IR 05000445/1989017
| ML20245H170 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 04/24/1989 |
| From: | Bitter S, Burris S, Joel Wiebe Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20245H148 | List: |
| References | |
| 50-445-89-17, 50-446-89-17, IEB-79-21, NUDOCS 8905030334 | |
| Download: ML20245H170 (26) | |
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S.1 NUCLEAR REGULATORY COMMISSION
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. OFFICE OF NUCLEAR REACTOR REGULATION
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.NRC inspection. Report:
50-445/89-17 Permits: CPPR-126 50-446/89-17 CPPR-127 Dockets: 50-445'
Category: A2 50-446-Construction Permit
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Expiration Date:
Unit 1: August 1, 1991 Unit.2: August 1, 1992 Applicant:
TU Electric Skyway Tower 400 North Olive Street ~
Lock Bo:( 81
- Dallas, Texas 75201
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Facility Name:
Comanche Peak Steam Electric Station (CPSES),
Units 1 and 2
. Inspection At:
Comanche Peak Site, Glen Rose, Texas Inspection Conducted: March 8-through April 4, 1989 l
' Inspector:
9 2V 89 S. D. Bitter, Resident Inspector,
'Date Operations Inspector:
S.
P.-Burris, Senior' Resident Inspector,
// D4te Operations j
Reviewed by: Ord b Y-A S.~ Wiebe, Lead Project Inspector
/Dat'e
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8905030334 890424 POR ADOCK 05000445
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Inspection Summary Inspection Conducted: March 8 through April 4, 1989 (Report 50-445/89-17; 50-446/89-17)
Areas Inspected:
Unannounced resident safety inspection of applicant action on previous inspection findings, action on 10 CFR part 50.55(e) deficiencies identified by the applicant, follow-up on NRC bulletins, TMI action items (Safety Issue Management System items I.A.1.1.1, closed; I.A.1.3.1, closed; I.A.1.3.2.A, closed; I.A.2.1.4, closed; II.E.1.2.1.A, closed; II.E.1.2.1.B, closed; II.E.1.2.2.A, closed; II.E.1.2.2.C, closed; II.E.3.1.1, open; II.E.4.1.1.B, closed; II.E.4.1.2, closed; II.E.4.2.1, closed; II.E.4.2.2, closed; II.E.4.2.3, closed; II.E.4.2.4, closed; II.E.4.2.5, open; II.E.4.2.6, open; II.E.4.2.7, closed; II.F.1.1.A, closed; II.F.1.1.B.2, open), preoperational retest program activities, and plant tours.
Resu3ts:
Within the areas inspected, significant weaknesses were noted in the preoperational retest program.
These weaknesses are discussed in paragraph 6 of this report.
No violations or deviations were identified.
Three open items are discussed, one in paragraph 3.b and two in paragraph 6.
Seven unresolved items disclosed during the inspection are discussed in paragraph 6.
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DETAILS 1.-
Persons Contacted
- J. W. Beck, Vice President, Nuclear Engineering, TU Electric
- M.
R. Blevins, Manager, Technical Support, TU Electric
- H.
D. Bruner, Senior Vice President, TU Electric
- W.
J.
Cahill, Executive Vice President, Nuclear, TU Electric
- W.
G. Guldemond, Manager of Site Licensing, TU Electric
- T.
L. Heatherly, Licensing Compliance Engineer, TU Electric i
- J.
C. Hicks, Licensing Compliance Manager, TU Electric
- J.
J. Kelley, Manager, Plant Operations, TU Electric
- E.
F. Ottney, Program Manager, CASE
- A.
B. Scott, Vice President, Nuclear Operations, TU Electric
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- C.
E.
Scott, Manager, Startup, TU Electric
- M.
R. Steelman, Licensing, TU Electric
- R.
D. Walker, Manager of Nuclear Licensing, TU Electric The NRC inspector also interviewed other applicant employees during this inspection period.
- Denotes personnel present at the April 4, 1989, exit I
interview.
2.
Applicant Action on Previous Inspection Findings (92702)
i a.
(Closed) Open Item (445/8445-0-01):
" Identification of Problems."
This issue was originally generated based on Discussions between the RRI and the applicant brought out a need for the applicant to take definitive corrective
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action to preclude future valve lineup problems and to ensure that all such problems are documented in a timely manner by the shift supervisors with first hand knowledge of the problems.
At the discussion it was pointed out by the RRI that the shift supervisor appears to be burdened with an analysis of the problem and possible corrective actions for the purpose of deciding in what format the problem must be reported, i.e.,
Deficiency
'""t, Nonconformance Report, or Problem Report.
snese reports are controlled by three different administrative procedures.
The applicant indicated that action will be taken to provide the shift supervisors with simpler reporting instructions.
The applicant has revised their procedures to remove some of the administrative burden from the shift supervisor by:
Revising the conditional report procedure, and by
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coincident renaming it " Condition Report" to report any concerns which can not be readily identified
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within one of the existing formats (NCR, DR, DIR, etc.).
' Relieving the shift supervisor and other plant
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operation's personnel from initial analysis and corrective. action for the purpose of determining which reporting format to use.
l Review of Procedure STA-504, " Condition Report" and
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STA-512, " Failure Analysis," found that situations similar to those described in the original report should i
not be a problem if these procedures are properly implemented by the applicant.
This item is, therefore, considered closed.
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b.
(Closed) Unresolved Item (445/8601-U-07):
" Vibration Program Requirements."
The inspector found that the applicant apparently had not been performing all of the i
vibration checks on the component cooling water pumps,as required by their maintenance schedule.
The applicant stated that vibration checks vill be performed on a regularly scheduled basis in accordance with STA-606,
" Work Order and Work Request," by rescheduling the routine generation of a work request.
This routine l
information will then be evaluated in accordance with REI-508, " Predictive Maintenance Vibration Program" and OPT-208A, " Component Cooling Water System Operability
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Test" to verify that the pumps are still operable.
This data will then be placed in the preventive maintenance data base.
