IR 05000269/1990027
| ML15224A725 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 10/25/1990 |
| From: | Binoy Desai, Poertner W, Shymlock M, Skinner P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15224A724 | List: |
| References | |
| 50-269-90-27, 50-270-90-27, 50-287-90-27, 72-0004-90-27, 72-4-90-27, GL-88-17, NUDOCS 9011090252 | |
| Download: ML15224A725 (8) | |
Text
A REGU UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET ATLANTA, GEORGIA 30323 Report Nos:
50-269/90-27, 50-270/90-27, 50-287/90-27, 72-4/90-27 Licensee: Duke Power Company 422 South Church Street Charlotte, N.C. 28242 Docket Nos.:
50-269, 50-270, 50-287, 72-4 License No DPR-38, DPR-47, DPR-55, SNM-2503 Facility Name:
Oconee Nuclear Station Inspection Conducte -
t
- S ptember 29, 1990 Inspectors:
/ /,
qef2 r,
-Resid nt Inspector Date Signed p B. B. esi Sid pe r
0at ige W. K. Poertner, Resident r
ae Signe Approved by:
'
M. B. Shymlock, Secti Chi Date Sig ed Division of Reactor Projec SUMMARY Scope:
This routine, announced inspection involved inspection on-site in the areas of operations, surveillance testing, maintenance activities, and inspection of open item Results: During this report period the inspectors performed in-depth reviews of the Unit 2 cooldown and draindow The inspectors concluded that the overall control of the draindown evolution exhibited several weaknesse These weaknesses are discussed in detail in paragraph ;()1 1090252 901025 PER ADOC:K 0500029 FE'C
REPORT DETAILS 1. Persons Contacted Licensee Employees
- B. Barron, Station Manager D. Couch, Keowee Hydrostation Manager
- T. Curtis, Compliance Manager
- J. Davis, Technical Services Superintendent D. Deatherage, Operations Support Manager B. Dolan, Design Engineering Manager, Oconee Site Office
- W. Foster, Maintenance Superintendent T. Glenn, Engineering Supervisor D. Hubbard, Performance Engineer
- E. LeGette, Compliance Engineer C. Little, Instrument and Electrical Manager H. Lowery, Chairman, Oconee Safety Review Group B. Millsap, Maintenance Engineer D. Powell, Station Services Superintendent G. Rothenberger, Integrated Scheduling Superintendent
- R. Sweigart, Operations Superintendent Other licensee employees contacted included technicians, operators, mechanics, security force members, and staff engineer NRC Resident Inspectors:
- Skinner
- W. Poertner
- B. Desai
- Attended exit intervie. Plant Operations (71707)
a. The inspectors reviewed plant operations throughout the reporting period to verify conformance with regulatory requirements, Technical Specifications (TS),
and administrative control Control room logs, shift turnover records, temporary modification log and equipment removal and restoration records were reviewed routinel Discussions were conducted with plant operations, maintenance, chemistry, health physics, instrument & electrical (I&E),
and performance personne Activities within the control rooms were monitored on an almost daily basi Inspections were conducted on day and on night shifts, during weekdays and on weekend Some inspections were made during shift change in order to evaluate shift turnover performanc Actions
observed were conducted as required by the Licensee's Administrative Procedure The complement of licensed personnel on each shift inspected met or exceeded the requirements of T Operators were responsive to plant annunciator alarms and were cognizant of plant condition Plant tours were taken throughout the reporting period on a routine basis. The areas toured included the following:
Turbine Building Auxiliary Building CCW Intake Structure Independent Spent Fuel Storage Facility Units 1, 2 and 3 Electrical Equipment Rooms Units 1, 2 and 3 Cable Spreading Rooms Units 1, 2 and 3 Penetration Rooms Units 1, 2 and 3 Spent Fuel Pool Rooms Unit 2 Containment Station Yard Zone within the Protected Area Standby Shutdown Facility Keowee Hydro Station During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control practices were observe Unit 1 operated at 100 percent until September 10, 1990, when a loss of the transformer cooling fans and pumps occurred (see paragraph 2.b).
