IR 05000254/1989012
| ML20247C429 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 07/17/1989 |
| From: | Harrison J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20247C421 | List: |
| References | |
| 50-254-89-12, 50-265-89-12, NUDOCS 8907240345 | |
| Download: ML20247C429 (23) | |
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lU.S. NUCLEAR' REGULATORY C0W61SSION q
REGION III
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50-254/89012(DRP);'50-265/89012(DRP)
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.., Reports No.
^ Licensee: Coninonwealth Edison Company
Post Office Box-767
. Chicago,.IL 60690 Facility Name:. Quad Cities' Nuclear Pcwer Station, Units 1 and 2.
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Inspection At: Quad Cities Site, Cordova, IL
' Inspection Conducted:.May-14 through June 24, 1989
/In'spectors:
R. L. Higgins-
.K.,R.'Ridgway A. Dunlop J. M.. Shine.
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J.:H. Neisler iT."Mi Ross.
P. R..Rescheske
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Approved By:'
. J. Harrison, Chief.
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Reactor Projects Section IB Date Inspection Summary
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Inspection on May ~4'through June 24,'1989 (Reports No. 50-254/89012(DRP);
~50-265/89012(DRP)).
Areas Inspected:
Routine, unannounced inspection of licensee actions on-ireviousitems,PlantOperations, Radiological. controls, Maintenance /
- Surveillance,. Emergency Preparedness, Security, Engineering / Technical Support and Safety Assessment / Quality Verification.
Results: ~ ~ During' the inspection period one~ apparent violation of NRC.
requirements and two unresolved items were discovered. The one apparent violation was licensee-identified:
the loss-of secondary containment
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(paragraph 3.d.(6)). The unresolved items' involved (1) the installation N
'of improper check valves in the air supply to the' actuators of the 18 inch
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butterfly valves in the purge and vent systems of;the primary containment.
of Units 1 and 2 and-(2) multiple examples of errors in the UFSAR, (paragraph 8.b'.)..
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8907240345 890719 PDR ADOCK 05000254
Q PDC
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Unit I shutdown to repair an 'unisolable feedwater leak on May 16 - 19, experienced main turbine control valve fluctuations on May 31 and June 8, f
. experienced a trip of the 1A reactor recirculation pump on June 5, and has been operating with a degraded ' inner seal on the IB reactor recirculation
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pump since early June.
Unit-2 reduced power on 11ay 22 to repair a leak in the drywell, shut down May 24 - 25 to repair another leak in the drywell,
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shut down'May 30 - June 1 to repair the two drywell floor drain sump pumps,.
and has operated normally ever since.
The licensee completed two major plant modifications withcet ' incident:
.the installation of a Unit 2125 VDC temporary battery and the replacement of.the Unit 2 125 VDC battery, and the control room ceiling and HVAC modification.
The overall radiological performance remained noteworthy. The number of
- personnel contaminations and amount of radiation exposure were less than projected despite extensive unanticipated maintenance activities which took place in radiation and contamination areas.
For most of the inspection period both units were at or near full power with only two or three illuminated annunciators on either unit. Plant cleanliness remained noteworthy. At the end of the inspection period Unit I had operated for 35 cont ecutive days and Unit 2 had operated for 24 consecutive days.
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! DETAILS'
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Personnel Contacted.
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- G. Spedl, Production Superintendent
- D. Gibson, Regulatory Assurance Supervisor
'*T. Barber,' Regulatory Assurance
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- R.' Hopkins,. Quality Assurance -
- Denotes those present at the exit interview on June 23,-.1989.
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The' inspectors' also contacted-and interviewed other licensee and.
contractor personnel during the course of this inspection.
2.
- Action on Previous-Items (92701-and 92702)
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.a.
(Closed) Open Item' 254/87033-05: HFA Auxiliary Relay Part 21 Report Documentation.
The station purchased four HFA 154 relays for a modification-that'has never been installed. A Part 21 report was submitted by General Electric and later a Service Advice Letter (SAL) was. issued on November 2, 1987-for this model. relay. ~The SAL was the subject of NRC.Bulletin 88-03,-dated March 10, 1988. The four HFA 154 i
re. lays are in storage and a copy of the SAL placed in the modifica-tion package to warn that'the relays are to be calibrated and checked per the SAL before use. The four.. relays were~ tagged i
'similarly: and the store computer description references the NRC Bulletin. This item is considered closed.
-b.
(Closed)-Violation 254/87013-01:
Failure to Establish Fire Inspections When a Sprinkler System was Inoperable.
A description of this violation is contained in Inspection Report
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254/87013.
Corrective actions were immediately taken to formally establish Operating Departmes. controls over contractor l fire watches. A Q0S 4100-3 Sprinkler System Outage Report was issued and twice per shift operator inspections established until the fire suppression system enhancement modifications were completed on July 7, 1987. A new procedure, Q05 4100-17, Fire Watch for Technical Specification Systems was developed and approved to establish the use of outage reports for fire detection or suppression systems for Technical Specification related systems.
The procedure specifies Operating Department tracking of all such surveillance during fire protection system outages.
Outage check sheets were also provided with the procedure. This item is considered closed.
c.
(Closed) Violation 265/87013-01:
Failure to Control Scram Discharge Volume Modification (SDV) Drawings and Procedures.
Long term actions regarding the SDV modifications on both units had
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been completed; however one electrical key diagram, 4E-2319, for
.the 24/48 VDC Battery Load and one Abnormal Operating procedure,
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Q0A 6900-3, for the 24/48 VDC systems failure had not been updated for Unit 2.
Corrective actions taken were the review of all procedures and drawings changed by the SDV modification'ns on both units. Two other procedures and one drawing were out of date and were subsequently corrected. Procedure QAP 1270-S10, Station Modification Checklist, for every modification or partial modification, had already been changed prior to this discovery to require the Technical Staff Engineer to list all procedures affected by the modification and to verify complation of all procedure changes before use of the modification. The Operating Engineer is required to review and approve the list and the procedure changes.
The architect engineer (AE) was contacted to review all drawings associated with these modifications.
No other deficiencies were found. The new modification program implemented in May 1987 requires that a project plan be developed for each modification.
All drawings affected by this modification are listed and tracked to assure all ' changes are properly reviewed and approved by station management and changes to all affected drawings completed.
This item is considered closed.
d.
(Closed) Violation 254/87019-01 and 265/87019-03:
Failure to follow procedures.
A temporary procedure change was placed into effect without notifying operators of the revision according to procedure QAP 300-27, " Operating Department Procedure Revision Training."
i A review performed after this event occurred verified that all other notice sheets were in place as required and no other deficiencies were identified.
Communications Center personnel and SCREs were made aware of this event.
In addition, procedure QAP 300-27 was revised to specifically assign the responsibility j
of processing temporary procedure changes to the Communications l
Center personnel and the SCREs will be assigned the responsibility for determining what training is required and inserting the notices into the appropriate procedure manual.