The inspectors determined that the applicant's response provides reasonable assurance that the vibration checks will be performed.
Based on this review, the inspectors consider this item closed.
c.
(Closed) Unresolved Item (445/8822-U-04):
" Housekeeping and Equipment Protection Problems."
This issue was originally identified because the inspectors noted that some craft personnel were climbing or standing on snubbers and instrument piping.
The inspectors were concerned that undetected damage could occur which would cause the snubbers to become inoperable and the instrument tubing to be overstressed.
To verify snubber i
operability, the applicant committed to hand stroke all snubbers sized 1/4 through 10 and to perform a representative sample size of snubbers sized 35 to 100.
This effort will be completed prior to the next thermal expansion test.
In addition to the preoperational and initial startup test programs, the applicant plans to perform visual inspections in each plant area, the combination of which should identify any instrument line problems.
This item is considered closed.
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d.
(Closed) Open item (445/8852-0-05):
Program for monitoring sediment buildup in the Safe Shutdown Impoundment (SSI).
This item involved the inspector's concern that if excess sediment is identified while the plant is in operation and the technical specifications require that it be removed in 30 days, adequate fore-thought and preparation may not be utilized to develop the procedure to remove the sediment.
The inspectors note that the final draft revision of the technical specifications no longer requires that the sediment be removed in 30 days.
Instead, the Final Draft Technical Specifications, paragraph 3.7.5, requires that the applicant prepare and submit to the NRC within 30 days, a special report that includes the measures to be employed to remove the sediment.
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The inspectors note that this is in conflict with the SER, Section 2.4.8, which requires the applicant to have a procedure for removal of the sediment.
This procedure was a prerequisite to the NRC's determination that this area is acceptable.
The NRC intends to revise the SER by a future supplement to evaluate this change in the final draft version of the Technical Specifications.
The inspector believes that without the time limit of 30 days, there is reasonable assurance that the sediment remmes.1 will be adequately planned and will not affect the oafety of the plant.
In addition, the NRC will have the opportunity to review the measures to be employed to remove the sediment.
This item is closed.
3.
Action on 10 CFR Part 50.55(e) Deficiencies Identified by the Applicant (92700),
a.
(Closed) Construction Deficiency (SDAR CP-87-137):
" Loose Baffle Plate in the Diesel Generator Governor Oil Cooler."
The baffle plate for the dietel generator (D/G)
governor oil cooler was found loose during routine maintenance activities.
The applicant found that the cause of this condition was an apparent error in vendor design and/or fabrication of the cooler internal baffle plate (plate was solderad or brazed in place).
The applicant reviewed other safety-related governor oil coolers and found that this deficiency apparently would affect only the diesel generator and turbine driven auxiliary feedwater (AFW) pump turbine governors.
However, after additional review of che AFW pump turbine governor, the applicant found that it would not undergo a l
similar failure.
In addition, the applicant elected to l
only replace the affected heat exchanger internals rather
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than replace the entire heat exchanger.
The necessary
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post work testing will be certified by TU Electric during the preoperational testing activities for Unit 1 systems.
Based,on this information, the inspectors consider this item closed.
j b.
(Closed) Construction Deficiency (SDAR CP-88-02)':
This issue lealt with the postulated
failure of a gravity damr w which would cause battery i
c room air flow to cease.
_;eview of the evaluation found i
that the applicant determined that all safety-related
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systems are provided with two 100% redundant fans which would start during an emergency.
Even with the failure of a single gravity damper to open, the redundant fan would still perform its safety-related function.
Engi-neering recommended making changes to add instrumentation-to give the control room an indication of an adverse i
pressure condition within the HVAC ductwork, as ide..ti-fled on Deficiency Report C87-04897.
The inspector 3 informed the applicant that'the results of these racom-mended changes would be identified and followed up as an open item (445/8917-O-01), "HVAC Gravity Damper Flow l
Indication and Alarms."
4.
Follow-up on NRC Bulletins (92700)
i (Closed) IE Bulletin (IEB 79-21):
" Temperature Effects on Level Measurement."
Water level errors in instrument measurements due to heatup in the steam generators and l
pressurizer could make the actual level different than the
indicated water level.
The applicant's response to this issue was to ensure that the operators have the correct plots and graphs available to illustrate'the proper water level error due to a reference leg heatup.
Review of operation's Procedures FRH-D.1, Revision 3,
" Response to Loss of Secondary Heat Sink," EOP-1.0, Revision 3, " Loss of Reactor or Secondary Coolant" and FRH-0.5, Revision 2, " Response to Steam Generator Low Level" found that these procedures have been revised to correctly implement water level error adjustments as a function of temperature.
The inspectors consider this item closed.
i 5.
TMI Action Items (SIMS)* (25565)
- The Safety Issue Management System (SIMS) track number is the same as the TMI Action Item Number.
a.
(Closed - Unit 1 only) TMI Action Item I.A.1.1.1:
" Shift Technical Advisor on Duty."
This item had remained open pending NRC review (pursuant to TI 2515/65) of the applicant's administrative procedures concerning the
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b requirements to have the Shift Technical Advisor (STA)
onsite.
In general, NUREG-0737, " Clarification of1TMI Action. Plan Requirements," states. that : an STA im available for duty -
on.each operating shift when'a pressurized. water reactor-(PWR). plant is being operated in Modes.1-4.
In the CPSES FSAR,.the applicant has : committed tx) having available
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lonsite.to each opere. ting. shift, when=the plant is being l
operate'd in Modes 1-4, an individual who is qualified to
- provide technical support tc the. shift supervisor in the i
areas of thermal hydraulias, reactor engineering, and plant analysis..This' individual, so described, is the y
STA.
The applicant had complied with this commitment by.using Procedure'ODA-102, Revision'9, " Shift Complement Responsibilities and Authorities."
C?ction 6.2.8 of this
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procedure defines-the STA's duties duriag both routine-
-and normal operations.
