calculations in December 1980, and again in March 198E, related to this
issue. The calculations utilized the approach outlined in Regulatory
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Guide 1.78 Assumptions for Evaluating the Habitability of a Nuclear Power
l Plant. Control Room During a Postulated Hazardous Chemical Release. The
analysis showed that of the chemicals barged past the site, only chlorine
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would affect habitability and that any accident where more than 5 tons of ;
! chlorine is vaporized would cause the concentration in the control room to
exceed the toxicity limit. The December 1980, version concluded that in
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j order to meet the guidelines of NUREG-0737, chlorine detectors should be
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installed in the Browns Ferry control room air intakes. This was based
upon 1978 Army Corps of Engineer Data which assumed that chlorine barge
shipments past the site exceeded 50 barges per year. This assumption was
necessary since the data did not explicitly list chlorine, rather;-
chlorine shipments would have been included in the line item entitled
" Commodity Code 2819, Basic Chemicals" (not elsewhere classified).
Subsequent evaluation of similar 1979 data as summarized in the updated
FSAR, Section 10.12.5.3 concluded that the data "does not indicate that
chlorine is barged past the site". Thus, the licensee justified not
installing chlorine monitors based upon an erroneous interpretation of
data tables even though the data tables continued to show significant
shipments of unidentified chemicals in the " Commodity Code 2819, Basic
Chemicals" (not elsewhere classified). The inspector was informed that
the Analysis and Support Group, Environmental Control, TVA Division of
Nuclear Engineering was to obtain accurate information on chlorine
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shipments past the site and would reevaluate the Reg. Guide 1.78 analysis.
Since the information related to this issue was used by the licensee in
their response to NUREG-0737, TMI-Action Plan Item III.D.3.4, Control Room
Habitability, this item was improperly dispositioned and will remain open
pending resubmittal by the licensee and reevaluation by NRR.
(Closed) Violation (259, 260, 296/84-01-01) This violation was for not
diesel-generator cooling heat exchangers and 12
targeting 16 emergency
residual heat removal - (RHR) pump seal cooling beat exchangers for prompt
corrective action applying the guidance of Engineering Design Procedure
1.48. The corrective action for this violation consisted of replacing all
12 RHR pump seal cooling heat exchangers and installing throttling valves
in the emergency equipment cooling water supply to the diesel-generator
heat exchanges. This work was accomplished under Engineering Change
Notice P0709 and P0083. The inspector questioned the adequacy of the
procedure for design control. The licensee provided current copies of the
The inspector reviewed Nuclear
applicable
Engineeringengineering (design
Procedure NEP) procedure.
9.1, Corrective Action; NEP-6.1, Change
Control; NEP-3.1, Calculations; NEP-3.2, Design Input; and NEP-5.1,
Design Output.
, NEP-9.1 provides for Conditions Adverse to Quality (CARS) as the means to
document any condition which renders an item unacceptable to perform its
required function or which creates uncertainty concerning its ability to
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meet design requirement. These will be documented as either Significant
Condition Reports (SCR) or as a Problem Identification Report (PIR).
NEP-6.1 provides a tie to NEP-9.1 in Section 3.3, specifying that proposed
changes must also be reviewed to the reouirements of NEP-9.1. Likewise,
NEP-3.1, NEP-3.2, and 5.1 are tied to NEP-6.1.
All of these procedures were implemented in 1986. Correction of the
hardware problems corrected the specific problem. Effective
implementation of the design procedures should preclude future mishaps.
This item is closed.
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(Closed) Open Item (259, .260, 296/82-23-04) This . item concerns zone
isolation in secondary containment. At Browns Ferry four zones.make up ,
secondary containment. The three reactor buildings and the refuel . floor
- are the four. zones. Because.of leakage between. zones the licensee has
been unable to demonstrate zone isolation. Zone isolation is not .an .
operating licensee requirement. The only license requirement is to be
able to prove and maintain secondary containment. . Zone isolation aids in
separating the three units.for operational considerations. This may prove
beneficial to the licensee for Unit 2 operation while the- other units
remain shutdown.' However, the licensee has chosen to meet the license
requirements by establishing secondary containment in all zones
simultaneously. . Applicable surveillance testing procedures are available
should demonstration of zone isolation be attempted. This item is closed.
(Closed) Follow-up Item (259, 260, 296/85-57-10) This item was to correct
the methyl iodine concentration specified on a data sheet. The inspector
reviewed Surveillance Instruction, SI-4.7.B 6 Standby Gas Treatment
System Iodine Removal Efficiency. The data sheet listed a concentration
of 0.05 to 0.15 mg/m3 instead of the correct value of 1.5 to 2.0 mg/m3
specified in the laboratory test document. The correct concentration was
used during the surveillance test, however. The licensee supplied a copy
of the corrected data sheet for the inspectors review. This item is
closed.
(Closed) Violation (259, 260, 296/85-28-08) - This was a Technical
Specification 6.2.B.4.e violation for failure to have the Plant Operating
Review Committee (PORC) review unusual events. The licensee admitted the
violation. The two examples in the violation were not recognized as
requiring PORC review. Four plant emergency Implementing Procedures were
revised to require the signature of the PORC Chairman for review of the
events. The inspector reviewed IP-2, Notification of Unusual Event; IP-3,
Alert; IP-4 Site Area Emergency; and IP-5, General Emergency for th
applicable' procedure revisions. This item is closed.
(0 pen) Follow-up Item (259, 260, 296/86-32-05) This item was that in
Technical Specification Amendment Number 125 the reason for the low scram
pilot air header pressure trip was unclear. In Section 3.1, Bases,
page 44, it states that the trip performs the same function as the high
water level in the Scram Discharge Instrument Volume (SDIV) for fast fill
events in which the high level instrument response time may be inadequate.
This trip is unique to Browns Ferry. The description of the Amendment
request states this input to the reactor protective system was installed
as required by NRC Bulletin IE-80-17, Supplement 3, as an interim measure
for improvement of the SDIV capabilities. The interim low scram pilot air
header pressure trip was retained because of problems with the SDIV
instrumentation. Long-term modift.:ations consisted of providing diverse,
redundant, and single failure oroof SDIV level instrumentation. TVA
appears not to have fully complied with the Confirmatory Order to
implement the long-term SDV modifications.
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The inspector . reviewed a ' letter from TVA to H. R.. Denton dated June 27,
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1984,- concerning, various problems of the long-term SDV modification. -The
NRC issued a Confirmatory Order in June 24, 1983, requiring the .
t ._ modifications be completed. TVA stated that TVA complied with the . intent
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of the'various criteria. in the BWR 0wner's Group Design Criteria and the
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t criteria. of the '" Generic Safety Evaluation Report,-BWR Scram Discharge
- ' System" transmitted in D. G. Eisenhut's letter to all BWR Licensees dated i
December 9, 1980. One of the criteria was to. provide diverse, redundant.
and single failure proof SDIV level instrumentation. .The scram ,
instrumentation provides a scram signal if.the level in the SDIV reaches
50 gallons.