This item is considered closed.
e.
(Closed) Violation 265/87019-02:
Reactor Scram Resulting From an Instrument Mechanic (IM) Not Following a Surveillance Procedure.
This scram, as described in LER 265/87-11, was caused by the IM not following test procedure QIS 11-2, Low-Low Reactor Water Level Functional Test. This procedure requires the pre pressurization of the line being tested before it is returned to service. This was not done on the third switch tested that day and resulted in a sensing line pressure transient which caused the tripping of two switches connected to this same sensing line causing the scram.
This event was discussed with all members of the IM Department I
emphasizing that attention to details must be carried out at j
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all times. Appropriate disciplinary action was taken. Other corrective action taken to prevent recurrence included the revision of Procedure QIS 11-2 and 15 other procedures and associated checklists. The revision-provided a warning on pre pressurizing a'line prior to returning it to service.
The pre pressurization step was also added to each of the checklists requiring a signoff for each' test. The inspector verified these procedural changes.
This item is considered closed.
f.
(Closed) Unresolved Item 254/88015-04 and 265/88015-04:
Group 2 Isolation Signal Caused During Maintenance by Inadequate Review for Fuse Removal.
In order to perform maintenance on a Unit 2 torus /drywell inerting valve, fuse F6 in Panel 902-40 was removed.
This inadvertently tripped the reactor building ventilation system and automatically started the Standby Gas Treatment System (SBGT). The fuse was immediately replaced and the systems returned to normal.
The valve was later isolated for maintenance by liftir,9 a lead which would
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not cause an ESF actuation.
The cause of this event was determined
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to be personnel error.
The systems performed as designed and there-
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was minimal safety significance. This event was reported by LER 265/88019.
Personnel involved with this event were counseled to stress the importance of thorough Out-of-Service reviews.
LERs are reviewed by all operating personnel during their continuing training program.
This item is considered closed.
g.
(Closed) Open Item 265/88027-04:
Print M-77 Sheet 2 and FSAR Page 4-50 Contain Errors.
During an inspection, errors were noted in Drawing M-77 of the Reactor Recirculating Pump Piping and in FSAR Section 4.3.4, both describing seal leak off annunciators and lines which no longer exist.
Drawing M-77 has been revised under Design Change Request 4-88-141 and the FSAR Annual revision to be submitted to the NRC July 1,1989 contains the necessary FSAR revisions.
This item is considered closed.
h.
(Closed) Unresolved Item 254/88027-08; 265/88028-08:
Regulatory Guide 1.97 - Level Indicators / Recorders Not Isolated from Computer Circuits.
This item concerned Reactor Vessel Level indicator 263-106A not being installed in the control room, thus failing to meet the Regulatory Guide 1.97 requirement of one indicator per division for measurement of each variable. The inspector verified the licensee has completed reinstalling and testing this indicator per work request number 70891.
This item is considered closed.
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(Closed) Information Notice'87-59: ~ Potential RHR Pump Loss,
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This notice was revised to NRC Bulletin 88-04,. " Potential'
b Safety-Related Pump. Loss" in May.1988..The licensee replie'd to
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the bulletin with~a' letter dated July 11,11988. NRR;is responsible for. closing'this bulletin.
This item is considered closed.
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'(Closed) Information Notice 88-09:
Reduced Reliability'of
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Steam-Driveh' Auxiliary'Feedwater Pumps Caused by Instability.of Woodward PG-PL Type Governors.
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The licensee has a Terry steam turbine (GS-1) with a Woodward governor.(EG-M) on the Reactor Core Isolation Cooline (RCIC)
. System but' has not experienced any governor instability problems or problems'with the steam line drain system. An overspeed problem
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has' occurred due to. loose or worn parts on the overspeed trip mechanism. Parts have been replaced as required..The licensee has been performing cold quick testing of the RCIC pump since
. August'1987.
This item is considered closed.
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(Closed) Information Notice 87-56:
Improper Hydraulic Control
. Unit Installation at BWR Plants.
This notice concerned missing or loose frame bolts to hydraulic t
control units (HCUs) and branch junction modules (BJMs) connected to HCU frames. The licensee-performed an inspection of HCUs and found two missing bolts on two. separate HCUs on Unit.1.
In addition,11' bolts on Unit 1 and 2 bolts on Unit 2 were loose.
The licensee also'found that' none of the bolts had flat washers installed as per design. The licensee replaced the missing bolts and washers and torqued the bolts per work requests Q54096 and Q55303.
Neither unit has BJMs.
This item is considered closed.
1.
(Closed) Information Notice 88-01:
Safety Injection Pipe Failure.
This notice concerned thermal cycling of safety related Emergency Core Cooling System (ECCS) piping due to valve leakage. The
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licensee contracted Imrell Corporation to perform a review of the ECCS piping for thermal cycling. The results were reported in a letter (#0590-236-005) from Impell to the licensee dated June 24, 1988.
It was determined that the conditions which caused the thermal fatigue crack described in the information notice do not exist during normal operation.
During testing of the HPCI and RCIC system pumps, the condition may exist downstream of their respective check valves, however, the potential is significantly reduced since the lines connect to the Feedwater system which operates at a lower temperature than the reactor.
This reduces
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the maximum piping temperature differential and associated j
thermal stresses.
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This item is considered closed.
Open Items listed below have been closed during this inspection period l
based on a directive by the Division Director, Division of Reactor j
Safety, Region III. Our decision to close these items is based on the length of time the item has been in existence and the recognition of l
limited safety significance.
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(Closed) Open Item 254/87011-07:
Inadequate Documentation to Qualify AVC0 Solenoid Valves Prior to the EQ Deadline, n.
-(Closed) LER 254/87016-LL:
Leak Rate From All Valves and
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Penetrations on Unit 1 in Excess of Technical Specification Limit.
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(Closed) Open Item 265/87030-01: Mechanical Measurement and Test Equipment Not Retained.
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(Closed) Open Item 265/88900-01:
Followup on Information Notice 88-03: Cracks in Shroud Support Access Hole Cover Welds (BWRs).
3.
Plant Operations a.
Operational Safety Verification (71707)
The inspectors, through direct observation, discussions with licensee personnel, and review of applicable records and logs, examined plant operations.
The inspectors verified that all
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activities were accomplished in a timely manner using approved procedures and drawings and were inspected / reviewed as applicable; and that procedures, procedure revisions and routine reports were issued in accordance with applicable Technical Specifications, regulatory guides, and industry codes or standards. Additionally, the inspectors verified that approvals were obtained prior to initiating any work; activities were accomplished by qualified personnel; the limiting conditions'for operation were met during normal operation and while components or systems were removed from service; functional testing and/or calibrations were performed prior to returning components or systems to service; and independent verification of equipment lineup and review of test results were accomplished. Also verified were quality control records for being properly maintained and reviewed, and parts, materials and equipment for proper certification, calibration, storage, and maintenance as applicable. The inspectors conducted frequent tours of plant facilities to search for the existence of adverse plant conditions such as equipment malfunctions, potential fire hazards, radiological hazards, fluid leaks, excessive vibrations, and personnel errors.