Furthermore,-'Section 6.3.13 specifies that the STA shall be onsite with one or both
. units operating in Modes 1-4.
Because the applicant has complied with.the provisions of NUREG-0737, this item is closed for Unit 1.
b.
(closed) TMI Action Item I.A.l.3.1:
" Limit overtime."
IE Circular No. 80-02, " Nuclear Power Plant Staff Working Hours," dated February 1, 1980, contained-guidance concerning overtime work for those members of the plant staff who perform safety-related functions.
This guidance was then amended by an NRC letter from D. G.
Eisenhut, July'31,'1980, which set forth interim criteria-for shift staffing and provided guidance for overtime.
TheLovertime guidance of the Eisenhut letter was then.
updated in Section I.A.1.3 of~NUREG-0737, " Clarification of TMI. Action Plan Requirements."
Finally, Supplement 1 to NUREG-0737 was issued.
This supplement. serves as an NRC policy statement'that further revises the overtime guidance contained in NUREG-0737.
Essentially, the policy statement contained in Supplement 1 to NUREG-0737 calls for developing
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administrative procedures (by fuel load) that specify the following:
(1)
Routine heavy use of overtime is to be avoided.
The object've is to have operating personnel work a normal 1-hour day, 40-hour week while the plant is operati g.
(2)
If unforeseen problems arise, or if major maintenance activities, major plant modifications, K
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s or extended periods of shutdown for refueling are necessary, then, on a temporary basis, the following guidelines should be followed.
An individual should not be permitted to work
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more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight (excluding shift turnover time).
An individual should not be permitted to work
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more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven-day period (all excluding shift turnover time).
A break of at least eight hours should be
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allowed between work periods (including shift turnover time).
Except during extended shutdown periods, the
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use of overtime should be considered on an individual basis and not for the entire staff on shift.
(3)
Deviations from the guidelines of part (2) (as stated above) shall be authorized by the plant man &ger (or his deputy) or by higher levels of management.
The paramount consideration in such authorization shall be that significant reductions in the effectiveness of operating personnel would be highly unlikely.
Authorized deviations to the working hour guidelines shall be documented and available for NRC review.
(4)
The procedures that are used to implement these policy guidelines should allow licensed operators at the controls to be periodically relieved and assigned to other duties away from the control board during their tours of duty.
The applicant has issued a procedure, STA-615, Revision 2, " Staff Work Hours."
This procedure covers all of the points listed above (items [1], [2], [3] and
[4]).
Specifically, Section 4.1 of the procedure explicitly meets the requirements of items (1), (2), and
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(4).
Section 4.2 explicitly meets the requirements of
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item (3).
In summary, the applicant has met the provisions of Supplement 1 to NUREG-0737.
Therefore, this item is closed.
c.
(Closed) TMI Action Item 1.A.l.3.2.A:
" Minimum Shift Crew Complement."
This item had remained open pending NRC review of plant administrative procedures (pursuant
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to Temporary Instruction 2515/65) to ensure compliance with 10 CFR 50.54m.
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The inspector has reviewed Operations Department Administrative Manual Procedure ODA-102, Revision 9, i
" Shift Complement Responsibilities and Authorities."
l This-procedure contains provisions for complying with
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Specifically, these provisions are-l covered as follows:
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Attachment 8.A lists the minimum shift crew members
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(composition) needed for various modes of plant
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operation.
j Part 6.3.1 specifies that a USNRC licensed Senior
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Reactor Operator (SRO) (as shift supervisor) shall
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be onsite at all times when at least one unit is
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loaded with fuel.
Part 6.3.2 specifies that one USNRC licensed SRO
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shall be in the control room at all times when the reactor plant is in Modes 1, 2, 3, or 4.
Part 6.2.4.19 specifies that the reactor operator
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shall remain "at the controls" unless properly relieved.
Part 6.3.7 specifies that during core alterations, a
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USNhC licensed SRO shall directly supervise the alterations.
Furthermore, during this period, this operator may have no other assignments than those directly dealing with core alterations.
Because these provisions meet the requirements of 10 CFR 50.54m, the inspector considers this item closed.
t d.
(Closed) TMI Action Item I.A.2.1.4:
" Upgrade of Reactor Operator and Senior Reactor Operator Training and
Qualifications / Modify Training."
This item had remained
open pending NRC review of the CPSES training program (Pursuant to Temporary Instruction 2515/65) to ensure that the provisions of Sections A and C of Enclosure 1 of
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the March 28, 1980, letter from H. R. Denton were met.
Essentially, Section A of Enclosure 1 of the Denton letter specifies the eligibility requirements that licensed operators must meet in order to be administered an NRC examination.
These requirements cover the areas of experience, training, and facility certifications.
Section C of Enclosure 1 addresses the requirements for licensed operator requalification programs.
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.The inspector has reviewed the manner in which the applicant addressed the provisions of Sections A and C.
j L Basically, three. procedures' cover the provisions.
These procedures are:
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TRA-203, Revision 4,'" Replacement Licer.se Training"
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TRA-204, Revision 6,
" Licensed Operator Requalification Training Program" STA-101;. Revision 6, " Nuclear Operations
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Organization" z
.i The' experience requirements of Enclosure A are contained in Sections 4.2.2 and 4.2.4 of Procedure TRA-203.
The training requirements of Enclosure A are contained in Section 4.3 of Procedure TRA-203 and section 6.9 of TRA-204.. The facility certifications requirement of Enclosure A-is covered in Section 5.1.3 of Procedure STA-101.1 The licensed' operator requalification program requirements of Enclosure C are contained in Procedures TRA-203 and TRA-204.
More specifically, Section 4.3 of-Procedure TRA-203 and Section.6.1.2 and 6.3.1 of Procedure'TRA-204 address the content-of-the requalification program.
In Procedure TRA-204,
.Section 6.5 addresses the accelerated requalification program criteria, and Section 6.3.3 specifies the control manipulations that must be performed during requalification.
In summary, the inspector has reviewed the three l
procedures referred to above.
