IR 05000213/1988019
| ML20196E584 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 12/01/1988 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20196E575 | List: |
| References | |
| 50-213-88-19, IEIN-85-071, IEIN-85-71, NUDOCS 8812120041 | |
| Download: ML20196E584 (16) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-213/88-19 Docket No.
50-213 License No.
DPR-61 Licensee:
Connecticut Yankee Atomic Power Company P. O. Box 270 Hartford, CT 06101 Facility:
Haddam Neck Plant, Haddam Neck, Connecticut Inspection at: Haddam Neck Plant Inspection dates:
September 28 through November 15, 1988 Inspectors:
Andra A. Asars, Resider.t Inspector Joseph A. Golla, Reactor Engineer, DRS John T. Shediosky, Senior Resident Inspector Approved by:
1 O. k N,hv
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l2lil&g E. C. McCabe, Chief, Rsactor Projects Section 18 Oate Summary:
Inspection 50-213/88-19 (9/28/88 - 11/15/88]
Areas Inspected: This was a routine safety inspection of plant operations, radi-ation protection, fire protection, security, maintenance, surveillance testing, licensee events, open items, the Containment Integrated Leak Rate Test Report, and licensee actions in response to a a steam leak in the reactor containment, a failed circulating water pump, and soil contaminated with radioactive material.
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Results: No violations were identified. No new Unresolved Items were opened.
Two Unresolved Items were closed.
No unacceptable conditions were identified.
I GG12120041 881202 PDR ADOCK 05000213 i
O PDC
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TABLE OF CONTENTS PAGE 1.
Summary of Facility Activities.......................................
2.
Review of Plant Operations...........................................
3.
Plant Operations Review Committee....................................
4.
Obs2rvation of Maintenance and Surveillance Activities...............
4.1 Circulating Water Pump Repairs...........
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4.2 Emergency Diesel $ tart Failure During Redurdant System Test.....
4.3 Steam Generator level Connection Leak Repairs.
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5.
Followup on Previous Inspection Fiau1ngs.............................
5.1 Acceptability of Auxi!1ary Feedwater System Design Basis........
5.2 Temperature Stabilization Be' ore Recalibration of RPI...........
6.
Followup on Events Occurring During the Inspection...................
6.1 Licensee Event Reports......................
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6.2 Power Reduction Following Circulating Water Pump Failure........
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6.3 Contaminated Soil Discovered 0nsite.............................
6.4 Power Reduction Af ter Traveling Water Screen Failure............
7.
Review of Periodic and Special Reports.........
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8.
Annual Emergency Preparedness Exercise...............................
9.
Report of a Substantial Safety Hazard Involving RCS Vent Valves......
10. Containment Integrated Leak Rate Test Results Review................
11.
Exit Interview.......................................................
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DETAILS 1.
Summary of Facility Activities At the beginning of the inspection period, the plant was operating at full power.
On September 27, the "C" Circulating Water Pump failed.
Power was immediately reduced to loss tnan 65%.
Following pump repair, full power operation resumed on October 1.
Another power reduction to less than 65%
power was conducted on October 25 due to failure of the "0" traveling water screen drive mechanism.
The plant was returned to full power on October 26 and continued to operate at full power.
2.
Review of Plant Operations (71707)
Plant operations were observed during regular tours cf the following.
Control Room Security Building
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Primary Auxiliary Building Fence Line (Protected Area)
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Vital Switchgear Room Yard Areas
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Diesel Generator Rooms Turbine Building
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Control Point Intake Structure and Pump
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Building Control room instruments were observed for correlation between channels and for conformance with Technical Specifications.
The inspector observed various alarm conditions which had been received and acknowledged.
Operator awareness of and response to these conditions were reviewed. Control room and shift manning were compared to regulatory requirements.
Posting and control of radiation and high radiation areas were inspected.
Compliance with Radiation Work Permits and use of appropriate personnel monitoring devices were checked.
Plant housekeeping controls were observed, including control and storage of flammable material.
The inspector also examined the condition of various fire prot?ction systems.