The inspectors' review ensured these issues were addressed in a timely manner with sufficient and proper corrective actions and reviewed by appropriate management personnel.
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One: violation for'which no Notice of Violation will be issued was E
identified and is. described in paragraph 3.d.(6) of this report.
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Engineered Safety Features System Walkdown (71710).
During plant tours'of Units 1 and 2, the inspectors walked down some of the accessible portions of the High Pressure Coolant
, Injection (HPCI), Reactor Core Isolation _ Cooling (RCIC),- Core Spray (CS), Residual Heat' Removal (RHR) RHR Service Water,
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Standby Liquid Control (SLC) Systems, Standby Gas Treatment (SGT);
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Systems. The inspectors also walked down the Emergency Diesel Generators (EDG) and the Station Batteries.
l No violations or deviations were noted.
c.
Summary' of Operations
' Unit 1 Unit 1 operated either at full-power, on Economic Generation Control (EGC), or at reduced power in order to perform surveillance
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testing or respond to load dispatcher orders until May 16,.1989, when the licensee placed the unit in cold shutdown to repair an unisolable'_ leak on the. feedwater regulating valve bypass pipe
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drain line. The leak was repaired and the unit was returned to power on May 20, 1989.
Unit I ran normally at power until main turbine control valve spiking occurred on May 31,.1989. The licensee cleaned dirty potentiometer contacts in the EHC cabinet and lowered the-temperature of the auxiliary electric room on June 1,1989.
These measures appeared to solve the main turbine control valve spiking prcblem.
On June 5, 1989, the 1A reactor recirculation pump' tripped while the licensee was trying to. isolate a ground. The reactor entered theLregion of potential instability on the power-to-flow map, but no power oscillations occurred. The. reactor operator inserted'
control rods to reduce power below the region of potential instability, restarted the 1A reactor recirculation pump, and returned the unit to normal power operation.
On June 8,1989, main turbine control valve spiking reoccurred.
The licensee imposed a limit of 700 MWe (88*4 power).
This limit was removed on June 10, 1989, because no further control valve spiking has occurred.
In early June licensee personnel noticed that the seal cavity pressure for the IB reactor recirculation pump was increasing, indicating that the inboard seal was possibly degraded. The licensee has implemented a temporary procedure which requires close monitoring of the reactor recirculation pump seal, entry into single loop operations and possible plant shut down if the seal fails.
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I As' of the end of the inspection period Unit l'had operatediat power j
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for 35 consecutive days. '
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,l Unit 2-l The: unit operated normally until May,22, 1989, when an' increase in l
drywell floor drain sump-leakage necessitated a power. reduction and -
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drywell entry..The -leak was from' an. instrument line on a recircula-
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tion loop riser.
The le'ak was repaired'and' normal' power operation
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' resumed on May 23, 1989.
On May'24, 1989, drywell floor drain sump leakage Lincreased'above d
the technical specification limit of 5 gpm,' necessitating a reactor
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shutdown'and the declaration of an unusual event. The increased -
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drywell leakage was due to a leak on the RCIC' inboard steam supply-valve. The leak was repaired and the unit was returned to power.
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operation on May 25, 1989.
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i On May 30,-1989, the A drywell floor drain sump pump' failed.
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Since the B drywell floor drain sump pump was already inoperable, the unit was-left without any operable floor drain sump monitoring'
system.
In accordance with Generic Letter 84-11, the' unit was
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l shutdown. Both drywell floor drain sump pumps were returned to l
. operability, and the unit was returned to power operation on
June 1,1989.
l Some difficulty in maintaining main condenser vacuum was experienced l
on June 2, 15739, necessitating a power decrease.
Readjusting the
circulating water system valve lineup improved the main condenser
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vacuum, allowing the. unit to resume normal power operation.
o As of end of the inspection period Unit 2 had' operated at power for
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24 consecutive days.
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d.
Cnsite Followup of Events At Operating Power Reactors (93702)
(1) ' Unit 1 Reactor Shutd'own Due to an Unisolable Feedwater Leak
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On May 16, 1989, while attaching a clamp to a leaking 3/4" i
socket weld on the feedwater bypass line, the leak worsened, i
resulting in an accelerated shutdown of Unit I from 100%
power.
The Unit 1 main turbine was manually tripped and y
Unit I was placed in cold shutdown on May 17, 1989. The i
leak which necessitated the shutdown was due to a crack in a socket weld r ich connects the 3/4 inch drain line to the 6 inch pipe. ine licensee repaired the leak, replaced the
"A" reactor pressure regulator, repaired several other steam leaks, and repaired a hanger for a pipe connecting the.
moisture separator to the moisture separator drain tank.
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.(2) -Unit 1 Reactor Startup
On May 19, 1989, the licensee commenced control rod withdrawal
'to: restart Unit I following an unplanned maintenanceioutage
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to. repair several steam and feedwater leaks.
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(3) Unit 2' Power Reduction and Drywell Entry Due to. Increased Unidentified Leakage in the Drywell-On May 22, 1989,. the Unit 2 reactor operator noticed that
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unidentified leakage in the drywell had increased.
Power-
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was reduced to 25%, and a.drywell. entry was made at 11:20 PM..
Al leak was discovered on an instrument line connected to a.
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recirculation loop riser.~ Adjustments'were made to.stop the leak. On May 23, 1989, power was increased and ' normal
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operation resumed.
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(4) Unit 2' Reactor Shutdown and Unusual Event Due to Excessive Unidentified Leakage in the Drywell On May 24, 1989, the Unit 2 reactor operator noticed that-unidentified leakage in the drywell had increased. At 6:15-AM drywell unidentified leakage exceeded the Technical Specification limit of 5 gpm. An unusual event was declared at 6:20 AM, a power. reduction began-at 6:40 AM, and the NRC Emergency Operations Center was notified at 7:02 AM.
The main turbine was manually. tripped at 3:20 PM,. and the reactor was manually' scrammed at 4:00'PM.
The leakage was determined to be due to worn' packing on the
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inboard RCIC steam supply valve. This valve was repacked and the reactor restarted on May 25, 1989.
(5) Unit 2' Reactor Startup At 7:05 AM CDT o'n'May 25, 1989, the licensee commenced control rod withdrawal to restart Unit 2 following an unplanned outage due to excessive unidentified leakage in the drywell.
Criticality occurred at 9:45 AM and the main generator.
reconnected to the electrical grid at 3:05 PM on May 25, 1989.
During the drywell closeout inspection, which was conducted during power ascension, the licensee discovered the above-seat drain line'for the "D" electromatic relief valve to be broken.