He has determined that they adequately cover the provisions of Enclosures A and C of the Denton letter. Therefore, this. item is closed.
j e.
(Closed) TMI Action Item II.E.1.2.1.A:
Short Term
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Actions for Auxiliary Feedwater System (AFWS) Initiation I
Circuitry.
Since the design of the AFWS initiation f
circuitry included a' safety-grade designation, the short
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term actions are not applicable.
The-inspection j
requirements'of Temporary Instruction 2515/65 for this item are considered complete and this item is closed for
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Units 1 and 2.
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(Closed) TMI Action Item II.E.1.2.1.B:
Long Term Actions
for AFWS Initiation Circuitry.
This item recommended t
that this circuitry be upgraded in accordance with safety-grade requirements..In NUREG-0797, the staff documented that at CPSES, this circuitry is part of the
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Engineered Safety Feature (ESF) actuation system and, l
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t therefore, the design conforms to the recommendations.
f Since no modifications were required, the inspection
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J requirements of Temporary Instruction 2515/65 for this
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item are considered complete and this item is closed for Units 1 &nd 2.
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(Closed) TMI Action Item II.E.1.2.2.A:
Short Term
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Actions for AFWS Flowrate Indication.
Since the flowrate indication is already safety-grade, the short term actions are not applicable.
The inspection requirements of Temporary Instruction 2515/65 for this item are considered complete and this item is closed for Units 1 and 2.
h.
(Closed - Unit 1 only) TMI Action Item II.E.1.2.2.C:
Long Term Actions for AFWS Flowrate Indication.
In I
NUREG-0797, Chapter 22,Section II.E.1.2, the staff documented that two safety-grade indicators of auxiliary feedwater flow to each steam generator were to be provided in the control room.
The staff concluded that this satisfied the item guidelines and was, therefore,
acceptable.
The inspector verified that two safety-grade
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indicators of auxiliary feedwater flow to each steam
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generator are provided in the control room for Unit 1.
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The inspector also verified that theses instruments are L
identified in the FSAR, Table 032.110-1, as being l
Category 1E, environmentally qualified, and seismically qualified.
The inspection requirements of Temporary Instruction 2515/65 are considered complete and this item is considered closed for Unit 1.
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(Open) TMI Action Item II.E.3.1.1:
Emergency Power
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Supply for Pressurizer Heaters.
This item concerned
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ensuring that enough pressurizer heaters are available to maintain natural circulation conditions (to maintain a high enough pressure to prevent saturation conditions in the RCS) on a loss of normal power.
The inspector j
reviewed this item pursuant to Temporary Instruction 2515/65 as follows:
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The inspector verified by review of plant drawings
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that the pressurizer heaters can be supplied from an emergency power source (diesel generator).
The inspector verified that redundant heater capacity is provided and that each group can be supplied from only one emergency power source.
The inspector verified that the pressurizer heaters
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are automatically shed from the emergency power source on a safety injection (SI) signal.
The SI signal must be manually reset before the heaters can be manually loaded on the bus.
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The inspector notes that the pressurizer heaters are
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t.ormally connected to the emergency bus when the emergency bus is not being powered by the diesel i
generator.
The inspector verified that the pressurizer heaters are shed.from the bus on a loss of offsite power and are not automatically loaded back on'the bus, j
In order to close this item, the inspector nds more information as follows:
The inspector needs to review documentation that
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shows that the number of heaters provided are sufficient to maintain natural circulation at hot standby conditions (to maintain a high enough
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pressure to prevent reaching saturation conditions in the RCS).
The FSAR in Section II.E.3 indicates that
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Westinghouse is evaluating the time by which the heaters will be required to be energized from the emergency power supply.
The inspector needs to review this evaluation.
t The inspector needs to review the procedures and
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training that were established to make the operator aware of when and how the required pressurizer heaters are to be connected to the emergency power supply.
This item remains open pending inspector review of the additional information required as described above.
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(Closed) TMI Action Item II.E.4.1.1.B:
Review and Revision of Procedures for Combustible Gas Control.
This item concerned plants using external hydrogen recombiners or purge systems for post accident combustible gas control.
Since CPSES has redundant safety-grade hydrogen recombiners located inside containment, this item is not
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applicable.
The inspection requirements of Temporary i
Instruction 2515/65 are considered complete for this item
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and the item is closed for Units 1 and 2.
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(Closed) TMI Action Item II.E.4.1.2:
Install a Dedicated
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Penetration for Combustible Gas Control.
This item I
concerned plants using external hydrogen recombiners or purge systems for post accident combustible gas control.
Since CPSES has redundant safety-grade hydrogen recombiners located inside containment, this item is not applicable.
The inspection requirements of Temporary Instruction 2515/65 are considered complete for this item and the item is closed for Units 1 and 2.
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(Closed) TMI Action Item II.E.4.2.1:
Diversity in the parameters Sensed for Containment Isolation.
In NUREG-0797,.Section II.E.4.2, the staff documented that the Containment Isolation Actuator Signal (CIAS) takes
. place on high containment pressure and all. safety injection signals.
The staff, therefore, concluded that the requirement to sense diverse parameters for containment isolation actuatcrs has been met.
The inspection requirement of Temporary Instru' tion 2515/65 are considered complete for this item and this item is closed for Units 1 and 2.
m.
(Closed) TMI Action Item II.E.4.2.2:
Reconsider Definition of Essential and Nonessential Systems.
In NUREG-0797,Section II.E.4.2, the staff documented their determination that the applicant properly designated systems as essential or nonessential.
The inspector reviewed Table 6,2.4-6 of the FSAR and no discrepancies concerning the designations were noted.- The inspection requirements of Temporary Instruction 2515/65 are considered complete for this item and the item is closed for Units 1 and 2.
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(Closed) TMI Action Item II.E.4.2.3:
CIAS to Isolate all Nonessential Systems.
In NUREG-0797,Section II.E.4.2, the staff documented their determination that all nonessential systems are isolated by the CIAS.