During plant tours, logs and records were reviewed to determine if entries were properly made and communicated equipment status /
deficiencies.
These records included operating legs, turnover sheets, tagout
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and jumper logs, process computer printouts, and Plant Information Reports.
i The inspector observed selected aspects of plant security including access control, physical barriers, and personnel monitoring.
In addition to normal utility working hours (7:00 a.m. to 3:30 p.m., weekdays),
plant operations was reviewed on the following days:
October 4, 1933 until 8:45 p.m.
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October 10, 1933 2:30 p.m. through 5:30 p.m.
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October 15, 1938 6:30 a.m. through 6:00 p.m. (during emergency exer-
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cise.
October 26, 1933 until 7:30 p.m.
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No unacceptable conditions were identified.
Operators were alert and dis-played no signs of inattention to duty or fatigu *
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3.
Plant Operations Review Cammittee (PORC) (71707)
The inspector attended several Plant Operations Review Committee (PORC) meet-ings.
Technical specification 6.5 requirements for required member attendance were verified. Meeting agenda included procedural changes, proposed changes to the Technical Specifications, and field changes to design change packages.
Meetings were characterized by frank discussions and questioning of proposed changes.
In particular, consideration was given to assuring clarity and con-sistency among procedures.
Items for which adequate review time was not available were postponed to allow committee members time to review and comment.
Dissenting opinions were encouraged.
The inspector had no further comments.
4.
Observation of Maintenance and Surveillance Testing (61726, 62703)
The inspector observed various maintenance and problem investigation activi-ties for: compliance with requirements, applicable codes and standards; Qual-ity Services Department involvement; safety tags; equipment alignment and use of jumpers; personnel qualifications; radiological controls; fire protection; retest; and reportability. Also, the inspector witnessed selected surveil-lances to determine whether properly approved procedures were in use, test instrumentation was properly calibrated and used, technical specifications were satisfied, testing was performed by qualified personnel, procedure de-tails were adequate, and results satisfied acceptance criteria or were pro-perly dispositioned.
Portions of the following activities were reviewed.
Circulating Water Pump C Repair.
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Certrol Rod Drive Motor Generator Set 1A Preventive Maintenance.
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Control Rod Drive Motor Generator Set IB Repair and Preventive Mainten-
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Componer*. Cooling Water Pump P-13-1A Shaft Seal Replacecent.
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lenporary Repair of Steam Leak on piping as;ociated with No.1 Steam
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Circulating Water Intake Traveling Screen Repair.
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Rebuild of Charging Pump tsare rotating assembly.
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Construction of the Appendix R Electrical Switchgear Building.
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Installation of seal flush water lines on Component Cooling Water Pumps
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per PDCE-88-38.
Repair of air leaks on the No. 2 and 4 Steam Generator Feedwater Regu-
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lating Valve Positioners.
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SUR 5.1-4, Emergency Core Cooling Systems Hot Operational Test.
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SUR 5.1-17, Emergency Diesel Generator 28 Manual Starting and Loading
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Test.
SUR 5.1-62, Reactor itainment Personnel Hatch Local Leak Rate Test.
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SUR 5.2-65, Safety Grade Automatic Initiation of Auxiliary Feedwater.
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SUR 5.7-25, Inservice Inspection Testing of Residual Heat Removal and
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High Pressure Safety injection Pumps.
4.1 Circulating Water Pump Repairs (62703)
During full power operation on September 27, the "C" Circulating Water (CW) pump failed. The operational impact of this failure is discussed in detail 6.2 of this inspection report.
Pump troubleshooting and repairs were conducted under Authorized Work Order (AWO) 88-8677.
Upon pump removal, it was identified that the pump coupling had broken.
The coupling and shaft were replaced with spares.
Also, an eroded pump endbell was replaced.
Removal of the pump was delayed by interference from a seismic support for the Cervice Water (SW) header.
The support is designed to carry compression forces from the SW header during a seismic event.
The lic-ensee elected to unbolt the support and slide it over approximately two inches to permit both removal and reinstallation of the CW pump.