The Unit returned to 100 percent power on September 11 and remained at that power level until September 17 when a runback occurred due to the loss of out limit indication on rod group 4. The licensee identified a fault in the indication for rod 8 in that group. All group 4 rods were balanced and the group withdrawn to return to 100 percent powe The Unit continued operation at that power level for the remainder of this report perio Unit 2 operated at 100 percent power until September 12 when the Unit was taken off the line to begin end of cycle 11 refueling outag Unit 3 has operated at 100 percent power level for the duration of this reporting perio b. Reduction in Power Due to Loss of Unit 1 Transformer Cooling Fans/Pumps On September 10, 1990, at 10:58 p.m. the operators received a
"Transformer #1 Loss of Control Power -
One Cooler Bank" stat alar Investigation determined that no transformer fans or pumps were operating and that circuit breaker 8-19 on power panel 1XC had trippe At 11:32 p.m., oil was observed to be overflowing from the transformer due to thermal expansion and a reactor shutdown at 10 percent per minute was commence At 11:42 p.m.,
power had been
reduced to 20 percent and the turbine was tripped off the lin Reactor power was reduced to 13 percent at 11:45.p.m. and remained at this power until repairs were completed. The licensee determined that the breaker had tripped due to a malfunction of a relay mounted on the door of the breaker compartmen The relay and the breaker were replaced and the cooling fans and pumps were returned to operatio Power increase was commenced at 5:30 a.m., on September 11, 1990. The generator was placed on the grid at 9:16 and the unit achieved 100 percent power at 10:31 p.m. later that da c. Unit 1 Core Flood Tank B Level Instrument Problems On September 7, 1990 at 2:55 p.m.,
the licensee determined that the channel 1 level instrument for "B" core flood tank indicated less that the TS value of 12.56 fee The level instrument indicated 12.499 feet as read on the computer indication. TS 3.3.3 requires the level be maintained at 13.0 + or -0.44 fee The indicated level dropped below the TS required value after the instrument was calibrated by I&E personne Prior to calibration the instrument was reading approximately 13 fee At this time the channel 2 instrument indicated 13.4 fee The licensee declared the core flood tank level indication out of service and entered TS 3.0. This requires the unit to be placed in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless corrective measures are completed that permit operation under the permissible action statemen The licensee calibrated the channel 2 level instrument and determined that the instrument was within the required toleranc The licensee took further action to perform a backfill of the reference leg which reduced the level to 12.9 feet on this channe The level in the core flood tank was increased to greater than 12.56 feet and the licensee exited TS 3.0 at 6:12 on September 7, 199 The licensee back filled the channel 2 instrument several additional times to reduce the difference between the two level instrument A LER associated with the B core flood tank level indicators is being developed to address in detail this occurrenc d. Unit 2 Reactor Vessel Drain Down Procedural Weaknesses The inspectors reviewed in detail and witnessed portions of the performance of Operating Procedure (OP)
2/A/1103/11, Draining and Nitrogen Purging of the RC System which commenced on September 18, 199 This procedure establishes the conditions for mid-loop operation Enclosure 3.3, Draining the Reactor Vessel, Pressurizer, and Cold Legs, of the procedure provides the procedural guidance to drain the vessel below 28 inches as indicated on the reactor vessel level indication (LT-5).
The inspectors observed the following during this period:
- During the draindown, problems were observed with vessel level changes that appeared to indicate the vessel was not adequately vente Step 2.5 of Enclosure 3.3 required that pressure be equalized between the reactor vessel head, hot legs, and pressurize via the Quench tank by venting the center Control Rod Drive Mechanism (CRD)
and CRD-31 at 184
+ or
-
inches indicated pressurizer leve Only one vent path had been established and the other had been signed off in the procedure as
"Not Applicable" (N/A).