The inspection requirements of Temporary Instruction 2515/65 are considered complete for this item and the item is closed of Units 1 and 2.
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(Closed) TMI Action Item II.E.4.2.4: This item concerned designing the CIAS such that resetting the isolation signal would not result in the automatic opening of containment isolation valves.
In NUREG-0797,Section II.E.4.2, the staff documented their determination that the design precludes automatic reopening of the containment isolation valves upon reset of the isolation signal.
The inspection requirements of Temporary Instruction 2515/65 are considered complete for this item and the item is closed for Units 1 and 2.
p.
(Open) TMI Action Item II.E.4.2.5:
Containment Pressure Setpoint.
NUREG-0797,Section II.E.4.2, documents the staff's acceptance of a CIAS setpoint of 4.0 psig.
The FSAR in Section II.E.4.2 indicates that the containment pressure setpoint (H-1) of 4 psig is the minimum compatible with normal operating conditions.
The Proof and Review Version of the Technical Specifications lists i
the allowable value for containment pressure (H-1) is <
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3.9 psig.
Since the Technical Specification allowable
value is less (more conservative ) than that deemed
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acceptable by the staff, the inspector has no concerns
with regard to staff acceptance.
However, the Technical
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Specification allowable value of 1 3.9 psig and the trip i
of 1 3.35 psig apparently conflicts with the FSAR statement that 4 psig is the minimum setpoint that is compatible with normal operating conditions.
The inspector needs more information to determine if the Technical Specification setpoint is compatible with normal operation.
This item is open pending inspector's review of the information identified above.
q.
(Open) TMI Action Item II.E.4.2.6:
Containment Purge Valves.
This item concerns valves which do not meet the operability criteria in Branch Technical Position (BTP)
CSB 6-4 or the Staff ?Interium Position of October 23, 1979.
Such valves are to be sealed closed during Modes 1, 2, 3, and 4 and must be verified closed at least every 31 days.
Inspection Report 50-445/88-79; 50-446/88-75 documented l
in paragraph 6.b that the CPSES 48-inch purge supply and i
I exhaust will be sealed closed and checked every 31 days.
NUREG-0797 documented, in Section II.E.4.2, the staff's conclusion that the 18-inch Containment Pressure Relief System was acceptable with regard to BTP CSB 6-4-
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The FSAR in.Section R022.20, paragraph 2.a, documents an I
applicant commitment to a Technical Specification that will limit'the use of the Containment Pressure Relief i
System to less than 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> per year during plant
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operating Modas 1, 2, 3, and 4.
The Proof and Review L
version of the Technical Specifications contains no such requirement.
The inspector requires additional information to resolve this issue.
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NUREG-0797,Section II.E.4.2 documented a ; confirmatory
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issue regarding the operability of the 18-inch valves.
NUREG-0797, supplement 12,Section II.E.4.2 documente6 the staff's evaluation of information provided by the applicant concerning this issue.
The staff found that the information provided by the applicant was not sufficient to demonstrate operability of the valves.
By I
a November 9, 1984 letter, the staff requested additional information.
l This item remains open pending resolution of the
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applicant's commitment regarding the Technical Specification and resolution of the operability of the 18-inch Containment Pressure Relief System valves.
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(Closed) TMI Action Item II.E.4.2.7:
Radiation Signal on
Purge Valves.
Section II.E.4.2, documents the staff's determination.
Tat the containment isolation
valves for the purge Eystem (48-inch) and pressure relief syrstem (18-inch) receive an automatic closure signal on d
high radiation.
The inspection requirements.of Temperary
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Instruction 2515/65 are considered complete t.'nd this item l
is closed for Units 1 and 2.
s.
(Closed) TMI Action Item II.F.1.1.A:
Noble Gas Monitor / Interim.
Since the FSAR,Section II.F.1 commits to completely implementing the accident monitoring items prior to fuel load, the interim actions are not
necessary.
The inspection requirements of Temporary Instruction 2515/65 are considered complete and this item is closed for Units 1 and 2.
t.
(Open) TMI Action Item II.F.1.1.B.2:
Noble Gas Monitor /
i Long Term.
NUREG-0797,Section II.F.1 documented that
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the staff considered the applicant's responce to this item incomplete.
Supplement 3 to NUREG-0797, in
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Section II.F.1, documented the staff's evaluation of additional information presented in FSAR amendments 27 and 31.
The staff concluded that the noble gas monitors for the plant vent stack and main steam lines meet the provisions of NUREG-0737 for this item.
The inspector notes that although the Proof and Review revision of the Technical Specifications addresses these y
monitors in Specification 3.3.3.3.b, they are not listed l
in Table 3.3-6.
This. item remains open pending resolution of the
- I Technical Specification discrepancy.
If these monitors are not to be included in the Technical Specification, the inspector requires information that provides reasonnble assurance that the monitors will be maintained in an operable and calibrated condition.
6.
Preoperational Retest Program Activities (70300, 70301, 70302, 70308, 70311, 70312, 70336, 70338, 70339, 70340, 70343, 70352 c
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70439, 70439, 70440, 70443)
i NCR inspections of the applicant's preoperational retest and operational preparedness phase activities were performed through direct obser7ation, personnel interviews; and review of preoperational test activities by verifying that:
Systems and components important to the safety of the
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plant were being fully tested to demonstrate their operability and design requirements.
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JAll management'and administrative controls and
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procedures, including QA requirements which were required for the necessary operation, had been implemented,
.followed, and documented.
The:NRC. inspectors accomplished these goals by reviewing aval';ble test procedures, witnessing selected ongoing test
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activities and reviewing completed test results.
The J
inspectors used the'following criteria to perform the pretest.
A review to ensure that:
Administrative content, format, and requirements were
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incorporated in the final approved procedure.
Test objectives _ met the referenced Regulatory Guide and
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FSAR Section 14 commitments.
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Acceptance criteria were identified-and clearly defined.
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Pre. requisite conditions.were established, adequately
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defined, and easily understood.