The support was held in place by clamps when it was in the shifted position.
These evclutions were controlled as jumper /lif ted leads 88-33 and 88-34.
Pump removal and reinstallation took about 30 minutes each.
An engineering evaluation was performed to determine the ef fects of shifting the support on SW System operability.
The licensee concluded
that the capability of the support to perform its intended function would
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not be compromised by shifting the support and securing it with clamps for a short pericd of time.
Pump repairs were completed on September 30 and the plant was returned to full power operation on October 1.
4.2 _ Emergency Diesel Start Failure During Redundant System Test (71707, 61726)
The licensee conducted preventive maintenance on Emergancy Diesel Gene-rator 2A on Noveeber 1.
This included semiannual testing of the engine i
l redundant starting systems.
During that test, the licensee discovered a characteristic of the engine start control circuit which had not pre-l viously been recogn' zed.
Section 6.6 of PMP 9.5-21, Revision 17 was used l
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to demonstrate that one of the two sets of engine air start motors oper-ated through their starting sequence.
This was to be accomplished by deenergizing part of the engine start logic (an abnormal power supply lineup).
The engine air start motors did not operate on November 1.
The licensee determined the cause to be that an engine cooldown time delay had not yet reset.
Evidently, this had not been observed in the past because normal delays in performing sequential steps of the procedure had allowed the time delay to reset.
To correct the problem the licensee has drafted a revision to the pre-ventive maintenance procedJre.
Inspector review found that the engine start logic had operated as de-signed.
Pressing the engine "Normal Stop" pushbuttons started the engine automatic cooldown sequence and its fif teen (15) minute time delay.
Selecting the "Preferred Start" switch to "Position 1" with Start Circuit
"1" logic power breaker open, resulted in the governor being reset for full speed operation. When the engine cooldown time delay was completed, the start failure circuit would then sequence the redundant air start motors.
This event did not present a safety concern because the s+.arting logic had intentionally been placed in an abnormal and degraded condition in which a standby Emergency Diesel Generator is not considered operable.
Additionally the inspector concluded that at least one set of engine air start motors w: id have operated if:
(a) the engine cooldown timer completed its sequence; (b) the "Preferred Start" switch was positioned to "Start 2" with power to either Start Circuit "1" or "2"; or (c) while in "Start 1",
power was available to that start circuit.
The folicwing d:c u ents were reviewed.
PMP 9.5-21, Semiannual Test of Emergency Diesel Redundant Systems,
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Revision 17, dated February 16, 1988.
Tenporary Procedure Changes88-641, -642, and -643 to PMP 9.5-21,
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dated November 1, 1988.
Operating "anual 999 System Generating Plant, dated 0:tober 1969.
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Drawing 16103-31099, Sh. 1, Schematic Wiring Diagram Equipmer,
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location Chart for Diesel Generators EG2A and EG2 '
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Drawing 16103-31099, Sh. 2, Schematic Wiring Diagram Emergency
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Generator Annunciator.
Drawing 16103-31099, Sh. 3, Schematic Wiring Diagram Electrical
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Control Panel and Engine Control Panel.
Drawings 16103-32001, Sh. 5F, 5FA, 5FB, and 5FC, Schematic Diagram
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4160v Emergency Bus 8 Undervoltage Trip Lockout & Loading.
Memorandum Danielson to Bouchard, EG-2A Redundant Systems Test,
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dated November 4, 1988, Serial MSM-88-318.
Although there were no unacceptable conditions identified, future engine testing will be reviewed when accomplished.
4.3 Steam Generator Level Connection Leak Repairs (62703)
On November 9, during a routine monthly containment entry and inspection, the licensee identified a small steam leak from an unused, two-inch level connection on the No. 1 Steam Generator.
The level tap is located on the charging floor level of containment.
The leak was observed to be blowing steam in a 45 degree arc about two feet long. Nonconformance Report 88-112 was issued for repair.
The licensee used Furmanite to repair the level tap.