The line being broken did not render the "D" electromatic relief valve inoperable, however, it would allow a pa'th for
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steam to enter the drywell should the "D" electromatic valve actuate. Rather than subject the plant to another cooldown transient, the licensee decided to take the "D" electromatic relief valve out of service rather than shut down and repair the above seat drain line. There are a total of 5 relief valves, one Target Rock and 4 electromatic, and Technical
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Specifications requires that only 4 of these be operable.
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-.The1 Target Rock and the'other 3 electromatic relief valves-were' operable and Technical-Specification requirements'were not violated.
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(6). Loss _of Secondary Containment At 12:15 AM on May.30,'1989, the reactor building to turbine
' building interlock doors at the 647. foot elevationLwere found L
.open, causing a breach of secondary containmer in violation of Technical. Specification 3.'7.C.1..
The equqment operator who found the doors open immediately shut them.
Investigation by the licensee revealed that breaker 12 or. the
- 125 VDC reactor building distribution panel 2 was cycled open and closed at 7:30 PM on May 29, 1989, c? part of a ground-
. isolation procedure. Opening breaker 12 failed power to the-electromagnetic catches of these doors, allowing the differential
, pressure between the reactor' building'and turbine building'to open them.
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The loss of. secondary containment from 7:30 PM on May 29, 1989, until 12:15 AM on May 30, 1989, with both units at power, is a violation of Technical Specification 3.7.C.1, and is considered to be a Severity Level IV violation:
.(254/89012-01(DRP); 265/89012-01(DRP)).
Because this'-
. violation satisfied the criteria of 10_ CFR 2 Appendix C
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Section V.G. (it was licensee-identified, was-promptly-reported 'and cor'ected, was Severity Level IV or V, and could not have been prevented by the licensee's corrective action for a previous violation) no Notice of Violation-will be issued.
-(7) Unit 2 Reactor Shut to Repair Two Drywell Floor Drain Sump Pumps At 5:05 PM on May 30, 1989, the licensee commenced.a normal reactor shutdown in order to repair the two drywell floor drain sump pumps.
The main generator was disconnected from the electrical ~ grid at 6:21 PM, and the reactor was manually:
scrammed at 6:29 PM. Unit 2 was placed in cold shutdown at 11:17..PM on May 30, 1989.
During this unplanned maintenance outage the licensee repaired one drywell floor drain sump pump, replaced the second drywell floor drain sump pump, and repaired the broken above-seat-drain line for the "D" electromatic relief valve.
(8) Unit 2 Reactor Startup At 9:48 PM on May 31, 1989, the licensee commenced control rod withdrawal to restart Unit 2 following an unplanned
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maintenance. outage-to repair two drywell floor drain sump pumps.
Criticality ~ occurred at 12:49 AM on June 1, 1989.
The licensee connected the main generator to the electrical grid at 6:09 PM on June 1, 1989.
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-(9) Unit 1 Recirculation Pump Trip -
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At 2:38 AM CDT on June 5,1989, licensee personnel were in the process of isolating a ground on the Unit. 2125 volt DC bus.
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The ground isolation procedure required opening the 125 volt DC backup power supply circuit breaker for the 1A recircula-
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tion pump MG set's 4160 volt AC circuit breaker. The ground'
isolation procedure cautioned that the normal 125 volt DC power supply circuit breaker be verifind shut prior. to opening the backup power supply circuit breater. The operator.
inadvertently opened the normal power supply circuit breaker instead of verifying it. shut.
This action caused the 1A2 recirculation pump MG. set oil' pump.to stop, reducing oil pressure for the recirculation pump MG set and causing the 1A
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recirculation pump to coast down. Opening the normal power supply also disabled _the IA recirculation pump MG set 4160 volt AC ' circuit. breaker's automatic trip ' functions.
The operator immediately realized his mistake and reshut the normal power supply circuit breaker. This enabled.the 1A recirculation pump MG set 4160 volt AC circuit breaker's automatic trip functions, and the 1A recirculation pump tripped'on low oil pressure at 2:41 AM on June 5, 1989.
At the time of the recirculation pump trip, Unit I was at approximately 60% power.
Power and core flow decreased, placing the reactor in a region of potential instability. No-power oscillations occurred, so the reactor operator followed the Loss of Recirculation Pump procedure by bypassing the rod worth minimizer and inserting control rods in. sequence until the reactor was below the 80% flow control line and out of the region of potential instability. This occurred at 3:28 AM.
The 1A recirculation pump was restarted at 3:40 AM on June 5,.
1989, and Unit I was returned to normal operation.
(10) Unit 1 Degraded Reactor Recirculation Pump IB Inboard Seal In early June, licensee personnel noticed that the pressure in the cavity between the inner and outer seals of the IB reactor recirculation pump was beginning to increase.
(The reactor recirculation pumps are manufactured by Byron-Jackson, and the seals are Byron-Jackson type S-U.)
Normal pressure in this
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cavity is one half of the pressure-in the reactor, or 500 psig
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when the reactor pressure is at its full power value of 1000
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Increasing cavity pressure is an indication that the inner reactor recirculation pump seal may be degrading. Cavity pressure increasing to reactor pressure (1000 psig at full
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L power) would indicate a completely failed inner seal.
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The exact date at which the cavity pressure began to increase is not known because the licensee does not normally log or record this pressure.
The earliest date at which an elevated pressure is recorded is June 12, 1989, when cavity pressure was 640 psig. As of the end of the inspection period, cavity pressure has remained relatively constant at 685 psig.
.The licensee has a permanent procedure which addresses seal failures, 00A 202-6, which permits normal full power operation if one of the two reactor recirculation pump seals is completely failed, At the request of the NRC, the licensee developed a temporary procedure on June 22, 1989, which supercedes Q0A 202-6. This temporary procedure requires the reactor operator to monitor the amount of water pumped from the drywell equipment drain tank, the pressure in the seal cavity, the differential pressure across.the seals and the seal temperatures, every four hours if the seal cavity pressure exceeds 680 psig. The licensee will notify the NRC if and when seal cavity pressure reaches 700 psig, 750 psig, and 800
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psig. At a seal cavity pressure of 800 psig the licensee will notify corporate headquarters and determine what action to take.
The temporary procedure requires the licensee to consider one or both seals failed if the amount of water pumped from the drywell equipment drain tank iricreases 85 gallons in four hours, seal cavity pressure increases to full system pressure, the outboard seal temperature reaches 155 degrees F, the inboard seal temperature reaches 175' degrees F, or either seal temperature changes 30 degrees F in four hours.
If ore or both seals is considered failed, the temporary proceduce requires the licensee to reduce power below the 80% flow control line to avoid entering the region of '.; stability, shutoff the reactor recirculation pump which has the failed seal, and isolate the affected recirculation loop.
If seal pressures do not decrease after the loop isolation valves are shut, the loop is not properly isolated and the licensee is to consider shutting down.
The licensee is considering making this temporary procedure permanent..
4.