Test equipment used specified the appropriate custody
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control and required calibration data.
Procedure format was clearly written and appeared to be
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able to be easily followed.
Test witnessing of the identified systems was accomplished to
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ensure that all testing was performed in accordance with approved procedures and to verify the adequacy of test program.
records including preliminary evaluation of test results.
The
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NRC inspectors accomplished'these purposes by ensuring that:
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The latest revision of the test procedure was in use by
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test personnel.
i All crew manning requirements were met,
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All test prerequisites were met.
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Proper plant systems were in service.
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Test equipment required by the procedure was calib.mted
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and in service, if applicable.
l Testing was performed in accordance with an approved
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procedure.
Criteria for interruption of testing and continuation of
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testing was adhered to during all witnessed portions of the test.
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All deficiencies were documented in accordance with
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program requirements.
All temporary modifications, such as jumpers, strainers, i
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spool pieces, or blank flanges were installed and tracked
per established administrative controls.
f The inspectors reviewed and witnessed the following tests as discussed below and will discuss all of the staff's identified concerns as a summuary at the.end of this section:
a.
Test Procedure 1CP-PT-02-01 SFT, Revision 1, "118 Volt Class 1E AC Inverters."
The purpose of this test was to demonstrate the capability of the safety-related balance-of-plant (BOP) inverters to supply continuous power to their associated instrument distribution panels.
Essentially, this was accomplished by:
Checking for proper transfers, both manual and
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automatic, between the normal, alternate, and bypass supplies.
Performing a load test to verify proper voltage and
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frequency over the full load range and proper current limiting under overload conditions.
Verifying the required synchronization between the
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inverter output and bypass input voltage waveforms.
Testing all inverter control panel status lights.
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Verifying the operation of control room alarms that
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were initiated or cleared during the test.
During the witnessing of this test, the inspectors noted numerous discrepancies.
These discrepancies fall into four categories:
errors in the preoperational procedure (as written), administrative errors, malfunctioning inverters, and malfunctioning test equipment.
TU Electric identified the following three errors in the test procedure (as written).
Upon starting the test and energizing inverter IV1ECl, a fuse blew in the inverter.
Investigation led to the shift test engineer's (STE's)
discovering that Figure 1 (depicting the test equipment hookup) of the test procedure had an error that caused the blown fuse.
Later, the STE discovered that Figure 1 3'
contained still another error; the test points to the visicorder from the inverter were incorrect.
Both of these problems were documented in the test log, test deficiency reports (TDRs) were written, and temporary procedure changes (TPCs) were generated.
Still later, an
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The STE noticed that a step calling for closing the DC breaker after performing the it.d test in Section 7.1,.3, was missing.
This, too, was corrected by a TPC and was documented.
These inadequacies in the test procedure will be considered as an unresolved item pending further inspection (445/8917-U-02), " Inadequate Inverter Test Procedure."
i TU Electric identified the following administrative errors.
Several days after initiating the test, the STE
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noted that he had inadvertently forgotten to obtain the shift supervisor's signature on the cover sheet of the test.
He also discovered that the shift supervisor had not signed TPCs 1, 2, and 3.
In both instances, a TDR was written to document these errors and the necessary signatures were obtained.
These failures to obtain the required signatures will be considered as an unresolved item pending further inspection (445/8917-U-03), " Failure to obtain Shift Supervisor Signature."
TU Electric documented the following inverter malfunctions.
Step 7.1.36, which calls for the low battery voltage light to go off after adjusting the DC bus voltage to 140 V DC, failed because the light remained on.
A TDR was written.
Troubleshooting revealed that the inverter had a wiring error in the circuitry.
Further investigation revealed that all of the Unit 1 and all but one of the Unit 2 Elgar 10 KVA inverters had the same problem.
The applicant is j
currently pursuing this situation to determine if it is
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reportable under the provisions of 10 CFR 21.
In an unrelated problem, Step 7.1.4.3 failed because the 125 percent current limiting value (as recorded) was
' out-of-tolerance.
The corrective action involved the
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calibration of the circuit.
During the calibration, a faulty solid state isolation module in an alarm circuit was discovered.
All of these equipment problems were documented and corrected.
The inverter wiring errors and t
isolation module failure will be identified as an open item pending resolution by the applicant of the appropriate test deficiency report (445/8917-0-04),
" Inverter Preop rational Testing Problems."
TU Electric identified one case of test equipment malfunction.
In Step 7.1.3.15, the inverter shutdown
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L while using the load bank to attempt to increase the load to 50 percent.
A TDR was written and troubleshooting commenced.
The troubleshooting revealed that the load f.
bank was responsible for the problem.
It was repaired and testing recommenced.
Another failure of a load bank i
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unit is discussed later in this section in the paragraph dealng with preoperational test Procedure 1CP-PT-02-02.
During the pretest review of this test procedure, the inspectors had one observation.
Nowhere in the test procedure is there any reference to room (ambient)
temperature.
There are no precautions for not exceeding a certain temperature; furthermore, there is no place to record room temperature.
.The failure to consider roon. temperature in this preoperational test will b; considered as an unresolved item-pending further inspection (445/8917-U-05), " Failure to Consider Room Temperature During Inverter Preopera-tional Testing."
During their test witnessing activi-ties, the inspectors noticed that, in spite of the numerous times this test was stopped and started, the STE properly addressed the prerequisites of Section 6.0 each time he reinitiated the test.
Finally, it should be noted that this test is continuing past the end of this reporting period.
The inspectors intend to witness and review portions of this test prior to conducting their
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review of the completed test package.
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b.
Test Procedures 1CP-PT-02-02 SFT, Revision 0, "118 VAC RPS Inverters."
The purpose of this test is to demonstrate the capability of the instrument and control power supply system to provide a reliable source of power for the reactor protection system (RPS) redundant vital buses.
During the witnessing and review of this test, the inspectors noted numerous discrepancies.
These discrepancies involved test equipment malfunctions, inverter malfunctions, and the large number of temporary procedure changes (TPCs) needed to conduct the test.