The Furmanite de-sign required a two piece casing to be fitted over the leaking pipe and sealed on the seams and ends with Furmanite compound.
Furmanite and Northeast Utilities Service Company (NUSCO) Engineerir; reviewed this design including seismic and pipe stress considerations (Reference Fur-manite Project No. NL3113 Procedure No. N-88408, and Memo Cheskis to Kasuga, CY, Steam Generator Level Connection Leak, dated November 9, 1988). These were attached to the NCR Repair Disposition.
Repairs were completed on November 10 and the leakage stopped.
The inspectors reviewed the NCR and associated calculations.
No dis-crepancies were identified.
However, the pipe stress engineering may be reviewed during future inspections, 5.
Followup on Previous Inspection Findings (92701)
5.1 Accqptability of Auxiliary _Feedsater System _ Design Basis (Closed) Unresolved Item (85-2_0-02): This item was opened in response to licensee identification of discrepancies in the design basis of the Auxiliary Feedwater (APd) System.
These included inaccurate modeling of reactor coolant system behavior on a loss of feedwater and possible AFW susceptibility to single failures.
The licensee reanalyzed this system and incorporated the reanalysis in the revised Final Safety An-alysis Report, Chapter 15, Accident Analysis. The adequacy of the AP4
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system design was reviewed by the NRC and accepted during review of the Accident Analysis.
The Accident Analysis Safety lvaluation was trans-mitted to the licensee on October 18, 1988.
5.2 Temperature Stabilization Before Recalibration of RPI (Closed) Unresolved Item (38-11-01): Licensee to determine an appropriate temperature stabilization time before recalibration of the Digital Rod Position Indication (RPI).
Since initiating this item, it has been necessary for the licensee to recalibrate RPI during several plant power manipulations.
The licensee assured in each instance that RPI was re-calibrated after temperature stabilization for several hours and well within the six hours permitted by Technical Specification 3.10.2.2.
The inspector randomly verified that calibrations were performed in a timely manner and had no further concerns.
6.
Followup on Events Occurring During the Inspection 6.1 Licensee Event Reports (LERs) (92700)
The followir.g LER was reviewed for clarity, accuracy of the description of cause, *.nd adequacy of corrective action.
The inspector determined whether fi rther information was required and whether there were generic implicatians.
The inspector also verified that the reperting require-ments of 10 CFR 50.73 and Station Administrative and Operating Procedures had been met, that appropriate corrective action had been taken, and that the cont nued operation of the facility was conducted witnin Technical Specificttion Limits.
88-20 Fire Scenario Inside Containment Not Part of Appendix R
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Schedular Exemptions.
No discrepancies were identified.
6.2 Power Reduction Following Cir_culating Water Pump Failure (61726, 71707)
On September 27, with the plant at full power, cperations personnel per-formed condenser waterbox backwashing. During backwashing, the corres-pending condenser Circulating Water (CW) Pump must be temporarily shut down.
During restart of the "C" CW pump, the pump failed to return to normal running amperage and was declared inoperable. Operations person-nel immediately started a load reduction to 50's power to reduce the high backpressure in the
"B" condenser and the high differential pressure between condenser water boxes.
F, ant load was stabilized at 50*. power after cbout t.2 ninutes.
The CW pump was removed from service for investigation and subsequent repair; this is discussed in section 4.1 of this repor _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _
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About 16 minutts into the power reduction, the Axial Offset (A0) alarm annunciated; this was attributed to the rapid rate of manual control rod insertion to acco*,modate the load decrease. The alarm function is set at 2% inside the 10chnical Specification (TS) Figure 3.17-A limit for 100% power.
The alurm does not vary with power and will come in prema-turely at lower power levels. Upon receiving the alarm, operations per-sonnel referred to the TS figure and determined that A0 was outside the TS limit. At approximately 55% power the TS limit for A0 is -30%; Power Range Nuclear Instrument Channel 31 indicated actual A0 to be -32%.
The action statement for TS 3.17.1 requires that, under these circumstances, actions be taken to bring A0 within the limits within two (2) hours or thermal power be reduced to less than 40% power.