Declaring a step in a procedure as N/A is authorized by Operations Manual Procedure (OMP)
1-9, Use of Procedures and Station Directive (SD) 2.2.1, Station Procedure Discussion with the Senior Reactor Operator (SRO) identified that the step had been N/A'd because only one vent rig was available inside containmen The SRO stated that only one vent path from the vessel head was require Discussions with operations support personnel determined that the procedure had been recently revised to include the additional vent path due to problems identified during the previous Unit 1 refueling outag Problem Identification Report 1-090-0043 identified problems in inadequate venting of the RCS during that outage and the corrective action taken was to add the additional vent path to the procedure for Unit 2. The inspectors consider that revising a procedure to add requirements to correct a previous deficiency and then deleting this requirement by use of the N/A process is a poor work practic LT-5 was signed off as being in service by I & E when pressurizer level indicated approximately 88 inche LT-5 is normally isolated and is placed in service during vessel draining below 100 inche LT-5 indicated approximately 84 inches when placed in service and the draindown of the vessel continue However, LT-5 did not respond as pressurizer level decreased. Operations secured the draining operations at approximately 72 inches on the pressurizer level indicator although LT-5 still indicated 84 inches and did not track the level reductio The procedure states that once pressurizer level decreases to approximately 72 inches it is no longer an accurate level indication since the RCS is drained below the instrument ta Subsequent investigations by the licensee determined that the instrument root valves, which are in the same location as the instrument, were not opened. The initial sign-off was based on the completion of the calibration of LT-5 by IP/O/B/200/27A, Reactor Level Instrumentation and Calibratio Review of this procedure determined that the root valves are not controlled by this procedure and that this procedure does not place the instrument in service. LT-5 was not required to be placed in service until pressurizer level was approximately 72 inche The inspectors consider that the lack of procedural guidance for ensuring LT-5 is properly placed in
operation is a weakness in the draindown procedur The inspectors consider that LT-5 not being required until the pressurizer level instrumentation is at a questionable area of indication to be another procedure weaknes An ultrasonic level indicator is normally installed on the hot legs as a second means of level indication when the decay heat removal system is operated at mid-loo This instrumentation provides indication over a narrow range of operatio The licensee decided to drain down below 50 inches without this instrumentation being operabl When questioned concerning this decision the inspector was told that the instrument was not required to be installed and that the response to Generic Letter (GL) 88-17 concerning mid-loop operation did not commit to the installation of these instrument A review of this response confirmed that the level instruments were not identified as a commitmen The licensee only committed to evaluate independent level indication During the previous two outages (Units 1 and 3) the instruments were functional during this evolutio The decision to continue the draindown without this instrumentation resulted in LT-5 being the only instrument operable during this evolutio Two makeup flow paths are required to be available per OP/2/1103/11, prior to draining below 50 inches on LT-The flowpaths taken credit for were the path from the Borated Water Storage Tank (BWST) to the suction of the Low Pressure Injection (LPI)
pumps and a path using the Bleed Transfer Pumps (BTP).
Enclosure 3.4, Level Control, of this OP requires that the makeup water boron concentration not reduce RCS boron concentration below 2200 ppm if LPI is in the purification mode of operation and vessel level is less than 80 inche The Enclosure assumes that the source of water is from the Bleed Holdup Tanks (BHUT).
The BHUTs did not contain greater than 2200 ppm boron concentration prior to decreasing below
inche The inspectors questioned whether this met the requirement of two flow paths and was told that the Concentrated Boric Acid Storage Tank (CBAST) could be aligned to the system if a source of makeup water greater than 2200 ppm was require The CBAST could have been aligned to the system but a review of the licensees'
procedure indicated that there was minimal procedural guidance established that would have accomplished this evolutio The inspectors concluded based on the observations identified above, that the procedural guidance established for the control of LT-5 is weak and that the overall controls exhibited during this draindown evolution were also wea The inspectors also consider that the decision to drain the reactor vessel without a second level indicator to be a non-conservative management decision that resulted in circumventing the intent of NRC GL 88-1 II
Unit 2 wiring inspection summary, evaluation and corrective action for each item identified. Each deficiency was evaluated and either a work request or a drawing change was issued to correct the deficiency. No operability concerns were identified during the review. Based on the above review, this item is close b. (Closed)
LER 269/89-08: Declared Cable Room and Equipment Rooms Fire Suppression Sprinkler Systems Inoperable Due to a Design Deficiency, Deficient Communication This LER was submitted in correspondence dated June 21, 198 On May 23, 1989, the Design Engineering (DE)
group identified that the sprinkler systems for the cable spread and equipment rooms of each unit were not adequately designed to operate in accordance with the existing operational guidance of the High Pressure Service Water System (HPSW).