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The_ low scram _ pilot air header pressure trip functions perform the same
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protective function as the . existing Scram Discharge Volume (SDV) high
water level: trip. Both . trip functions ensure that a reactor scram is
initiated while sufficient volume remains in the Scram' Discharge Volume.to
! accept discharged water from the control rod drives. For a postulated low
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air header pressure event where the scram outlet valv'es leak but do not '
- fully open,,the rate at which water could.be introduced into the SDV may-
- cause the volume to fill before the high level switches can initiate a t
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trip. The low air header pressure switches provide added protection
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against this scenario.
4 TVA initially installed two Magnetrol- float switches and two Rosemount
i sealed differential pressure (dp) transmitters on each SDV. These four ;
i instruments make up the one out of two taken twice logic for the reactor
protective system. They would meet the diverse, redundant, and single ,
j failure design criteria for the long-term modification. However, the dp-
j switches were replaced with Resistance Temperature Devices (RTDs) because .
[ .of high response times. The dp transmitters could have an actuation time
j to a step change in the SDIV level of-as great as 71 seconds,
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This area was the subject of a previous civil penalty (Reference IE Report
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83-46 and Enforcement Action 84-25). ,
l In addition to the dp switch problems the Magnetrol float switches have a
L time delay of 20 seconds. As part of the long-term modification two
j scenarios were postulated for introduction of water into the SDV during
- power operations. These were excess control rod drive leakage .;
i (approximately 10 gpm/SDV) and fast-fill leakage (approximately 465 '
i gpm/SDV) caused by a degraded control air event. For the fast-fill event
L TVA must rely on the air header pressure switches. Since the air header
j pressure switches were only approved for an interim basis, the long-term
j modification required by the Confirmatory Order apparently has not been
j fully complied with for the SDIV instrumentation. The RPS logic is not {
j met for a fast-fill event using the SDIV level instrumentation alone. The
acceptability of using the air header pressure switches and the RTD
}L instruments to meet this logic has not been previously analyzed for the *
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long-term.
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(Closed). Unresolved Item (259, 260, 296/87-02-03) This item concerns the-
detennination of the reporting of a continuous air monitor,(CAM) that
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failed a low - flow alarm test - during performance of surveillance
, instruction SI-4.8.B.4-3A. The CAM failure was, attributed.to in-leakage.
from a loose orifice flange and a large dead band for the Magnehelic flow
gage. The licensee follows Standard Practice BF-15.2 Licensee Event
Report (LER), in completing a licensee reportable event determination -
(LRED) form to determine if the item is reportable as an LER. If a single
item fails, t.he licensee ' determines if a generic problem exists with
similar equipment.- Stated on the- LRED was that Maintenance Requests
would be written to perform a flow check for each CAM to verify no
in-leakage. The initial LRED for taking the CAM out of service on
January _16, 1987, was updated on January 26, 1987, with the. flow check
requirement so stated. The information obtained from the investigation
was to be used for determining . reportability. . Thirty days after the
initial CAM failure no flow checks had been performed. Accordingly, this
-is a violation for failure to follow BF-15.2 in sufficient detail for-
determining reportability (259, 260, 296/-87-09-01). This is an example
in the violation of T.S. 6.3. Also, no flow checks were made of similar -
Magnehelic flow gages on similar CAMS.
In addition, the inspector reviewed Employee Concerns Program; Item ECP.
86-BF-567-001. This concerns CAM problems and lack of attention of
personnel to CAM alarms. One of the conclusions of the report was that
after about 15 years of continuous daily service, the CAMS are worn out.
They.are in need of a major refurbishment or replacement. Also mentioned
-in the report was that the CAM " lead plugs" were machined but the " shield
sleeve" was not machined; therefore, a good seal was not able to be
maintained which resulted in in-leakage _ (poor _ sample quality). These
facts sustain that a generic problem may exist with the CAMS but was not
adequately evaluated for reportability..
The licensee plans to replace the CAMS in fiscal year 1987. However,
other compensatory measures such as sampling every four hours can be taken
if the CAMS are evaluated to be inadequate.
4. _ Unresolved Items * (92701)
A new unresolved item is identified in paragraph 5.
5. -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 members of the plant operating
staff.
'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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The inspectors made routine visits to the control rooms when an inspector:
~was1 on ' site. . Observations included; instrument; readings, setpoints and
- recordings; status of . operating systems; , status and alignments - of
emergency- standby. systems; onsite and :offsite emergency power.. sources:
" available for automatic operation; purpose ~ of temporary tags on equipment
controls and switches; annunciator alarm. status;-adherence to procedures;
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adherence to limiting conditions for operations;- nuclear instruments
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operable; temporary alterations in effect; daily journals and' logs; sta-k: .
monitor recorder- traces; and control room -manning. This inspection..
activity also included numerous informal discussions with operators and
.their supervisors.
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General plant tours were conducted on at least a weekly. basis. Portions
i- of .the turbine building, each reactor building and outside areas were
. visited. Observations included valve positions and system alignment;
snubber andz hanger conditions; containment isolation . alignments;;
instrument readings; housekeeping; proper- power supply and -breaker;
alignments; radiation farea controls; ' tag -controls on equipment; work '
- activities in . progress; and radiation protection controls. Informal-
discussions were held with selected plant personnel in their functional
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areas during these tours.
Weekly verifications of system status which included major flow path valve
alignment, . instrument alignment, and switch position alignments were :
performed on the electrical distribution, pressure suppression chamber and-
residual heat removal systems.
4 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
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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
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addition, the inspectors observed protected area lighting, protected and
- vital areas barrier integrity,
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i Explosive Chemical Shi.pments
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In the licensee's response to questions proposed by the Atomic Energy
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Commission (AEC) during the initial licensing review, TVA stated that
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there were no barge shipments of explosive chemicals past the Browns
Ferry Plant. As documented in Licensing Question Number 2.3 in the
FSAR, the AEC was concerned with the effect of explosions on the safe
operation of the reactor. Although the licensee indicated no
explosive chemicals or munitions were barged past the site, an
analysis was performed to determine the maximum explosion that the
4 structures could withstand. It was found that the reactor building
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super-structure was the limiting structure and that it could
i withstand a 50-ton TNT explosion at the center of the channel. The
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plant apparently has not maintained an up-to-date analysis of the
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explosive risk since the original licensing issue. The inspector
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noted that Army Corps of Engineer data obtained by the licensee which.
covered - the ' period of 1976 through 1979 clearly showed _ gasoline
shipments of up to 94 barges per year with about 2,000 tons per barge
made during-each of those years. Using the Regulatory Guide 1.91
methodology, this would equate to the equivalent of about 4800-tons
TNT for each barge. This . is . significantly. over the 50-ton limit.
Other. explosive chemicals shipped during the 1976-1979 period include
jet -fuel, kerosene fuel oil, and other petroleum products. The
inspector talked with a licensee representative in the Division of
Nuclear Engineering who is responsible for the Reg. Guide 1.91
analysis who indicated that a re-evaluation would be initiated. This
will be~left as an Unresolved Item (259, 260, 296/87-09-02) until the
potential impact on plant structures has been fully evaluated by the
licensee.