Radiological Controls (71707)
The licenset continued to demonstrate noteworthy performance in the area of radiological controls. Unanticipated maintenance activities involving the replacement of one electromatic relief valve and three electromatic relief valve oilot valves, and the repair of a leaking head vent pipe, were performed in the Unit I drywell with no personnel contaminations.
Personnel e> posure was less than budgeted despite these and other additional unanticipated maintenance activities.
The licensee's performance, and the attention showed by management to further reduce personnel contaminations and exposure, is indicative of
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strong management support for the ALARA program.
I No violations or deviations were noted.
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a.
Aer'ial Radiation Survey
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During the/ inspection period the Department of Energy conducted an-
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aerial radiological survey of area within a.2.5~ mile radius of the Quad Cities Nuclear Power Plant. No radiation. levels above natural background radiation _ levels were found outside'of the Quad Cities'
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Nuclear Power Plant protected area fen :e.
b.
Leak in a Laundry Drain Tank' Pipe On Thursday, June 8,1989, the licensee discovered that the pipe which connected the laundry drain tank to the laundry sample tank was leaking.
The leaking radioactive liquid was discharged via a-circuitous path to the circulating water discharge canal and was
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subsequently released to the Mississippi. River.
Based on review of pump run time and tank volume records,.the licensee estimated-othat 6000 gallons (300 microcuries) had been discharged via this pathway since about May 20, 1989..The laundry liquid radioactive
. concentrations during this time period were about one. maximum'
permissible concentration. Dilution in the circulating water system reduced.these concentrations significantly such that2 Technical Specification release limits were not exceeded. The licen'ee terminated the release' path and is repairing the pipe.
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Fuel Pool Radiation Monitor Spikes High At 5:16 AM CDT on June-9, 1989, thez1A fuel pool radiation monitor spiked high. At the time there were no-. activities occurring in the vicinity of the fuel pool, and the IB fuel pool radiation monitor
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showed no abnormal increase:in radiation levels,;so'it is believed
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that the 1A fuel pool radiation monitor reading was spurious.
When the 1A fuel pool radiation monitor spiked high the reactor building vents isolated, the control room ventilation shifted to recirculation, and the standby gas treatment. system started. At
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5:26 AM the 1A fuel pool radiation monitor was bypassed, and at c
5:28 AM the ESF signal was reset. The reactor buildint~ ventilation,
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control room ventilation, and standby gas treatment systems were returned to normal. At 5:52 AM the NRC Emergency Operations Center-was notified.
5.
Maintenance / Surveillance a.
Monthly Maintenance Observation (62703)
Station maintenance activities of safety related and non-safety related systems and components listed below were observed / reviewed to ascr*tain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards.and in conformance with Technical Specifications.
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The following items wer9 considered during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable. Additional items reviewed included verification that functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; and activities were accomplished by qualified personnel. Also, the inspectors verified that' parts and materials used were properly certified; radiological controls were implemented; and fire prevention procedures were followed. Work requests were reviewed to determine the. status of outstanding jols and to assure that priority is assigned to the maintenance of safety related equipment which may affect system performance.
Portions of the following activities were observed / reviewed:
(1) Unit 2 drywell floor drain sump pump replacement.
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(2) Unit 2 "D" electromatic relief valve transmitter replacement.
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Ground Isolation.
(4) Unit 1 "B" containment atmosphere monitor calibration.
(5) 1/2 service water pump inspection.
(6) Unit 1 HPCI line weld repair.
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(7) Unit 1 RCIC line weld repatr.
(8) Unit 1 extraction steam line repair.
No violations or deviations were noted.
b.
Monthly Surveillance Observation (61726)
The inspectors observed surveillance. testing required by the Technical Specification and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, and that limiting conditions for operation were met.
Additionally, the inspectors observed / verified the removal and restoration of the affected components, and that test results conformed with Technical Specifications and procedure requirements.
Also, the inspect.crs verified that the results were reviewed by personnel other than the individual directing the test and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management pers6nnel.
One unresolved item was identified and is described in paragraph 5.b.(2) of this report.
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L(1)-~ Surveillance' activities-observedreviewed:
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(a) Unit 1-MSIV closure-functional test.
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(b) Unit 2 core flux map' ping'using the traveling incore probe.
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(c) Unit 1 monthly scram functional test.
f-(d). Unit 1 RCIC quarterly operability surveillance.
(e) Unit 1 RCIC test bypass valve functional. test.
(f) Unit 1 diesel generator surveillance.
(g) Unit 2 RHR service water operability surveillance.
(h) Unit I master trip solenoid surveillance.
(i)' Unit 1 APRM gain adjustment.
(j) 1/2 "A" standby gas treatment system tiow rate surveillance.
(2) Improp u Check Valves At 2:45-PM CDT on June 9, 1989, the licensee discovered that improper check valves were installed on the air lines to the butterfly valves in the 18 inch drywell purge _ lines for both Unit I and Unit 2.
At the time of the' discovery both units'-
were operating above 80% power.
The licensee notified the NRC Emergency Operations Center at 3:33 PM CDT on June 9,1989.
These improper check valves would have allowed the accumulator associated with each butterfly. valve to dissipate.its pressure if the instrument air system failed or if a leak developed in the air supply lihes, rendering the butterfly valves inoperable.
It_ is believed that these improper check. valves were installed.
during the_ original construction and have been in place for-the life.of each unit (over 17 years).
The licensee discovered the problem whi_le performing fail-safe surveillance tests on the air supply check valves for the 1601-23 valve (drywell main exhaust valve) on Unit 1.
These fail-safe surveillance tests are more rigorous than the previous surveillance tests which were performed. When the check valves did not perform as required, the licensee investigated and found that the check valves which were installed were model F-6'008, not model number C-600B as specified in the design drawings.
The licensee placed the 1601-23 valve in its fail-safe position (closed) and performed a visual inspection of the air supply check valves for all of the butterfly valves in the primary containment vent and purge systems of both units.
Improper check valves were found on the 1601-21 and 22 valves (drywell purge inlet valves), on the
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L 1601-23 valve (drywell main exhaust valve), on the 1601-24 valve (main primary containment exhaust valve), on the 1601-56 valve (suppression chamber purge inlet valve) and on the 1601-60 valve (suppression chamber main-exhaust valve) of each unit. Since there are two check valves associated with each butterfly valve, there are a total of 24 improper check valves.
The licensee placed all of the butterfly valves in the fail-safe position (closed) and replaced 14 F-600B check valves with C-600B check valves and modified the remaining 10 F-600B check valves such that they will function as C-6008
- a check valves.
By June 12, 1989, the licensee had restored the affected vent and purge system valves to operability. The remaining 10 F-600B check valves will be replaced with C-600B check valves when the licensee procures the valves.
The installation of improper check valves which possibly rendered six containment isolation valves in each unit-incapable of shutting upon a loss of air pressure is contrary to 10 CFR 50 Appendix B, section'V (which requires that activities affecting quality be accomplished in accordance with documented drawings) and is an unresolved item.