The sprinkler system was designed to provide adequate fire protection assuming a system pressure equivalent to that provided by a HPSW pump in operatio Since the pumps are normally in a standby status and start on a reduction in the system pressure, design flows can not be obtained until the pump is started. Fire protection procedures for these areas were revised to start a HPSW pump if the sprinkler system is needed for fire purposes. The FSAR will be revised to address this method of operation in the next revision. Based on the corrective actions taken and review by the inspector, this item is close (Open) LER 269/89-15: Inoperable Containment Isolation Valves Following Failure to Test After Maintenance/Modification Resulting From Inappropriate Action and Management Deficienc This LER was submitted in correspondence dated October 23, 198 The licensee identified that a specific containment penetration had not been tested as required by 10 CFR 50, Appendix J, Type A Leak Rate Tests, on all three units since September 21, 198 Further investigation identified that on Units 1 and 2, two penetrations had not been properly tested since modifications had been completed in 198 The corrective actions identified in this report have been reviewed by the inspecto All corrective actions except for a detailed program review have been completed. This program review is an in-depth review that may result in TS revision It is presently scheduled to be complete by the end of cycle 12 on Unit 3 which is presently in August 199 This item will remain open pending the review of this actio d. (Closed)
LER 269/89-16:
Design Oversight Results in Potential for Unanalyzed Breach of Containment Isolation During a Simultaneous LOCA/Seismic Even This LER was submitted in correspondence dated November 16, 1989 and supplemented on December 15, 198 On October 17, 1989, DE identified that during a simultaneous LOCA/seismic event an unanalyzed breech of containment could resul The licensee determined that this condition had existed since 1982, following the modification that installed the Reactor Building Auxiliary Cooling fans. Modifications have been completed on Units 1 and 3 and will be completed on Unit 2 during this outage, Based on this action, this item is close e. (Closed)
LER 269/90-01: Failure to Implement Technical Specification Change Due to Management Deficiency, Inadequate Policy/Directiv This LER was submitted in correspondence dated January 26, 199 This event occurred as a result of a TS change that was initially intended for implementation on Unit 3 which was in an outage. This change was to modify the Reactor Protection System (RPS)
circuitry to provide a limitation to preclude operation with only two Reactor Coolant Pump However, the TS was submitted and issued with provisions to change all three unit As a result, Unit 3 circuitry was properly aligned, but the circuitry for Units 1 and 2 were not. This was identified after startup of Unit 3 which resulted in a violation of this TS for Units 1 and Corrective action for this event was to generate Station Directive 4.5.6, Technical Specification Amendment Processing, dated August 1, 199 The inspectors have reviewed this corrective action and based on this review, this item is close (Closed)
LER 269/90-06:
Management Deficiency/Inadequate Review of Technical Specification Change Led to Unit 1 Unanticipated Reactor Protection System Tri This LER was submitted in correspondence dated May 24, 199 On April 26, 1990, Unit 1 was in the process of a cooldown to commence a refueling outag All control rods were inserted except group 1 which was 50 percent withdrawn per procedure During the previous operating period a reactor trip signal had been implemented which would cause a trip if only two reactor coolant pumps were running and reactor power level was greater than 0 percent. Upon shifting to a two pump combination a slight positive signal (less that 2 percent) was present on the power level instrument and resulted in a RPS actuation. All corrective actions for this event has been taken and a review conducted by the inspector A proposed TS change has been submitted by the licensee that will allow a slight tolerance in the setpoint to eliminate the effect of noise on a power range channe Based on this action, this item is close g. (Closed) LER 270/89-05: Unit 2 Reactor Coolant Sample Isolation Valves Failed to Meet Environmental Qualification Requirements Due to Inappropriate Actions With a Contributing Cause of Management Deficienc This was a voluntary LER submitted to the NRC in correspondence dated July 19, 198 The corrective actions addressed in this report has been reviewed by the inspector and based on this action, this item is close h. (Closed) LER 270/89-08:
Low Temperature Overpressure Protection Commitments to NRC were Violated Due to Management Deficiency, Inadequate Polic This event was submitted as a voluntary LER in correspondence dated January 15, 199 The corrective actions for this item have been reviewed by the inspecto A TS change has been submitted to the NR Based on this action, this item is close