In accordance with the TS and SUR 5.1-26, Axial Offset Control, operators initiated boration and returned the A0 to within the TS limits in about 37 minutes.
The SUR also requires that, when the A0 alarm is in, hourly logs are taken to verify that A0 is within the TS limits. The A0 alarm was lit several times during reduced power operation on September 27 and 28.
The in-spector reviewed the completed surveillance procedures and verified that actions taken were appropriate.
During the load reduction, Control Rod Position Indication (RPI), as displayed by the process computer, indicated that several control rods in banks A, C & D were below the insertion limits of TS Figure 3.10-1.
These banks were required to be in the full out position (320 steps).
No control rod movement had been initiated for these banks and the step counters indicated that they were not below the insertion limits.
Opera-tions personnel moved these banks out to 324 steps and the RPI then in-dicated that all of the rods were above 320 steps. About 16 minutes later, RPI again indicated that several rods in banks A, C & D were below the insertion limits. TS 3.10.2.5 and 3.10.2.6 govern the insertion limits for banks C & 0 (the shutdown banks) and bank A, respectively.
The action statement for the shutdown banks is more restrictive and was applied.
The shutdown banks were declared inoperable per TS 3.10.2.5.a.
The TS 3.10.2.1.c action statement states that the plant must be placed in hot standby within six (6) hours under these conditions.
Instrument &
Controls technicians were called in to recalibrate RPI.
The recalibra-tion for the three rod banks was completed within three hours, well be-
fore expiration of the TS action statement.
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Changes in RPI indication during reactor manipule' ans have been observed before and are discussed in NRC Inspection Report 50-213/88-11. Opera-
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tions and Instrument & Controls personnel responses were in accordance with TS and station procedures and policies.
On September 28, power was increased to 65% and remained at that level until the CW pump was repaired and returned to service.
The plant was returred to full power operation on October 1.
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6.3 Contaminated Soil Discovered Onsite (71707)
On October 11, during excavation of a trench in support of the Appendix R Electrical Switchgear Building construction, the licensee identified contaminated soil under paved blacktop in the area between the Service Building and the Auxiliary Feedwater Pump Room. The affected area is inside the Station Radiologically Control Area (RCA).
Soil excavated from within the RCA is surveyed for beta gamma radicac-tivity.
In addition, soil samples receive gamma energy spectral analysis for isotopic identification prior to removal from the RCA. Much excava-tion for the new Electrical Switchgear Building has been for the con-struction of underground electrical conduit banks, and the soil has been handled within the requirements of Station Radiation Protection Procedure RAP 6.2-14, Unconditional Radiological Release of Material Offsite, Re-vision 5, dated October 14, 1987, and the applicable Radiation Work Per-mit.
The inspectors have observed that licensee personnel have treated soil as radiologically contaminated until analysis has shown it to be clean.
The contaminated soil was found near an underground concrete sump associ-ated with drains from radioactive systems.
This sump became the sus-pected source of the radioactive material.
It is located outside of plant buildings. A single pipe carries drains from the machine shop and the chemistry laboratory located in the Service Building to the sump.
A second line drains the sump to the Aerated Waste Drain System located in the Primary Auxiliary Building (PAB).
The licensee made a survey in which soil samples were taken along the length of the trench at one-foot increments north and south of the drain line from the Service Building.
The results were mapped on a grid.
Analysis showed that the contamination, composed solely of long-lived isotopes, had the highest activity in soil at the top and bottom of the box-shaped concrete sump.
The pattern indicated that the soil had been contaminated due to an overflow of the sump or due to a leak between the drain pipe and the concrete sump.
The latter condition was discounted because present waste handled by the chemistry laboratory includes short-lived isotopes, including Iodine 131; this waste has a 0.70 ratio of Cesium 134 to Cesium 137 activity.
The licensee also hydrostatically tested the sump and its seal to the pipes by plugging the drain line and filling the enclosure with water.
The Cesium-134 to Cesium-137 isotope ratios of the contaminated soil samples averaged 0.11, indicating an age of approximately five (5) years.