(254/89012-02(DRP);265/89012-02(DRP)).
6.
Emergency Preparedness (71707)
i During the inspection period the inspectors visited the Quad Cities Technical Support Center (TSC) and the Emergency Operations Facility (EOF). Minor housekeeping problems in the TSC were brought to the licensee's attention and immediately corrected.
No violations or deviations were noted.
7.
Security (7170f)
During the inspection period the inspectors toured the plant and the
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Central Alarm Station to assure that security programs were being properly implemented.
The inspectors verified that security barriers were in place, security doors were operable, the security force was
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alert, personnel correctly displayed their identifi ation badges and i
visitor access was being properly controlled.
No violations or deviations were noted.
8.
Engineering / Technical Support
a.
Installation and Testing of Modifications (37828)
During the inspection period the resident inspectors monitored several major plant modifications including, installation of reactor feedwater hydrogen-addition equipment and controls on
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both Units 1 and 2; modification of the control room lighting and heating, ventilation and air conditioning; installation of a Unit 2 125 VDC temporary battery; and installation of new discharge piping for the Unit 2 RHR service water system. All modifications j
were being constructed with minimal problems or disruption of plant activities.
Particularly noteworthy were the temporary battery installation and the control room lighting and heating, ventilation and air conditioning modifications.
Both were extremely complex and demanding, yet were completed professionally with no adverse affect upon plant operation.
NG violations or deviations were noted.
b.
UFSAR Discrepancies
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Revisions 5 and 6 to the Quad Cities Updated Final Safety Ar:1ysis Report (UFSAR),datedNovember 20, 1987 and July 27, 1988 (respec-tively), were reviewed and several deficiencies and/or discrepancies were identified. NRR had previously identified various findings to CECO by a letter dated June 7, 1989. The NRC letter requested that CECO respond to the specific findings identified as well as generic l
implications to other CECO stations's UFSAR. Examples of findings from Revision 5 are described below:
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(1) Figure 3.2.11 was replaced with a new power-flow map.
The discussion of the operating characteristics remained unchanged. The new figure used a 20% pump speed line, whereas, the discussion references a 30% pump speed line.
This discrepancy'could lead to confusion and misunderstanding, and should be clarified in a subsequent FSAR revision.
(2) Section 7.9 describes the Rod Worth M?nimizer (RWM). The RWM was replaced with a new system. The cew RWM uses terms like sequence step, sequence array, and latched step. Although the new terms are defined, some previous descriptions remained unchanged and reference tems from the old pWM, such as, rod group, The definition for group was deleted in the revision and it is unclear as to whether this term can be used in describing the new RWM. The description appears to be inconsistent with the new RWM and should be clarified in a subsequent FSAR revision.
(3) Comparison of FSAR Table 7.7.3 and Technical Specification (TS) Table 3.7-1 (primary c.ontainment isolation groupings)
i identified discrepancies in the group descriptions. This was
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not due to an FSAR u)date.
It appears that the TS should be revised to reflect ue current description.
FSAR Table 7.7.2 was revised to sange terms (e.g., steamline j
high rad changed to Hi-Hi) and setpoints (e.g., drywell (DW)
i hi rad changed from 2000 R/hr to 100 R/hr).
No basis (i.e.
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50.59 safety evaluation) could be found for these changes.
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(4); Section' 2.8.e was changed to reflect a modification to the Sodium'Hypochlorite storage tank. This tank is used for water
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chlorination of.the circulating water and service water systems.
' The modification changed the underground 30,000 gallon. tank'to.
an above ground 6,000 gallon tank.
Documents reviewed for.
information regarding this modification' included the monthly operating reports, correspondence, annual reports, and performance reports for 1986 and 1987. Neither a.10.CFR 50.59 evaluation nor references to the existence of.such an evaluation were found.
(5) A 10 CFR 50.59 evaluation or reference.to the existence of one was not found for-the modification to the RWM discussed above-in item two.
(6) -Modification M-4-2-81-24 (Suppression Pool Temperature Monitoring System) reported in compliance with 10 CFR 50.59 by letter dated December 1, 1986, from R. Robey (Ceco) to E. Case-
-(NRC), was not described within the FSAR, (7) UFSAR Table 6.7.1 " Design Low Level Solution Volume" of.
3470 gallons does not correspond with the minimum required Technical Specifications tank volume of 3733 gallons.
Examples of findings from the review of Revision 6' are described.below:
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(1)-0peratingmodesoftheRdactorWaterCleanupSystem(UFSAR Section 10.3.3.1) were re<ised without any apparent-10 CFR 50.59 evaluation.
-(2) Analysis of boraflex degradation of storage racks in the Spent Fuel Pool -that consti:uted configuration changes and reductions in the sub-criti:ality margin were not addressed in the FSAR.
(3) An-additional off-site 345 KV power line (UFSAR Section 8) was connected to the switchyard ring bus without acly apparent 10 CFR 50.E9 evaluation.
(4) Analysis conducted to resolve safety issues associated with Embedment Plates and Piping Configuration Control were not addressed in the UFSAR.
An additional example of a discrepancy is UFSAR Table 5.2.5, which states that the power to close valves 1601-21 and 22 (the drywell purge inlet valves), 1601-23 (the drywell main exhaust valve),
1601-24 (the main primary containment exhaust valve), 1601-24 (the
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main primary. containment exhaust valve), 1601-56(thesuppression chamber purge inlet valve), and 1601-60(thesuppressionchamber
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main exhaust valve) is a spring. The actual power to close these L
valves is air.
Collectively (while these findings are contrary to 10 CFR 50.34(b),
10 CFR 50.59 c) and 10 CFR 50.71(e), the NRC is awaiting Ceco a
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l actions before reaching an enforcement decision. These findings d
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are considered to be an unresolved item (254/89012-03(DRP);
265/89012-03(DRP)).
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j 9.
Safety Assessment / Quality Verification j
Evaluation of Licensee Quality Assurance Program Implementation
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a.
(35502)
(1) Quality Assur=nra During the inspection period the Senior Resident Inspector observed quality assurance inspecting portions of the following activities:
(a) Preventive maintenance of the IB instrument air drier.
(b) Transfer of DC power from the Unit 2 battery to the temporary battery.
(c) Unit 2 reactor startup on May 25, 1989.
In all instances the quality assurance inspectors were
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thorough and conscientious.
(2) Quality Control During the inspection period the 3enior Resident Inspector observed quality control inspections of portions of the following activities:
(a) Fabrication and installation of the Unit 2 temporary 125 volt battery racks and conduit.
(b) Installation of the control room ceiling and HVAC modifications.
(c) Unit'1 RCIC test bypass valve breaker functional test.
In all instances the quality control inspectors were thorough and conscientious.
b.
In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities (90712) and Onsite Followup of Written Reports of Nonroutine Events At Power Reactor Facilities (92700)
During the inspection period the resident inspectors reviewed incidents such as scrams, ESF actuations and component failures which occurred at other plants.