TU Electric documented that at Step 7.1.21, the inductive load bank failed to operate correctly.
After documenting this, the problem was corrected.by repairing several faulty switches in the load bank unit.
It should be noted that during the conduct of Test Procedure 1CP-PT-02-01, the test of the 118 Class 1E inverters, the load bank that was used also failed.
The load bank test equipment multiple failures for both this test (1CP-PT-02-02) and the previously discussed inverter test (1CP-PT-02-01) will be~ identified as an
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unresolved item pending further NRC review
(445/8917-U-06), " Inserter Load Bank Failures."
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TU Electric documented that during the performance of the
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prerequisites of Section 6.2, a capacitor and fuse failed
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in Inverter 1V1PC2.
This was documented by a TDR and
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startup work authorizations were written to replace the components.
Additional inverter problems were noted for Inverters IV1PC4 and lV1PC3.
Specifically, at Step 7.4.88, inverter IV1PC4 did not trip on overload as
required.
A TDR was initiated and the testing in i
Section 7.4 was terminated pending troubleshooting.
i Troubleshooting the metering and relay circuits failed to determine the cause of this problem.
Furthermore, in Step 6.3.10, Inverter IV1PC3 failed to power up as called for.
Troubleshooting revealed that a failed ca_acitor i
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and an open fuse were the cause, the applicant replaced these components, and testing recommenced.
However, after approximately one hour of operation, during the
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performance of Step 7.3.20, the capacitor and fuse failed again.
It appears to the NRC inspectors that in the case of inverters IV1PC2, IVlPC4, and 1V1PC3, as described above, the root causes for the inverter problems were not adequately determined.
The apparent failure to determine the root causes will be considered as an unresolved item pending further inspection (445/8917-U-07), " Failure to Determine Root Causes for Multiple Inverter Failures During Preoperational Testing."
In addition to the equipment errors detailed above, the inspectors noted the large number of TPCs and TDRs needed to allow for testing the inputs to the Sarety System Inoperable' Indication (SSII) system.
This and the large amount of paperwork generated as a result of the equipment failures will be reviewed in more detail in a t
future inspection' period.
c.
Preoperational Test 1CP-PT-37-01 SFT, Revision 0, l
" Auxiliary Feedwater System (Motor Driven Pumps)".
The purpose of this test is to demonstrate the capability of the motor-driven auxiliary feedwater system to supply feedwater to the steam generators, to maintain steam generator water inventory as required, and to ensure system performance in accordance with the FSAR.
During the inspectors' review and witnessing of various
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portions of this test, the following two major discrepancies, identified by TU Electric, were noted.
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While preparing to perform Step 7.1.2.18, which calls for j
increasing comparator air pressure to the high pressure
side of flow transmitter FT-2456, the STE discovered that
the test equipment (comparator and essociated equipment)
l was no longer connected to the flow transmitter.
The i
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i equipment had been connected earlier, at Step 7.1.2.4.
i No step between Steps 7.1.2.4 and 7.1.2.18 called for its
removal.
The STE documented this and investigated.
l Discussions with Startup personnel revealed that the i
technicians did not want to leave the equipment connected-when it was not in use..Therefore, it was disconnected and removed; both actions took place without the knowledge of the STE.
The inspectors notified startup management that this appears to be a straightforward case of " unauthorized work" and would be tracked as an unresolved item pending dt:cussions with both the STE and technicians
'(445/8917-U-08), " Unauthorized Work During properational Testing."
The second discrepancy involved the STE's finding a valve
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out-of-position.
Specifically, while preparing to open valve TV-2, as called for in Step 7.4.21.1, the STE noticed that valve TV-5 was open.
TV-5 should have been closed.
The STE documented this and investigated the circumstances surrounding this.
He concluded that the l
valve-had been inadvertently opened while several closely
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positioned valves were being repeatedly manipulated.
Although the NRC inspecters have concluded that no serious direct impact to the test occurred, it appears j
that the necessary procedural control during this portion
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of the testing was not properly maintained.
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No other adverse conditions were noted by the inspectors j
in their review and witnessing of this. test.
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d.
Test procedure 1CP-pT-64-03 SFT, Revision 0, " Turbine l
Runback-and Reactor Control."
The purpose of this test
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is to demonstrate the capability'of the rector control system to respond properly to simulated input signals and to transmit proper control signals to other plant control systems and components.. Furthermore, the test was designed to demonstrate proper response of the rod control system to control signals from the reactor control system and'to demonstrate proper generation of various turbine runback signals.
l The inspectors' witnessed and reviewed various portions of
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this test.
During conduct of the test, the inspectors
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noted one TU Electric identified discrepancy.
Specifically, when the STE directed that Step 7.3.7 be performed, step 7.3.14 was performed instead.
Step 7.3.7 calls for manipulating a bistable switch in-procese control cabinet 1.
Step 7.3.14, on the other hand, calls for manipulating the same functional switch, but in-process control cabinet 2.
The STE discovered this l
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discrepancy immediately because the wrong alarm actuated at the main control board.
The STE investigated and determined that his assistant, who had performed the step, had manipulated the correct switch (functionally),
but in the wrong cabinet.
This discrepancy will be tracked as an unresolved item pending the applicant's resolution as to the root cause and the circumstances surrounding the incident (445/8917-U-09), "Preoperational T e s t i'n g i n W r o n g C a b i n e t. "
During a review of the test procedure, the inspectors noticed that in some cases, where identical multiple test instruments are used, no records that tie a particular instrument to a particular function are maintained.
For example, Step 7.1.3 callc for connecting four multimeters to four-different sets of cables.
Although each multimeter was labeled as to which cable set it was connected and each multimeter's serial number was recorded, no record was made of which multimeter (by serial number) was connected to which cable set.
The STE l
i stated that because the multimeters are not being used quantitatively, but instead are used merely for continuity measurements, no records are necessary as to which multimeter was connected to which cable set.