6. 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
service; quality control records were maintained; activities were
accomplished by qualified personnel; parts and materials used were
properly certified; proper tagout clearance procedures were adhered to;
Technical Specification adherence; and radiological controls were
implemented as required.
Maintenance requests 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. RHRSW Pump Maintenance
On February 2,1987, the licensee began making preparations for
removal and overhaul of the A2 Residual Heat Removal System (RHRSW)
pump due to its failure to satisfy surveillance instruction
acceptance criteria. Due to the seemingly excessive maintenance on
RHRSW Pumps during the last several years, the inspector conducted an
in-depth review of maintenance practices on these pumps. A
maintenance history was put together using the Maintenance Request
(MR) computer printout (for data beginning in 1983), the manual
equipment history files (for data prior to MRs), vibration trend
data, and inservice inspection (ISI) records. Several maintenance or
installation practices did not comply with instructions contained in
the vendor manual (Byron Jackson Installation and Operation
Instructions, Type 20 KXH and Type 20 KXL Vertical Circulation
Pumps). These discrepancies may manifest themselves in future
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performance problems:
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1. The vendor manual _ contains a ~ caution that it is imperative that-
the pump shaft' and; column sections be independently supported
during ' lifting operations. ~ Mechanical' Maintenance Instruction
(MMI)-29,_RHRSW Pump Inspection and Maintenance contains no such
precaution and..in fact,. actual practice as ' witnessed during
removal of the A2 pump and as discussed with maintenance
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personnel, is to. lift the pump.by' attaching the rigging to the
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column sections -only and leave the shaft to be supported by the
pump bearings alone.
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2. The_ vendor manual states that a good. grout job is essentialito a
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trouble free installation and warns against the use of ordinary
cement mixtures which can shrink and leave the foundation piece
. insufficiently supported.- Plant practice consists of placing -
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the pump foundation on a concrete pad. Between the concrete
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and the pump foundation on the A2 pump was a deteriorated rubber
gasket. LMaintenance personnel stated that the degraded . gasket '
is not routinely replaced and MMI-29 contains no requirements
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for the use of a new gasket. ,
3. The vendorimanual cautions that the pipe-to-pump flange faces
must be parallel and must. mate without the application of force
to _ permit no strains on the pump nozzle and to provide piping
r supports close to the pump flange to avoid vibration and strain
] on the pump casing. The installed condition is different from *
1- this in that the closest piping support is about 6 feet away.
. This -nearest support performs only a vertical load carrying
- function and is not attached to the floor with anchor bolts.
After the' pipe-to-pump flange was uncoupled on the A2 pump the -
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pipe displaced upward by about 1/2 inch as evidenced by the
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clearance between the support' and its baseplate pad.
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Maintenance personnel additionally indicated that.it is quite
difficult - to align the flange during reinsta11ation of some
i pumps. In a July 31, 1980 letter to the licensee, a vendor-
representative reporting on a site assistance visit stated that
piping strain resulting in undue forces exerted by improperly
- aligned 'and unsupported piping has been detrimental to pump
- performance. The licensee is investigating what if any action
[ was initiated in response to this finding. This will be tracked
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as an Inspector Follow-up Item (259, 260, 296/87-09-03).
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4. The vendor manual states that the pump must hang freely from the
i- foundation and not be forced into alignment with the outside-
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piping; misalignment may lead to vibration and heavy wear on the
! pump. Judging from items 2 and 3 above, this may be the case on
some pumps. This contention is supported by the frequent
baseplate torque adjustments currently being performed by the
licensee's vibration analysis personnel. Excessive vibration
has been corrected by a trial and error method of baseplate bolt
- torque adjustments. This method of adjustment has resulted in
baseplate bolts.for the same pump having up to three different
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torque values. The A3 pump has one-particular bolt which was
torqued to ~0 ft-lbs on November 24, 1986, (refer to MR
- A-706494). This was contrary to the requirements of 21-29,
RHRSW Pump Inspection and Maintenance which requires a minimum
torque value of 15 ft-lbs and has been identified as an example
of the violation for failure to follow procedures (259, 260,
296/87-09-01). This bolt is visibly loose and a perceptible
up-and-down movement of the baseplate at this bolt is visible.
This situation prompted a review of the vibration analysis
program which is discussed in the next paragraph.
5. The packing adjustment procedure described in MMI-29 does not
agree with the vendor manual. MMI-29 starts with packing
leakage about the diameter of a pencil and runs the packing in
to 40-60 drops per minute during a 4-hour run-in. The vendor
manual . has the pump running for 4 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> at operating
temperature'and pressure before beginning the packing adjustment
to a final leakage of a stream of water about the diameter of a
lead pencil.
Although the maintenance history review is not totally comprehensive
due to the difficulty in retrieving the data, some conclusions can be
reached. After about 10 years of operation, all but two of the
twelve pumps have been overhauled. The pump overhaul and/or
reinstallation practices may not be optimal, but these activities
have not yet resulted in an excessive repair frequency. A new trend
appears to be developing in the vibration analysis program with
corrective action being required to reduce vibration on pumps at a
more frequent rate than in the past. Since the implementation of the
vibration program in 1980, 33 adjustments have been required. Ten
have occurred in 1986.
4
b. .RHRSW Vibration Analysis Program
In 1977, the licensee began implementation of ASME Section XI
vibration monitoring requirements. In 1980, the licensee determined
that the location on the bottom of the pump housing near the
baseplate, which was selected for vibration monitoring, was not
. representative of the machine's condition. When representative
monitoring points were selected, excessive vibration levels were
'
. detected. Although the official monitoring point remains the
original non-representative location iur the purpose of satisfying
operability requirements of the inservice inspection (ISI) program,
the licensee has taken action to reduce the vibration at the other
location. The inspector's review of over six years of vibration
data shows that the original monitoring location is insensitive to
various equipment problems.
In an attempt to correct the excessive vibration, the licensee first
E installed a neoprene rubber gasket between the pump base and the
concrete pad. Although this was effective, alignment problems with
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.
11-
the system piping forced the licensee to use another option to reduce
the vibration problems. This option involved a trial and error
method of sequential loosening of the baseplate bolts. This method
was chosen by plant personnel in 1980 who requested that the design
organization evaluate and approve the resulting configuration
particularly with respect to seismic requirements. On September 12,
1980, the design organization approved the fix as a temporary one and
on August 31, 1981, they issued their recommendation for permanent
solution to the problem. A request was made by design for the plant
to initiate a design change request (DCR) to have the permanent fix
installed. Although this request was dated August 31, 1981, no DCR
has yet been initiated. Thus, a temporary fix has essentially become
permanent. This will be tracked as an Inspector Follow-up Item
pending implementation of a permanent correction to the problem (259,
260,296/87-09-04).