The resident insperctors informed the licensee of the details of all events which potentially had applicability to components or activities at Quad Cities.
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LER Review (1) (Closed) LER 265/88019-LL:
Engineered Safety Feature Actuations While Taking Valve 2-1601-56 Out of Service Due to Personnel Error.
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This event is describtd in Paragraph 2.f of this report.
.(2) (Closed) LER 265/89002-LLi Drywell Floor Ocain Leakage in Excess of 5 gpm Technical Specification Limit.
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This event is' discussed in paragraph 3.d.(3) of this report.
The leakage has been repaired by repacking the valve. A work request has been written to replace the packing with live-load packing.
This item is considered closed.
(3) (Closed) LER 254/89005-LL:
At 2:35 PM on May 22, 1989, RCIC was dec'ared inoperable when
.j a differential pressure switch used to is olate the system on
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steam line high flow could not be calibrited. The event was
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caused b; a worn trip set point locking nechanism which prevented the switch from tripping at the correct setpoint.
The locking screw broke while trying to ecalibrate the switch, which rendered the switch inoperable. The switch wa,s replaced and the new switch calibrated. RCIC was. returned to service at 6:00 PM on March 24, 1989.
Technical Staff personnel inspected all other accessible Barton differential pressure switches (Model 288,188A, 289 and 289A) installed at Quad Cities.
Five discrepancies were found, none of which affected the switch operability, and work requests were written to repair these discrepancies.
This item is considered closed, c.
Temporary Instructions (1) (Closed) Temporary Instruction (TI) 2515/17:
Inspection Guidance for Heat Shrinkable Tubing (25017).
The Temporary Instruction required verification of how the licensee addressed IE Information Notice 86-53, " Improper Installation of Heat Shrinkable Tubing."
The inspector reviewed the following procedures and records:
(a) QEMP 700-4, "Raychem Heat Shrink Installation
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Instructions" (b) QEMP 700-4-51, "Raychem WCSF-N In-Line Splice 7nstellation Instructions" (c) QEMP 700-4-T1, "Raychem WCSF-N Tables and Formulas"
I (d) QEMP 700-4-T2, "Raychem WCSF-N In-Line Splice Examples"
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(e) EQ test documentation, " Environmental Qualification of
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' Raychem Connection / Sealing Assemblies"
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(f)' Quality Control Inspection Number 86-58.
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(g).Raychem training record,LJuly 7, 1985.
(h) Work request numbers 75462, 75463, and 71631.
A Quality Control Inspect 4n of 20 splices'was performed in May 1986-after Quad Cities learned of the problems at Dresden 13.
Several problems were noted on splices for: solenoid valves SP-1-1601-50A and.50-1-1601-50B, however, the environmental qualification coordinator determined that qualified heat shrink was not required on these valves and that heat shrink-was.only used-for added insulation. No other problems were found.
.The, licensee's procedures incorporate.the vendor's applicatio'n
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guide.to. plan and install each splice.
For example, the procedure verifies splices are not installed over braiding and ensures the proper splice kit or bulk material is-used.(size and qualification), adequate s W ee overlap and minimum bend radius are provided, and the splices are properly cooled prior to placement fin conduit or junction box. When Raychem solice kits are used, the mechanics use the instructions pre sad in
'the kit, Raychem provided a hands-on workshop to the electrical maintenance and' instrument maintenance staff and quality control inspectors in July 1986, in addition to in-house training in May 1986. The inspector reviewed three work requests that installed Raychem splices.and verified that they were.in accordance with approved procedures; and the installers and Quality Control (QC) inspectors were qualified.
The procedures'do not require a QC inspector to observe the installation of the splice, hc Wyer.
Either QC'or Quality Assurance (QA) was presen durke the installation.of the
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splices in the work requests reviewed.. The inspector.was informed that QC policy.is to witness the installation of selected splices depending on wcrk load.
This Temporary Instruction and associated Information Notice are considered closed.
(2) (Closed) Temporary Instruction 2515/93:
Inspection for Verification of Quality Assurance Request Regarding Diesel Generator Fuel Oil Action Item A-15 (25593).
The inspector verified that the licensee's QA manual, Quality Procedure Q. P. No, 4-51, ' Procurement Document Control for Operations Processing purchase Document", Attachment A,
" Instruction for S icifying Quality Assurance Documentation",
Paragraph 3.10, " Diesel Fuel", addresses the area of concern.
'i Fuel Oil (#1 grade) is purchased commercial grade from Royal
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. Fuel Liquid. Energies,IInc. with a Cr* tificate of-Conformance to ASTM-D-975-77 and ASTM-D-2274. The fuel oil is classified'~
.as safety-relcted for final u,cc oy procedure QAP 400-T4,
" Dedicated Upgrade Form". A fuel oil sample is sent to System Materials Analysis Department (SMAD) where. it is' analyzed in
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conformance with NRC Regulatory Guide 1.137,'" Fuel-011 System
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For> Standby Diesel Generators". The inspector also verified that the licensee has procedures in place for receipt-inspection (QOP 6600-7, " Receiving) Diesel 011"),:and sampling (QCP 1300-6, "011 System Sampling", of fuel oil.
i This Temporary instruction is considered closed.
E d.
Evaluation of Licerisee Self-Assessment Capability -(40500)
During the inspection period the Senior Resident Inspector attended On-Site Review Committee meetings on several occasions.
In each instance. the committee was properly staffed, adequately addressed the relevant issues, and demonstrated adequate concern for reactor..
safety. ' On-Site Review Committee meetings which addressed the following subjects were observed:
(1) Unit 2_ battery modification.
(2) Unit l'RCIC inoperability.
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(3) Loss of ' secondary containment.
(4) Automatic Depressurization System cable. separation modification.
No violations or deviations were.noted.
E 10. Management Meetings - Entrance and Exit Interviews (30703)
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The inspectors met with licencee' representatives (denoted in Paragn ph 1)throughouttheinspectionperiodandattheconclusionofthe inspection on June'23, 1989, and summarized the scope and findings of the inspection activities.
The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the-j inspectors de ing the inspection. The licensee did not identify an)
such document,/ processes as proprietary.
Attachment: Review of the Quad Cities Updated Final Safety Analysis Report, Revisions 5 & 6 (Tac Nos.