Plant records documented an overflow of this sump on April 18, 1983 due to a plugged drain line.
Liquid samples of that spill had an activity of 1.0E-04 microcuries per milliliter (pC1/ml).
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The licensee excavated around the three remaining sides of the sump.
The soil was analyzed to provide results of a one-foot horizontal and vertical grid. Again, the highest activity was found in soil along the sides of the sump; and the radioactive material had not migrated more than about six (6) feet from the sump.
The findings the licensee's corporate Radiological Assessment B"anch recommended were that soil with an activity greater than 1.0E-03 micro-curies per gram (uC1/g) be removed.
This was based on a calcalated ex-posure from a worst case estimate from one thousand cubic feet of soil with an activity of 1.0E-03 pCi/g (0.037 Ci).
Based on this recommendation, the licensee decided to ramove all soil contaminated to greater than or equal to 1.0E-04 pCi/g. As the work progressed, one exception was made.
Soil under tne concrete sump was found contaminated up to 4.0E-04 pC1/g.
Since at was within the envelope value of 1.0E-03 uC1/g, it was decided that it would remain.
Clean fill vas used exclusively. Contaminated scil which was placed in containers for storage and to allow disposal as solid radioactive waste.
The Station Chemistry Department performs a monthly surveillance in which water pumpej from the external containment sump is analyzed for radio-active material.
That water is essentially ground water from below the reactor containment and the surrounding area, which includes the location of the concrete sump. Additionally, Yard Orain No. 5, which is closest to the sump and next to the Auxiliary Feedwater pump Building, is sampled weekly for radioactive material.
Surveillance records for the past year indicate no detectable activity at either locat-lon.
The licensee evaluated the dr. sign of this drain and its underground sump and concluded that, although it was not an ideal design, no other work such as removal, sealing o: encapsulation was necessary.
Likewise, ad-ditional preventive maintenance such as periodic drain pipe cleaning was determined not to be desirabla, partly due to concern for minimizing personnel radiation exposure.
The 1983 incident resulted when the down-stream pipe clogged *;ith debris from a concrete solidification process for liquid radioac'.ive waste.
That process has been discontinued.
A pipe clean-out connection, installed in 1983, is available if needed.
However, the work would have to be performed in a radiation field as the clean-out is located in the PAB pipe trench.
At the request of the NRC Resident Inspector, the licensee conducted an engineering survey to determine if underground sumps for radioactive drains were used elsewhere.
Preliminary results indicate that, at the Haddam Neck Plant, the sump referred to in this report section is unique to this one specific location.
The inspectors will continue to follow the licensee's actions in this area.
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The NRC Inspector's review of this incident was supported by plant records including those addressing the drain flooding on April 18, 1983.
Additional records reviewed included gamma spectral analysis for isotopic identification memoranda and Plant Incident Reports88-181 and 83-42.
There were no unacceptable conditions identified; however, this issue may be addressed during future NRC Inspections.
6.4 Power Reduction After Traveling Water Screen Failure (71707)
On October 26, with the plant operating at 100% power, a shear pin on the "D" traveling water screen brnke, necessitating a load reduction to about 55% power.
Earl:er in the day, divers had been cleaning the trash racks in the "D" screen house bay. Also, operators had noted abnormally high running amps and discharge pressure on the "0" Condenser Circulating Water (*W) pump, This was attributed to clogging of the condenser tubes with foreign mat-ter (leaves and dirt) from the river (typical during this time of year and aggravated by the divers).
The "D" condenser hotwell had been back-washed twice during the shift in an attempt to clear the condenser.
These evolutions were unsuccessful.
Operations personnel elected
+.o discontinue the diving activities and continued to monitor the
"0" CW pump.
At approximately 3:10 p.m.,
a shear pin on the "0" traveling water screen broke and the screen janmed.
Shortly thereafter, the "0" CW pump began to cavitate. Operators began a power reduction at about 2% per minute.
The plant reached 55% power at about 3:55 p.m.