7. Surveillance Testing 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. Surveillance Instruction Reactor Building Ventilation
(SI)4.8.8.4-3A Monitoring System Functional
Test
b. SI 4.8.B.4.3 Reactor Building Ventilation
Monitoring System Calibration
Test
c. SI 4.7.B.6 Standby Gas Treatment System
Iodine Removal Efficiency
No violations or deviations were identified in this paragraph.
8. ReportableOccurrences(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
in-plant reviews and discussion with plant personnel, as appropriate, werc
conducted.
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12
o
l The following licensee event reports are closed:
LER No. Date Event
296/86-11 11-21-86 Technical Specification Violation
from Low-Pressure Coolant
Injection Motor Generator Set
Coupling Failure.
260/86-12 10-17-86 Breaker Failure Initiating
Engineering Safety Features
The cause oJ the breaker failure (LER 260/86-12) was a loose internal wire
in the breaker compartment and no further corrective action was required
since a preventative maintenance program on plant breakers is in place.
The cause of the LPCI coupling failure (LER 296/86-11) was attributed to
deficient information on coupling alignment, and plant maintenance
instructions revisions were initiated to incorporate the latest coupling
information. However, the inspectors observed that the licensee failed to
follow Site Director Standard Practice (SDSP) 2.11, Review, Approval of
Site-Generated Procedures / Instructions, when revising Mechanical
Maintenance Instruction (MMI) 157, Inspection, Lubricat*on, and
Replacement of the LPCI MG-Set Couplings and Bearings. S'te Director
Standard Practice 2.11 required that long-term commitaents to
organizations outside BFN (such as NRC) shall be marked to easily identify
the commitment and the text which implements that commitment. When an
entire procedure (such as MMI 157) implements a commitment, it is
acceptable to denote that commitment in the purpose or scope of that
,
procedure. The above requirements were not followed when revising MMI 157
trA is another example of the T.S. 6.3 Violation (259, 260, 296/87-09-01).
This is a recurring problem as indicated by similar concerns in the
licensee QA program (LER QA Surveys QA S-85-1051, QBF-S-86-0028).
The following licensee event reports were reviewed and remain open pending
further review:
LER No. Date Event
296/83-26 5-09-83 Defective Heat Exchanger' Head
259/85-05 3-29-85 Inoperability of High Pressure
Coolant Injection System
259/85-06 4-02-85 Inoperability of High Pressure
Coolant Injection System
I
260/86-01 1-31-86 Inadequate Procedure Leads to
Lapse in Special Requirements for
Use of Temporary Lead Shielding.
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. _ . . _ _ _ - _ _ _ - _ _
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9. Unit Three Fuel Off-load
The inspectors observed Unit 3 fuel off-load to assure regulatory
requirements were met. On February 17, 1987, the inspector observed the
off-loading of Unit 3. The inspector observed the operators were on step
number 451 of the off-load sequence. Step 452 required removal of one of
the 4 fuel assemblies surrounding the "A"' source range monitor (SRM).
The inspector was surprised that four fuel assemblies were not being left
around each SRM to try to maintain the count rate greater than the 3 count
per second operable limit. The inspector questioned the refueling SR0
but he was not aware of any controls to prevent this. The off-load
proceeded and step 452 removed one of the assemblies around the A' SRM.
This concern was immediately brought to the attention of the Plant
Manager.
This same concern.was brought to the attention of plant management during
the off-load of another unit (Reference IE Report 85-43 and 85-44). The
licensee at that time made an interim procedure change to leave fuel
around the SRMs to maintain an indicated count rate greater than 3 counts
per second. Also, the licensee committed to reevaluate the operability
requirement for the SRMs as described in Technical Specification (T.S.)
3/4.10. The T.S. appears ambiguous in that the SRM count rate can become
less than 3 cps while at the same time indicating that the SRMs are
required until the core is unloaded. The licensee committed to change the
T.S. and this item was being tracked on a list of T.S. changes for Browns
Ferry required for Unit 2 startup. This was determined not needed for
startup or fuel off-load of Unit 3. However, in light of the previous
off-load concern, the inspector considered that the SRM concern would have
been addressed during the current off-load. This was not done and was
overlooked by the licensee. Hence, management was not fully involved
with fuel off-load operations as they should have been to preclude
recurrence of the problem described above.
The licensee made a procedura change for the rest of the off-load. SRM
"A" will have only three fuel assemblies around it and the remainder of
the SRMs four during the completion of the off-load. The T.S. change is
still in the review process.
Various observations of the operators in charge of the fuel off-load
indicated the evolution was adequately supervised by the Senior Reactor
Operator and professionally conducted by the fuel handlers.
10. Configuration Management Progran
An inspector continued to review the licensee's ongoing Design Baseline
Program. This program is designed to improve the configuration management
!
system at Browns Ferry by enst. ring that the actual plant configuration is
reflected on plant documents and conforms to the design requirements.
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14
,
The program is divided into two phases: Phase 1 consists of work required
for restart as scoped by the safe shutdown analysis while phase 2 consists
of all post-restart work. As described in inspection report numbers
50-259, 260, 296/87-02, phase 1 is further divided into 5 major areas.
They are: 1) Development of system design basis documents; 2) System
walkdowns by Field Engineering Services personnel (FES); 3) Issuance of
Configuration Control Drawings (CCDs); 4) Evaluation of ECNs and other
potential systems changes (NCRs, SCRs, TACFs, FCRs, and Local Design
Change Requests) initiated since operating license issuance against the
design basis, and 5) Establishment of design baseline for these systems
prior to restart of the associated unit. The design baseline will also be
established for balance-of plant systems, but this effort is not required
to be completed prior to restart (Phase 2).
The first area has been completed in that DNE completed the various
separate Baseline Evaluation / System Requirement Calculation Packages for
those systems that were identified for restart of Unit 2. The separate
packages identified the requirements for the individual systems that are
required for safe shutdown of the associated unit from all anticipated
transients and accidents.
The second area was completed February 10, 1987, when FES completed the
verification walkdowns for those systems that were identified for restart
of Unit 2. Marked copies of as constructed drawings are being provided to
the Computer Assisted Drawing (CAD) Section for input to update CAD. For
the 47 systems involved in the program a total of 550 new drawings will
result. FES has provided inputs (drawing discrepancy packages) to the CAD
section for 125 of these with the remainder scheduled to be provided by
March 17, 1987. Eighty of these have been updated but require checking by
FES prior to CAD issue. Additional walkdown effort will be required due
to recent revision of the safe shutdown boundaries and on a case by case
basis as required to support system evaluation. This work will be part of
the Supplemental Walkdown Program.
The third area consists of issuance of CCDs. The CCD for System 86,
Diesel Air Start System, was issued on October 9, 1986, on a trial basis.
The remaining CCDs are scheduled to be issued by April 1,1987. No
drawings will be considered validated in accordance with SDSP 9.2 until
associated work under areas 4 & 5 is completed, i.e. completely field
verified and design evaluated.