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67017,67018,69004,and,69005)
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UNITED STATES S{
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$
NUCLEAR GEGULATORY COMMISSION
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. wAsHtNGTON D. C. 205S5 pI
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June 7,'1989-l
' Docket Nos. 50-254' arH 50-265
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Mr. Thomas ' Nuclear. Licensing Manager
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Connonwealth Edison Company Post Office Box 767 Chicago, IL 60690
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Dear Mr. Kovach:
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SUBJECT:
REVIEW 0F THE QUAD CITIES UP0ATED. FINAL SAFETY ANALYSIS REPORT, REV!SIONS 5 & 6 (TAC NOS. 67017,67018,69004cAND.69005)
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' REFERENCES:
(a)' November 20, 1987 letter from I.i. Johnson I
(Ceco) to H.R. Denton (NRC) - UFSAR Rev. 5;
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(b) July 27,1988 letter from I.M. Johnson (CECO) to U.S.NRC - UFSAR Rev. 6
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.Inaccordancewiththerequirementsof10CFR50.71(e),CommonwealthEdison-Company (Ceco) subnitted references (a) and.(b), Revisions 5 and 6 of.the
. Quad Cities Updated Final l Safety Analysis Report (UFSAR),: to us.. We reviewed a sampling.of the UFSAR sections affected by these revisions for accuracy, b
consistency, and appropriateness. Enclosed is a : list detailing our. specific f
findings.'
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From the results of our review, we have concluded.the following:
(1) CECO failed to comply with the annual filing requirement of 10CFR50.71(e)(4)-Rev.5wasissued5monthslate.
p (2) Since no summarized outline or description detailing the scope and context of UFSAR changes was' provided, it could not be determined L
that the"UFSAR revisions represented all facility changes completed F
no later than a maximum of 6 months prior to filing.
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i, (3). Changes made under the provisions of 10 CFR 50.59, but not previously submitted to the NRC, were'not. identified as required by
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If no such changes were made, this was indeterminate from the submitted UFSAR revisions.
(4) Some applicable facility changes reported to tne NRC in accordance with 10 CFR 50.59 were not incorporated in the UFSAR as required by 10CFR50.71(e).-
(5) Some changes incorporated in the UFSAR were not evaluated and/cr
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reported in compliance with 10 CFR 50.59.
.(6) Certain UFSAR changes require further clarification to achieve adequate consistency.
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I (7) Lists of all current pages, after replacement, were not provided to NRC for UFSAR Figures and Appendices as' required by 10 CFR 50.71(e)(1)..
(8)_ Some analyses performed by or on behalf of Ceco, at the NRC's request,_
for new safety issues were not included as part of revisions to the UFSAR, as required by 10 CFR 50.71(e).
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In general, except for the above, CECO has followed the requirements of
.10CFR50.71(e). However, the significance of our findings and determinations indicates' prompt and comprehensive corrective actions are warranted by Ceco to assure future UFSARs for the Quad Cities Station are submitted in compliance-with regulatory requirements..Upon receipt of this letter, CECO is requested to provide us within the next ninety. (90) days a response that addresses our conclusions (listed above)_and specific findings (enclosed). This response L
should also detail the scope and schedule of. proposed corrective actions.. Any I
and all UFSAR discrepancies or deficiencies identified in the enclosure should be reconciled in the next UFSAR revision.: Furthermore, we recomend that CECO
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review the applicability of our findings and conclusions as " lessons learned" to; ensure other station's UFSARs comply with regulatory requirements.
Potential enforcement actions regarding failure to comply with portions of 10 CFR 50.71(e) are being discussed with Region III. You will be notified in.
the near future concerning our consensus decision. Should you need any detailed-clarification or additional information related to this review of' references (a)'and(b),donothesitatetoask.
hierry M. Ross, Project Manager Project Directorate 111-2
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Division of Reactor Projects III, IV, V, and Special Projects Enclosure:
As stated cc w/ enclosure:
See next page
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ENCLO5URE FINDINGS.FROE REVIEW.0F. REVISIONS.S.AND 6 TO QUAD CITIES. UPDATED. FINAL.5AFETY. ANALYSIS REP 6RT We have completed our review of CECO's update to the Quad Cities Final Safety AnalysisReport(FSAR), Revisions 5and6,datedNovember 20, 1987 and July 27, 1988 (respectively). A sampling of FSAR sections affected by these updates were reviewed and several deficiencies and/or discrepancies were identified.
Examples of our findings from Revision 5 are described below.
(1) Figure 3.2.11 was replaced with a new power-flow map. The discussion of the operating characteristics remained unchanged. The new figure used a 20% pump speed line, whereas, the discussion references a 30% pukp speed line. This discrepancy cou'1d lead to confusion and misunderstanding, and should be clarified in a subsequent FSAR revision.
(2) Section7.9describestheRodWorthMinimizer(RWM).
It appears that the
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RWM was replaced with a new system. The new RWM uses terms like sequence step, sequence array, and latched step. Although, the new terms are defined, some previous descriptions remained unchanged and reference terms from the old RWM, such as, rod group. The definition for group was deleted in the revision and it is unclear as to whether this term can be used in describing the new RWM. The description appears to be inconsistent with the new RWM and should be clarified in a subsequent FSAR revision.
(3) ComparisonofFSARTable7.7.3andTechnicalSpecification(TS)
Table 3.7-l'(primary containment isolation groupings) identified discrepancies in the group descriptions. This was not due to an FSAR
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update.
It appears that the TS should be revised to reflect the current description.
FSAR Table 7.7.2 was revised to change terms (e.g., steamline high rad changedtoHi-Hi)andsetpoints(e.g.,DWhiradchangedfrom2000R/hr to100R/hr). No basis (i.e. 50.59 safety evaluation) could be found for these changes.
(4) Section 2.8.e was changed to reflect a modification to the Sodium Hypochlorite storage tank. This tank is used for water chlorination of the circulating water and service water systems. The modification changed the underground 30,000 gallon tank to an above ground 6,000 gallon tank. Documents reviewed for information regarding this modification included the monthly operating reports, correspondence, annual reports, and performance reports for 1986 and 1987. A 10 CFR 50.59 evaluation or reference to the existence of one was not found.
(5) A 10 CFR 50.59 evaluation or reference to the existence of one was not found for the modification to the RWM discussed above in item two.
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-2-(6) Modification M-4-2-81-24 (Suppression Pool Temperature Monitoring System) reported in compliance with 10 CFR 50.59 by(NRC), was not letter dated December 1,1986, from R. Robey (CECO) to E. Case described within the UFSAR.
(7) UFSAR Table 6.7.1 " Design Low Level Solution Volume" of 3470 gallons does not correspond with the minimum required Technical Specifications tank volume of 3733 gallons.
Examples of findings from our review of Revision 6 are described below.
(1) Operating modes of the Reactor Water Cleanup System (UFSAR Section 10.3.3.1) were revised without any apparent 10 CFR 50.59 evaluation.
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(2) Analys.is of boraflex ' degradation of storage racks in the Spent Fuel
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Pool that constituted configuration changes and reductions in the sub-criticality margin were not addressed in the UFSAR.
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(3) An additional off-site 345 KV power line (UFSAR Section 8) was connected to the switchyard ring bus without any apparent 10 CFR 50.59 evaluation.
(4) Analysis conducted to resolve safety issues associated with Embedment Plates and Piping Configuration Control were not addressed in the UFSAR.
Principal Contributors:
T. Ross P. Rescheske Dated: June 7, 1989
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