During the power reduction, the Rod Dosition Indication (RPI) System indicated that control rod banks A, C, and D were below the control rod insertion limit of 320 steps.
This indication problem with RPI is dis-
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cussed in NRC Inspection Report 50-213/88-11 and in detail 7.2 of this
report.
The traveling water screen was repaired and the plant was returned to full power at 1:35 a.m. on October 26.
l The inspector observed control room activities prior to and during the transient. Operators communicated well and were cognizant of and re-sponsive to changing plant paramoters. Appropriate procedures were used as required.
TS limits were met. Also, although oncoming shift person-nel had already arrived, the control room noise level and occupancy were positively controlled to prevent interference with operations.
7.
Review of Periodic and Special Reports (71707)
Upon receipt, periodic and special reports submitted pursuant to Technical l
Specification 6.9 were reviewed.
This review verified that the reported in-l formation was valid and included the NRC required data.
Test results and supporting information were consistent with design predictions and performance
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specifications and planned corrective actions were adequate for resolution of the problem.
ine inspector also ascertained whether any reported informa-tion should be classified as an abnormal occurrence.
The following periodic reports were reviewed:
Monthly Operating Report 88-09, Covering the Period September 1, 1988
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through September 30, 1988 Monthly Operating Report 88-10, Covering the Period October 1,1988
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through October 31, 1988 No unacceptable conditions were identi/ied.
8.
Annual Emergency Preparedness Exercise (82301)
The licensee conducted the annual Emergency Preparedness Exercise on October 15. The State of Connecticut and local towns participated.
The drill was observed by teams from the Federal Emergency Management Agency and NRC Region I.
Exercise observations and results are documented in NRC Inspection Report 50-213/88-20.
The inspectors noted that the licensee was making use of a personal computer programmed with specific thermal hydraulic analysis for the Haddam Neck plant.
The system appeared to provide a powerful calculation tool for use in the Corporate Emergency Operations Center.
The use of the device provided fast and accurate results for iterative calculations which, when performed manually, may be subject to error.
These types of programs free the Technical Support personnel from tedious mathematical tasks allowing them to apply their engi-neering expertise to solving reactor safety problems.
The licensee's develop-ment of this capability was evaluated as a noteworthy positive contributor to licensee performance in developing Emergency Response capabilities.
9.
Report of a Substantial Safety Hazard Involving RCS Vent Valves (71707)
On September 27, 1988, the licensee issued a Substantial Safety Hazard Report in accordance with 10 CFR Part 21.
The report details the identification of corrosion and solder flux on the electrical connectors of the Reactor Coolant System (RCS) vent valves.
The valves are one-inch, two-way direct lift solenoid-operated valves manufactured by Valcor Engineering Corporation.
Mounted on these valves is an tiectrical connector supplied by Litton Pre-cision Products International.
During the refueling outage, the licensee identified corrosion on the valve electrical connectors af ter several of the valves failed post maintenance
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testing.
The corrosion and solder flux apparently caused a short circuit between adjacent connector pins, resulting in dual valve position iriication and potential disabling of the valve.
This type of failure would not be
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identified at Haddam Neck until the valves are used because, during power operation, the valves are normally deenergized and isolated by open circuit breakers.
The licensee classified this as reportable under 10 CFR Part 21 because this type of failure could be postulated at plants where these valves are normally energized.
Failure could result in spurious operation of the valves and a potential loss of reactor coolant inventory.
There are eight of these valves at Haddam Neck: two in series in each of two redundant flow paths for both the pressurizer and the reactor vessel head.
No credit is taken for operation of these valves in the Accident Analysis.
They are functionally tested during each refueling outage.
Before return to power operations after the outage, the corrosion and solder flux were removed and the valvis were successfully tested.
The licensee con-cluded that the valves were operable for both accident and normal operating conditions.
Station proceduret were revised to require visual inspection of
these valves during each refueling outage.
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Currently, the licensee is continuing to evaluate this phenomenon with respect to the cause of the corrosion and the possible effects on valve qualification.
This evaluation is expected to be completed by January, 1989.