Work under the final 2 areas will be performed by DNE personnel assigned
to the system evaluation section located in Knoxville. The evaluation
process is scheduled to start in April and be complete by June 30, 1987,
and any identified plant modification work to be completed during the
second half of 1987.
The inspector reviewed the unissued CCD, drawing discrepancy package and
performed a limited walkdown on selected portions of System 23, RHR
Service Water. The inspector noted that a major portion of the system
located in the pumping station was marked on the CrD as not verified.
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This portion include'd 11'of 12, pump motors, pump discharge piping, various
_
valves, and motor operated strainers. The stated reason for not being
verified was due to presence of insulation / heat tracing. . Pump motor-D1
4- was not included within the portion meaning that it was verified yet all
'
motors are uninsulated and easily accessible. Additionally, all pump
shafts were included in the verified portion even though the shafts are
not accessible.
The inspector noted the presence of several other portions of System 23
and other systems that were marked not verified on unissued CCDs. The
issued CCD for. system 86 contains portions marked as not verified. -The
inspector determined from discussions with various licensee FES and CAD
section personnel that. this condition is quite common. In most cases
these are due'. to ongoing maintenance work, physical location. (buried,
underwater) or various other problems associated with the particular-
components.
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The inspector noted that in some cases the safe shutdown analysis boundary
did not always include the entire portion of a particular. safety related
system. This results in portions of that system not being walked down.
,
Some of the systems such as the main steam system are not being verified
- 100%. The enly portion being verified is the safe shutdown boundary. The
inspector re. viewed a 128 page associated drawing package to determine
jl this boundary. This package is termed the system calculations for the
!- main steam system. Each system has a system calculation package. The
j preliminary CCD for this system has sections of the system cross-hatched
- on the drawing indicating that portions are'not-verified. Additionally,
many drawings contain interfaces with other systems that are covered by
, other drawings (out of scope). The inspector was informed that these
- boundaries would be clearly defined on the CCDs with a series of
l dot-dashes. However, the inspector noted that these boundaries were not
,
clearly defined on the issued CCD for system 86 where it interfaced with
'
i system 82 and no marked boundary existed .to warn a drawing user that
- portions of the CCD were not verified. Due to no apparent plan of
removing these unverified portions from the drawings an inspector followup
'
item will be opened, (260/87-09-05). The licensee is addressing this
j issue.
As stated in SDSP 9.2, Configuration Control Drawings (CCDsi, section
4.13, issued CCDs will be stamped as validated after complete field
i verification and design evaluation. The inspector was informed by
baseline personnel that some drawings will be marked as only being partly
. validated and that the drawing will be clearly marked to define the
associated boundaries. Since no CCD validation has yet occurred, the
'
inspector was unable to inspect in this area. This condition could lead
to confusion or misinterpretation during drawing usage. The inspector
a
intends to look at the validation process in the future and this item will
j betrackedunderanInspectorFollow-upItem(260/87-09-06).
i The results of the baseline program should be very good for the purpose of
i supporting design requirements but not good for supporting operations.
-- . . - - .---.. -.. . . - - - _ - _ -- , _ _ _ _ - - _ . , _ , _ _ , _ _ -
_ _
16
This appears to be due in part to a lack of communications between the
operations section and the baseline groups resulting in confusion over
what operations needs.
a. Field Walkdown Observation
On February 5,1987, the inspector observed the performance of a
mechanical system walkdown. The second walkdown with 100% quality
control verification was being performed for the' raw service water
and fire protection system in the security lighting diesel generator
building. Plant drawing 67-M-0-47E836-1 R000 was made after the
first walkdown of the system. No drawing existed prior to this. The
system mixes raw service water and foam to supply six sprinkler heads
in the room. Thirty valves are in the system.
The person from the Field Engineering Services (FES) hung the system
drawing on the wall and traced the system out using different colored
markers on the drawing. At the same time a Quality Control (QC)
person marked up another copy of the drawing as the walkdown
proceeded. Although the QC person was stated to be performing an
independent verification, the walkdown was actually a team effort.
Both of the persons were contract personnel and not TVA employees.
The applicable plant procedures for the process are as follows:
SDSP 9.6 Mechanical and Instrument and Controls System
Walkdown
QCI 10.5 Verification Walkdown
BF-8.11 Fabricating and Installing Plant Valve and
Component Identification Tags and Labels.
During the walkdown each valve identification label was checked
against a design mechanical valve marker tag tabulation. Any
difference was noted as requiring a new identification valve. Of the
thirty valves all but two required new labels. Most of the new
labels were required because of differences in punctuation. The
example below shows this:
0-26-1472 Shown on valve
HPFPS-ISLN-SDV identification tags
0-26-1472 Shown on valve marker
HPFPS ISLN SDV tag tabulation
This valve was identified as needing a new identification label. The
process of changing all the valve "dentification labels because of
differences due to dashes will be very manpower intensive. It is
debatable if this is needed for restart of the Unit. Corrnction of
the identification labels is a startup item for Unit 2 by the
licensee. Since there was no designation of why a label needed
_ - --_ __ ____-
.- .. - - - . .- . .. . -- -. . _.
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replacing all of the-labels will have to be ieplaced prior to restart
although most labels are being corrected due to dashes.
" Ten other errors were noted that'were not previously shown after the
first walkdown. These errors were pipe. penetration errors, drain
,
lines, and pipe size. The number of errors for this. system could be
- ' attributed to. not having an original drawing of the system.. 'The
>
first walkdown was actually construction.of the system drawing.. The-
~' system drawing was not verified to be correct prior to the second and
final verification walkdown.
. The inspector observed that . the fire protection system was 'not
'
aligned for standby readiness for either manual initiation or. .
automatic initiation. Diesel fuel odor-was evidentiin the- room and
the fuel oil. day tank located in_ the room indicated full. 'Also, two
fire extinguishers located in the building did not have the monthly
inspection label attached to them. One ANSUL extinguisher was hot to
1 the touch due to a six foot portable electrical -heater located next
t to it.
The diesel generator (DG) was noted to have a hold order tag,
84-1233, dated in 1984. The DG starting battery frame contained -
i holes for. securing the battery to the floor but no bolts were in the
, holes. The DG mounting frame bolts were all loose. Discussion with
the Plant Manager indicated the DG was required for Unit-2 restart.
All .of these concerns were discussed with ' the Plant Manager on
i February 5,1987. _The fire protection concerns were discussed with
,
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the fire protection' supervisor. Resolution of the mounting concerns
and fire protection concerns will be tracked as an Inspector
Follow-upItem(259,260,296/87-09-07).
b. Quality of System Walkdowns,
In discussion with the walkdown personnel .all of the activities' are
described as before or after the Corrective Action Report (CAR).
Initially after all of the systems had undergone a first and second
walkdown, Quality Control reviewed the work and found major problems.
] A CAR (BF-CAR-86-0119) was written which stated that: (1) Contrary
- to the requirements of 10 CFR 50, Appendix B and Site Director's
.