The inspectors consider this as an open item pending discussions with applicant management (445/8917-0-10),
" Traceability of Test Equipment."
e.
Test Procedure 1CP-PT-74-05, Revision 0, " Heated Junction Thermocouple System."
The purpose of this test is to demonstrate the capability of the heated junction j
thermocouple system to detect the approach to inadequate core cooling by indication of water level in the upper
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head and upper plenum regions of the reactor vessel.
I The inspectors reviewed the procedure and observed portions of the conduct of this test.
This test was performed in conjunction with the reactor coolant cystem fill.
One problem encountered in the test was documented by TU Electric; a heater controller was not operating properly.
The inspectors were unable to follow up on this prior to the end of this inspection period.
Therefore, the applicant's action to address the heater
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controller problem will be reviewed with the test results
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package in a future inspection period.
No significant items or conditions were identified by the NRC in the review and witnessing activities.
The NRC inspectors performed reviews of the overall preoperational test program to ascertain the applicant's administrative controls over the preoperational retest program.
These reviews were done to verify that the retest
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program had been developed and implemented in accordance with FSAR commitments, retest program commitments, and applicable regulatory requirements.
These inspections were accomplished by ensuring that:
The applicant's test program properly controlled flush
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and cleaning evolutions, performance of any necessary hydrostatic test, verification of instrument calibrations, functional testing, and controls of mechanical, electrical, and instrument and control tests.
Test procedure format and content were in accordance with
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regulatory guidance, industry standards, and the applicant's administrative controls.
Testing schedules were properly conceptualized,
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implemented, and controlled.
Test schedules were met as close as practical.
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Test personnel have been qualified to the appropriate
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level necessary to accomplish the activity for which they are responsible.
Organizational interfaces existed and were being properly
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implemented.
Engineering and vendor manuals and drawings were being
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properly controlled and updated as necessary.
Design changes, temporary modifications, jumpers, and
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bypasses were established and controlled in accordance with approved program procedures.
Maintenance activities were controlled in accordance with
.
administrative procedures which included the methodology for initiating, reviewing, approving, and scheduling
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maintenance activities.
i Maintenance activities will be controlled, coordinated,
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and/or utilized by the reoperation test program.
periodic or preventive maintenance is scheduled,
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performed, and documented during the preoperational test phase.
Cleanliness control and protection of facilities and
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equipment was established.
All necessary training requirements and subsequent
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documentation were met during this phase of plant construction.
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Based on discussions with the Startup Manager and his staff, the inspectors verified that the applicant's management were knowledgeable of their responsibilities and the general description of their test program.
The NRC inspectors have verified that all major preoperational testing has been scheduled for completion with the exception of those test that TU Electric has evaluated and determined not necessary to be reperformed.
Responsibilities for specific pretest procedure i
reviews, test witnessing, and post test results review have been assigned using the guidance established-in Regulatory Guide 1.68.
Test personnel qualifications were verified as meeting the acceptance criteria established by the startup administrative program.
The NRC inspectors have reviewed numerous design changes and have not found any major discrepancies which have not been i
previously documented by TU Electric.
Numerous maintenance inspections by the NRC have been conducted during the preoperational test phase and have been documented in previous inspection reports.
Based on these NRC inspections, the staff currently finds the applicant's maintenance program acceptable.
Administrative controls and personnel training have been found to.oe generally acceptable.
Based on the previous reviews and documentation, the NRC i
inspectors have determined that the overall preoperational retest program and the preoperational retest program i1 implementation modules have been satisfactorily completed.
The inspectors will continue to monitor program completions throughout the remaindev of the NRC 2513 and 2514 programs.
7.
Plant Tours (71302)
j The NRC inspectors conducted numerous plant tours during this inspection period.
These tours provided c,varnge during
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normal, off-normal, and backshift working hou..
NRC inspection activities included reviewing work documentation, witnessing ongoing work activities, observing and interviewing shift operations personnel, reviewing the status of control room construction work, reviewing the status of system and component completion, determining the status of Units 1 and 2 equipment lay up, observing housekeeping activities, and inspecting for general safety compliance.
To support these activities, NRC inspectors attended numerous hot functional test (HFT) and startup meetings and several Operations shift turnover meetings.
Special attention was also directed at the state of plant cleanliness and housekeeping activities in general.
These activities were deemed to be more important during this period because of the i
impending commencement of the HFT program.
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'During the plant tours, no adverse conditions were noted.
In t
general, the applicant is making excellent progress toward
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readying the plant for HFT.
8.
Open Items open-items are matters which have been discussed with the applicant, which will be reviewed further by the inspector,
.and which involve some action on the part of the NRC or applicant or both.
Three open items disclosed during the inspection are discussed, one in paragraph 3.b, and two in paragraph 6.
9.
Unresolved Items i
Unresolved. items are matters about which more information is required in order to ascertain whether they are acceptable-items, violations or deviations.
Seven unresolved items disclosed during the inspection are discussed in paragraph 6.
10.
Egit Meeting (30703)
An exit meeting was conducted on April 4, 1989, with the applicant's representatives 4.dentified in paragraph 1 of this report.
No written material was provided to the l
applicant by the inspectors during this reporting period.
The applicant did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspection.
During this meeting, the NRC inspectors summarized the scope and findings of the inspection.
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- 50-445/M- /'7; 50-446/ 89-l'7 i
DISTRIBUTION:
l
. Docket Files'(50-445/446)
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l-NRCPDR'
l'
LPDR CPPD-LA CPPD Reading (HQ)
ADSP Reading
- Site Reading File
J
- R. Warnick
- J. Wiebe
- H. Livermore
- MIS System, RIV
- RSTS Operator, RIV RPB, RIV RIV Docket File
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- L.
Shea, ARM /LFMB j
J. Taylor C. Grimes P. McKee i
J. Lyons
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J. Wilson M. Malloy J. Moore, OGC-WF M. Fields
J. Gilliland, RIV l
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D.
Crutchfield g
E. Jordan B. Grimes B. Hayes
- w/766 l
f
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