No unacceptable conditions were identified; further NRC review may be under-taken.
10.
Containment Integrated leak Rate Test Results Review (70173)
The inspector reviewed the licensee's September, 1987 Containment Integrated Leak Rate Test (CILRT) results documented in accordance with 10 CFR 50 Appen-dix J.
These results were summarized in a technical document entitled "Reac-tor Containment Building Integrated Leak Rate Test and Air Filtration System Test Report," transmitted by liconsee letter dated June 1, 1933.
The report l
contains a test description and includes an edited test log of events, soft-ware description, data analysis techniques, and presentation of results in-cluding Type "B" and "C" test results.
Both the total time and mass point calculation methods were used to calculate cantainment leak rat ss f rom test data.
The purpose of the test was to demon-strate that leakages through the primary containment structure and systems penetrating containment do not exceed that allowed by Technical Specifications.
The test was performed at peak accident pressure for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
It was con-ducted with containment isolation valves and pressure boundaries in the as-left condition.
The computed leak rate, when adjusted using techniques speci-fied in Information Notice 85-71 to reflect Local Leak Rate Test (LLRT) re-work / retest results, indicated a test failure for the containment in the as-found condition.
The as-lef t results satisfied the test acceptance criteria.
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The test was witnessed by the Resident Inspectors and a Senior Reactor Engi-neer from Region I as documented in NRC Inspection Report 56-213/87-25.
Re-sults are presented below:
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RESULTS l
Type A Containment Leakage Rate Test Results Description Total Time Method Mass Point Method (wt'./ day)
(wt'./ day)
(a) LSF Lam ( )
0.0793 0.0777 (b)
95*. UC L L,( 2 )
0.0820 0.0789 (c) Leakage Savings (3)
0.4868 (plus one undeter-0.4868 (plus one mined leakage path)
undetermined leakage path)
(d) As-Found Leakage 0.0650 0.0650 l
Penalties (*)
(e) As-Left Leakage 0.0017 0.0017 (f) As-Found CILRT 0.6338 (plus one undeter-0.6307 (plus one (sum of b+c+d)
mined leakage path)
undetermined leakage path)
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l (g) As-Left CILRT 0.0837 0.0806 (sum of b+e)
(h) Acceptable 0.135 0.135 l
Notes:
(8) LSF L,, - Least Square Fit Type A Measured Containment Leakage Rate, weight percent (wt'4) per day.
(2) UCL L,, - 95'4 Upper Confidence Limit Type A Measured Containment Leakage Rate, wt's per day.
l (3) Leakage Savings - Sum of the difference between penetrations "as-found" and "as-lef t" minimum pathway leakage in wt's per day.
(Applies to re-l paired or retested penetrations.)
(') Leakage Penalties - Sum of the leakages from those penetrations isolated i
during the test, valves not in proper post-accident positions, and pene-trations (due to design) unable to be vented or drained, in wt's per day.
Based on the results presented, the inspector concluded the containment met the test acceptance criteria for leakage in the as-lef t condition. However, this containment did not meet the acceptance criteria in the as-found condi-I tion. The as-found containment leak rate in April, 1956 also did not meet the test acceptance criteria.
This constitutes consecutive failures for the Haddam Neck Containment.
The licensee, per 10 CFR 50 Appendix J paragraph I
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III.A.6, is now required to perform a Type A test at each plant shutdown for refueling or rpproximately every 18 months, whichever occurs first, until two consecutive 'spe A tests meet the acceptance criteria.
Relief from this accelerated testing schedule may be granted to the licensee
if a formal relief request is submitted by the licensee to the NRC outlining an improved maintenance and corrective action program for containment pene-tration boundaries.
If the request is approved, the licensee may implement
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the corrective action and an alternative leak test program in lieu of the re-quired increase in Type A test frequency.
This NRC position is outlined in Information Notice 85-71, Containment Integrated Leak Rate Tests.
11.
Exit Interview (30703)
During this inspection, meetings were held with plant management to discuss the findings.
No proprietary information related to this inspection was identified.
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