Standard Practice (SDSP) 9.1, sufficient records of mechanical
walkdowns have not been made and maintained; (2). Contrary to the
,
requirements of SDSP 9.1 Appendix A, drawing discrepancies have not
i been identified. ThU CAR was initiated on July 11, 1986. The CAR
- resulted from a survt. formed on seven systems.
j. As a result of the CAR all systems have undergone a third walkdown
I with 100% Quality Control (QC) verification. -The inspector
i questioned if any QC inspections were being conducted on the third
j wal kdowns .
.
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. _ _ _ . . . _ _ _ _ . . _ . _ _ _ _ _ _ _ _ _ _ , , __.. _ _ n__._ _ _____
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18
After the second walkdown, the system drawings were redrawn using
computer aided drafting (CAD). Due to the large number of errors
found by the CAR and redrawing the system with CAD the third walkdown
was similar to an initial walkdown. QC had sampled some of the third
walkdown but most were just now being completed. No CARS have been
initiated to date but several discrepancy reports (DR) have been
initiated. The . inspector reviewed the DRs and found no major
problems to invalidate the whole program such as the CAR. DRs are
discrepancies of less significance than a CAR.
Follow-up inspections will be preformed to ascertain the quality of
third walkdown verifications.
10. Operating Instructions Review
.The inspectors reviewed Operating Instructions for Unit 2 which have been
through the procedures upgrade program except for 01-84 which has been
through the plant walkdown and technical review program. The inspectors
found numerous examples of instructions that were misleading, unclear or
needed more clarification to ensure correct operator actions. The
following Instructions were reviewed by the inspectors:
Operating Instruction (01)-84, Containment Atmosphere Dilution
Operating Instruction (01)-32A, Drywell Control Air
. Abnormal Operating Instruction (A01)-32A, Loss of Drywell Control
Air
Operating Instruction (01)-63, Standby Liquid Control
Operating Instruction (01)-82, Standby Diesel Generator; Units 1, 2.
Some examples of problem areas were:
a. Labels on instruments or controls were different than that used in
the instruction. Some components are misidentified and/or mislocated
from the instruction requirements.
(1) Paragraph 7.1.3 of 01-32A states to place control switch
2-HS-32-64 (67) in STOP. The control switch is labeled
(2) Attachment 1, page 3 of 01-32A lists the required position of
the breaker as " closed". Typically, breakers are labeled 0FF
and ON.
(3) Attachment 1, of 01-63, electrical lineup checklist describes
the standby liquid control (SLC) pumps as 1A and 18. In the
Unit 2 procedure these should be 2A and 28.
(4) Attachment 3 of 480V Diesel Aux Board B lineup, lists diesel
generator C battery exhaust fan breaker number as 4C. It is
actually 4B. Also breakers 3C, 3D, and 3F refer to diesel
-
.
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19
generator A.on.this board. These are actually associated with
diesel _ generator D.
b. Drawings used symbols that are not defined on the symbols drawing for
BFNP (47W801-1 and -2). Some operators were notfaware of what the
symbols meant.
(1) Drawing 47W610-32-2,' Revision 1 has anlX beneath FCV 32-62 and
- 32-63. Also, two large dots are on the right side of the valve
symbol,
c. Instructions referenced. incorrect procedures or non-existent sections
of procedures. Also, incorrect instruments / controls ar'e referenced;
~
(1) Paragraph 2.3.2 of A0I 32A references Alarm Response Procedure
(ARP) XA-55-208, window 32, Panel 9-20. Operator action 2.a
references El-32-30 but the instrument is labeled PI-32-88.
'
.(2) ?aragraph 2.1 of A01 32A references ARP XA-55-3E, window 'h5,' l
Panel.9-3. Operator action 3 refers to 01-32A.V. There is no
section V'of 01-32A.
'(3) ARP procedures LA-63-1, EA-63-8, TA-63-3 and EA-63-2 referenced
the abnormal section of 0I-63. The upgraded 01-63 has no
abnormal sections. ,
(4) Paragraph 4.2.1 of A01 32A refers to abnormal instruction 01-32,
Ventilation Systems Isolation (Group VI). The correct abnormal
instruction is 01-30.
(5) Paragraph 4.2.8 of A0I 32A refers to G01-100-12, the section for
" Shutdown by Manual Scram". There is no separate section of
l G01-100-12 by that title. The action is covered under the
section " Normal Shutdown".
t (6) Paragraph III.C.1 of 01-84 states tank level is indicated by
A LI-84-2A and 28. It s'iould reference LI-84-2A and 13A.
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l (7) Paragraph III.D.I.c of 01-84 references keylock switches
L i HS-84-8A/B and tis-84-8C/D. These handswitches are not keylock
q switches.
(8) Paragraph III.D.2, Note of 01-84, states to maintain tank
pressure using PI-84-1 (tank A) and PI-84-12 (tank B). PI-84-1
- and 12 are vacuum instruments and'do not measure tank pressure.
a *
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(9) Attachment 1 of 01-82 lists valves 0-86-534A through 538A and
, , 0-86-524A through 527A as being associated with AC/DC
'
compressor. In fact these are associated with the AC powered
compressor.
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.-. -
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L. d.: -Instructions? direct operators to -perform ~ control manipulations or
.
-read instruments on panels by panel number. Some instruments _and
controls are.only on Unit .1 panels .but the procedure -does not state
5 this. . Also locations provided'may be inaccurate orinot helpful in
- locating,a device.'
'
,(1): . Paragraph III.D.I.d' of 01-84 checks FI-84-7. and -18 on panel
-
9-54 (9-55)'. FI-84-7 and -18 are only .on Unit 1 panels 9-54.
f. .-(9-55) . This also' applies'. to the .following instruments
Ldiscussed in this procedure:
1:1-84-2A and '13A
"i PI-84-3A and 14A'
TIN 4-27and28
. ,
PI-84-6 and 17-
(2) . Paragraph III.D.1.b of 0I-84. states . to open FCV-84-5/16 using
handswitches HS-84-5A/16A on panels 9-54 and 9-55. Handswitches
HS-84-5A/16A are only on Unit 1 panels -9-54 and 9-55.
(3) Attachment 3 of 01-82 provides the location of Battery Board 250
DC as being on' elevation 593 of the reactor building. It is
actually 1ocated on' elevation 586 of the . Unit ~3 turbine
building.. The 120V plant preferred panel 9-24 is specified to
be.-in the reactor building. In fact the desired panel is = in
control . bay 3C. Breaker 1134 of Battery 1 Board 3 48V DC is
,
listed as on panel 24-41C. Actual location is panel 25-41C.
,
The, location of the 48V DC . boards could be better- specified.
~ For example, Battery Board -1 48V DC'could be specified as the
back side 0* Battery Board .1250V DC on' elevation 593 of the
reactor bifilding.
-(4) Attachment 2 of 01-82 lists the Compressor. B 250V DC backup
. motor ON-OFF switch as being located on the diesel generator
engine control cabinet. .It is actual across the room on the
wall-behind the air compressor. -
(5) Paragraph' 4.1.15 of 01-82 positions a fuel oil selector lever.
The procedure can be enhanced in order to aid the / operator in
'
physically locating the lever by inserting the word " 'strainer"
, before the words " selector lever."
s
3
e. Instructio'ns list parameters the operators: should monitor but some
significar.t parameters are not listed.
(1) Paragraph II.C of 01-84 should also reference maintaining oxygen
concentration below 5 percent.
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(2) Paragraph III.D.1.e of 01-84 should require monitoring of Torus
p Pressure and Oxygen Concentration also.
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(3) Emergency Operating Instruction (E01) 2, Primary Containment
Control, page 12 states to vent with the CAD system only when
the temperature in the , space being evacuated is below 210
. degrees F. 01-84 does not list this precaution even though
E01-2 references 0I-84 for venting.
f.. Instructions direct operators to take certain actions or if needed,
desired or- appropriate. More guidance is needed to ensure adequate
actions are taken.
(1) Paragraph III.D.1.f of 01-84 states to use containment spray if
needed or desired to promote Nitrogen mixing. Operators should
have guidance on when to use containment spray.
(2) Paragraph IV.A.2 of 01-84 states to check. tank heater in
automatic and operating properly. Guidance is needed on how
operators are to determine heater is operating properly.
(3) Paragraph IV.B.3. of 01-84 states to check the flow controller
for proper operation. The previous issue of 01-84 had detailed
instructions on how to commence venting that has been deleted.
More guidance should be given.
(4) Paragraph III.D.2.a(8) of 01-84 states after delivery of 1000
gallons,-start transport liquid pump at minimum rate. Guidance
is needed on what minimum rate means and what is acceptable.
(5) Paragraph 4.1.13.1 of 01-82 checks diesel generator lube oil
reservoir level is normal. Amount below " Full" mark on
dipstick which would be considered acceptable is not specified.
Two operators were asked. One indicated 3 inches; the other
indicated 10 inches.
(6) Paragraph 4.1.13.2 of 01-82 checks diesel generator lube oil
temperature is greater than 85 degrees F. Instrument,
TI-82-20A, which is used for this check is not specified in the
instruction.
(7) Paragraph 4.1.16.2 of 01-82 checks speed set adjust set at
maximum. Instructions should be provided on how this is to be
accomplished. For example, one method if the setpoint is not
known; is to use the engine panel governor control switch to
raise the setting to the upper stop. The procedure does not
specify a maximum speed set setpoint. ,
(8) Faragraph 6.2.6 and 6.2.7 of 01-82 says to monitor pressure
indicators for fuel system 1 and 2 filter in, lube oil filter in
and lube oil engine and temperature indicators for vater
,
temperature in, out and oil temperature. Neither 01-82 or the
l instruments installed in the field indicates what woJ1d be
abnormal values. A surveillance check sheet specifies the
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values but it is not referenced.
(9) ' Paragraph 5.1.3.2 of.- 01-82 checks- that the diesel generators
reach " proper loading" as they supply equipment powered ,from
. assigned board. " Proper loading" needs to be clarified as to
'what it means and how it can be verified, e.g. what parameters
on what' instruments.
(10) Paragraph 6.1.10 of 0I-82 . increases real load- on diesel
generator by adjusting generator control ' switch .to obtain
desired KW load. Under abnormal conditions various combinations
of KW loads could be on the boards, e.g. the desired KW load may
not be readily- known. In practice, 'this would most likely be
accomplished on a non-paralleled system by verifying. or
adjusting the voltage to the nominal value, which is -a known
value.
(11) Information note in section 5.1 of 01-82 indicates .three
permissive conditions for a diesel generator output breaker to
automatically close.. Two conditions, diesel greater than 870
RPM and no supply breaker over-current lockout exist, cannot be
determined from the control room. . Instructions are not provided
as to the location to obtain the status of these items.
(12) Paragraph 6.1 of 01-82 provides instructions for diesel
generator feed to a shutdown board. . These are for parallel
feeding to an already energized board. Instructions for feeding
a dead bus are not- specifically detailed. Furthermore, no
caution is provided to verify that the energized board is stable
and not undergoing abnormal- frequency or voltage transients
prior to paralleling a diesel generator to the board.
(13) Paragraph 6.1.7 requires adjusting the diesel generator speed
until the synchroscope is rotating slowly in the clockwise
, direction. An approximate number of revolutions per minute
should be specified.'
- . (14) Information Note in section 5.4 of 01-82 states that HS-82-1
should be used only during an emergency situation. No
i explanation is provided as to why this is the case. Guidance is
not provided to describe under what circumstances it should be
used.
l (15) Paragraph 8.1 of 01-63 does not provide for flushing of the
piping associated with the relief valves after injection of the
,
standby liquid control system.
(16) Paragraphs 8.4.3-8.4.6 of 01-82 provide two different methods
of emergency shutdown of a diesel generator. This is not
- clearly stated in the instruction. In fact, the numbering
format implies only one method is provided.
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g. Drawings and instructions do not agree.
(1) Paragraph IV.B.1 of 01-84 states CAD system outlet valve
(FCV-84-19 or 84-20) isolates. Both FCV-84-19 and 84-20 should
isolate.
(2) Paragraph IV.C.1.a and b of 01-84~ states to check valves locked
open. Drawing 47W862-1 does not require -these valves to be
locked open. This is typical of all locked valves in the valve
lineup sheets.
(3) Instrument inspection list in 01-84, page 16 and 17, list
FIC-84-20 on panel 9-54. FIC-84-20 is located on panel 9-55.
(4) Drawing 47W862-1, Revision 1 shows relief valves 0-84-136 and
138. No setpoints are specified for these relief valves.
h. Instructions are inconsistent between similar applications between
components and as to what is specified or verified. Also different
language is used to perform identical tasks.
j (1) Attachment 2 of 01-82 requires the synchroscope switch to be
l "0FF" for all four 4KV Breakers associated with three of the
'
diesel generators, however, only 3 of the 4 are required to be
"0FF" for the other diesel, e.g. synchroscope for 4KV Breaker
1818 is not on checklist.
'
(2) Attachment 1 of 01-82 requires some of the diesel generator air .
isolation valves to be locked open while others'are specified as
open. For example, valve D 0-86-540 on diesel generator D is
specified as open while the similar valves 0-86-540 A, B and C
associated with diesel generators A, B and C, respectively are
specified as locked open.
(3) Attachment 4 of 01-63 requires the drain valve to be sealed
closed for 2-PT-63-7 B. However, many other instruments have
their drain valves sealed closed but are not verified as such.
For example, this instrument supplies a local pressure
indication. The similar pressure indicator, 2-PT-63-7, which
supplies the control room indication is sealed closed but not
verified. No justification for this discrepancy was provided by
the procedure writer.
(4) Paragraph 8.1.13 of 01-63 specifies stopping the A standby
liquid control (SLC) pump by using control switch 2-HS-63-68.
Paragraph 8.5.15 which performs the same task, stopping pump
"A", does not specify the hand switch number.
(5) Paragraph 6.1.5 of 01-82 requires the diesel generator
operational mode selector switch be " PULL UP" to engage the
appropriate circuitry. Paragraph 7.1.4.6 and .7 does not remind
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the operator to " PULL UP".
i. The Final Safety Analysis Report (FSAR) and the instructions or
drawings do not agree.
(1) 01-84, Electrical Component Checklist references Board 1C for
CAD system A Nitrogen heater panel 25-246A and Board 3B for CAD
system B Nitrogen heater panel 25-2468. FSAR 5.2.6.2 states
MOV Board A supplies the heater in Train A and M0V Board B
supplies the heater in Train B. It appears the FSAR is in
error.
(2) FSAR 5.2.6.2 states the nitrogen storage tanks have a capacity
of nominal 4000 gallons each. Drawing 47W862-1 states each
nitrogen storage tank has a capacity of 3000 gallons.
j. Valve Lineup Checklist attachments do not list valves in most
convenient order to perform lineup.
(1) Attachment 2 of 01-63 has the operator go from one of the A
standby liquid control (SLC) pump to the other side of the B
pump and then back again to the A pump.
(2) Attachment 1 of 01-82 has the operator check a valve on one side
of the diesel generator and then one on the opposite side and
back again.
Observations of other problem areas include the following:
a. The Containment Air Dilution (CAD) local control and instrument
panels for CAD Nitrogen tanks were rusty, full of debris and
contained cut electrical leads laying loose.
b. Paragraph III.D.4.b of 01-84 states to close FCV-84-5 and 16 using
handswitch HS-84-5A and 16A. HS-84-5A and 16A were in the "Close"
position and FCV-84-5 and 16 still indicated "Open". Operators could
not explain why.
c. The inspectors obtained the latest copy of 0I-84 from document
control. The document was approved by PORC on January 30, 1986.
During the inspectors review in the control room, the control room
copy of 01-84 was approved by PORC on January 13, 1987. Document
Control issued an out of date procedure to the inspectors.
d. Manual valves with external position switches in the SLC system are
verified in the valve checklist of 01-63 as being in their correct
position by their remote indication on the control board. The
inspector discussed with the licensee the inappropriateness of this
type of verification after extensive maintenance on the system or
return to service after a refueling outage. The licensee indicated
that they had already identified this and changed 01-63 to specify a
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h'a nd-on verification. -
e. ARP TA-63-3, Standby Liquid Control Temperature Abnormal,.a'nnunciatort
' procedure states that: the low temperature alarm setpoint is 75 :
' degrees F. -If this is correct, then Procedure BF-TI-18 and.BF-SI-4.4-
could allow concentrations of sodium pentaborate and temperature
outside of ' Technical Specifications ' before ' the temperature alarm
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.would come in.- The inspector noted that SI 2 does daily checks when-
the system is operational which verifies compliance with Technical-
Specifications limitations. .The licensee should: consider adjusting
the alarm setpoint to totally bound the Technical Specification
allowed values.
~
f. The inspector observed that shutdown board in Units 1 and 2 had one
breaker compartment labeled as "3A core spray". Also shutdown board
I has controls for diesel generator B which are labeled and appear
operational. The ' inspector was informed that this equipment was
never made operational or was spared. Such labeling of spared
equipment could cause unnecessary confusion during an accident
situation,
g. The inspector observed that shutdown board I had the red targets
showing on all three under-voltage devices and on two of the three
over-voltage devices. The shutdown board was energized at the time.
Apparently, personnel are not resetting the targets on their normal
rounds.
Each discrepancy noted above, taken individually, would not make the :
instructions unworkable but, due .to the numerous discrepancies identified
-by-'the inspectors, the Operating Instructions have not reached the level
of improvement intended by the procedures upgrade program. The inspectors-
feel the procedures upgrade program must be improved in order to obtain
procedures that will be acceptable to the licensee or the NRC for reactor
cperations. This program will be followed as Inspector Follow-up Item
(50-260/87-09-08). ,
11. Commercial Grade Components l
In order to establish tighter controls on the use of commercial grade
components without proper dedication documentation and to augment existing
material controls on items in safety-related applications, the licensee
established the following guidelines:
a. No safety-related items that have been issued by Power Stores without
specific designated applications (shop spares) shall be used. Each
site shall ensure that shop spares for safety-related applications
are -eliminated by returning to Power Stores all safety-related shop
spares including consumable and bulk items. Satellite stores under
[, Power Stores' administrative and procedural control may be
l established to accommodate expeditious issues of safety-related
l
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Shop spares for nonsafety-related applications may be maintained in
- secured areas and issued in a controlled manner only if adequate
,
controis are implemented to prevent their use in safety-related
applications.
Consumable and bulk items. shall be procured to the highest quality
level, unless specifically approved by appropriate site management on
a case-by-case basis,
b. Each site shall establish .a conditional release 1 program for all
Quality Assurance (QA) Level II items (commercial grade items used in'
safety-related application).. This conditional release program shall
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be structurednto permit these items to be issued and installed ~ prior
to evaluation of the adequacy of the . dedication process for that:
_
item. All safety-related items must be tracked from Power Stores
issuance to their specific application. Each conditional release of -
material shall be made only with the written approval of the- site -
director with copy to the site manager of QA.
c. P.rocurement -of QA' Level II items shall be pennitted only with an
acceptable dedication process. The dedication process shall be
defined and ' documented at' time of purchase requisition' preparation. .
Any item for-which an acceptable dedication process cannot be defined
at time of purchase requisition preparation shall be procured as QA
Level I (safety-related),
d. Each site shall establish an item evaluation group consisting of
. appropriate personnel from Division of Nuclear ' Engineering,
Environmental Qualification Project, and QA to accomplish the
following activities:
(1) Evaluate previously installed QA Level-II items. Any item that
upon evaluation is found to be lacking sufficient data to pennit
dedication will be documented on a Condition Adverse to Quality
(CAQ) ' and tracked through closeout. Items with sufficient
documentation will be dedicated, and the dedication documents
maintained as permanent QA records.
(2) Evaluate QA Level II items that are conditionally released.
Power Stores shall forward all copies of form TVA 575 to the
evaluation group. Any item that upon evaluation is found to be
lacking sufficient data to permit dedication will be documented
on a CAQ and tracked through closecut. Items with sufficient
documentation will be dedicated and the dedication document will
be maintained as permanent QA records.
(3) Evaluate existing Power Stores inventory of QA Level II items
and returned shop spares. Evaluation of items currently in
inventory and shop spares shall be performed to determine if-
documentation exists that permits dedication to a known specific
application. Any item that cannot be dedicated upon evaluation,
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either dueto unknown application or insufficient' data, shall be
redesignated for use in nonsafety-related applications.
(4) Define proper QA level of safety-related = items prior to
procurement.
(5) . Define the dedication process for QA Level II items prior-to
procurement.
Follow-up inspections will be scheduled in this area to evaluate the
implementation phase of this program.
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