IR 05000220/1989004
| ML17055E681 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 04/24/1989 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17055E679 | List: |
| References | |
| 50-220-89-04, 50-220-89-4, 50-410-89-04, 50-410-89-4, IEB-79-02, IEB-79-14, IEB-79-2, IEB-88-007, IEB-88-7, NUDOCS 8905030531 | |
| Download: ML17055E681 (42) | |
Text
.S.
NUCLEAR P~GULATORY COMMIS
REGION I
I e
Report No.
89-04/89-04 Docket No.
50-220/50-410 License No.
Licensee:
DPR-63/NPF-69 Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, New York 13212 Faci 1 ity Location:
Dates:
Inspectors:
Nine Mile Point, Units 1 and
Scriba, New York February 18, 1989 thru April 3, 1989
'W. Cook, Senior Resident Inspector R.
Temps, Resident Inspector R.
Laura, Resident Inspector M. Banerjee, Project Engineer, DRP R. Barkley, Reactor Engineer, DRP M. Dev, Reactor Engineer, DRS OPS Approved by:
MA J.
Johnso Chief, Reactor Projects Section 2C, DRP
~v/~v Date INSPECTION SUMMARY Areas Ins ected:
Routine inspection by the resident inspectors of station activities including Unit 1 and 2 shutdown operations, a Unit 2 reactor startup, licensee action on previously identified items, plant tours, safety system walkdowns, surveillance testing reviews, maintenance reviews, NRC Bulletin and Information Notice reviews, and LER reviews.
This inspection period involved 360 hours0.00417 days <br />0.1 hours <br />5.952381e-4 weeks <br />1.3698e-4 months <br /> of direct inspection effort of which 81 hours9.375e-4 days <br />0.0225 hours <br />1.339286e-4 weeks <br />3.08205e-5 months <br /> were regular backshift and 39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br /> were deep-backshift inspection conducted on February 19, 20, 25, 26, and March 11 and 25.
Results:
A violation of Unit 1 Technical Specifications regarding the use of procedures is discussed in Section 4. 1.
One violation of Unit 2 Technical Specification regarding three different examples of failure to use or follow procedures is discussed in Sections 1.2.a, 1.2.b and 1.2.c.
A Unit 2 licensee identified non-cited violation (NCV) concerning a design error in the Service Water System cross connect valve actuation logic is discussed in Section 1.2.d.
Six Unit 2 licensee identified NCVs from previous inspection periods are discussed in Section 6.2.
A review of licensee actions regarding NRC Bulletin 88-07, Supplement
(BWR Power Oscillations)
for both Units is discussed in Section 7.
A concern regarding Unit 1 Core and Containment Spray systems'trainer supports is discussed in Section 3. DETAILS 1.
Review of Plant Events (71707, 71710, 93702, 90712, 40500)
1. 1 UNIT On March 13, 1989, a meeting was held at the Region 1 Office between members of the NRC Unit 1 Restart Panel and senior management officials of Niagara Mohawk.
The topic of discussion was the licensee's Restart Action Plan (RAP) for Unit 1 and the impact on the plan as a result of the recent NRC Special Team Inspection findings.
Meeting minutes were issued under a separate cover.
At approximately 3:50 p.m on March 8, the Unit 1 operators received a transformer cooling trouble alarm on the 101N Reserve Transformer (one of two 115KV/4. 16KV transformers being fed by the independent offsite power sources).
The operators took prompt action to isolate the transformer before damage occurred.
In so doing, the 102 Emergency Power Board was deenergized because the associated 102 emergency diesel generator was out of service.
Consequently, an automatic initiation of reactor building Emergency Ventilation (EV) occurred due to the electrical power loss of an associated power board (No.
16B).
Power board (PB)
16B or 17B (powered from PB 103) supplies power to PB 167 which in turn supplies power to Instrumentation and Controls ( I&C) bus 130.
One of the circuits supplied by the I&C bus is the refuel bridge high range area radiation monitor.
This monitor is in use due to plant conditions and is designed such that on a loss of power it will cause an EV initiation.
On the loss of PB 102, PB 16B also deenergized.
On loss of power to PB 16B, PB 167 is designed to switch over to PB 17B.
This switching did take place; however, the momentary (one second)
interruption in power to PB 167 and ultimately I&C bus 130, resulted in the EV initiation.
Additionally, when the operators restored transformer 101N to service on March 11, the EV system initiated again.
The resident inspectors determined that the operators were not aware of the "break before make" switching feature of PB 167 as it was restored to its normal PB 16B power supply.
A Training Modification Request 01-89-35 was generated to review electrical interlock's associated with the reserve transformer switching and power board breakers.
Additionally, the licensee will generate a "lessons learned" transmittal to summarize and review operator actions during both the March 8 and March 11 event Post-maintenance testing was performed on the subject detector per Procedure N2-ISP-ISC-R117, Attachment 1.
Prior to the close-out of.the surveillance procedure, the I&G technician performed a backfill of the detector per a hand written note attached to the front of the procedure.
The technician failed to use an established procedure to backfill the detector which contained precautionary measures to preclude spurious system actuations during detector backfilling operations.
Supervisory personnel were aware of the procedure and intended for the detector to be, backfi lied using the correct work instructions.
The technician's performance of this safety-related maintenance, which is considered to be outside the "skills of the trade",
without a written procedure, is a 'violation of Technical Specification 6.8.1.
VIOLATION (50-410/89-04-01)
.
On February 21, the unit experienced a Secondary Containment Isolation, an initiation of Division I Standby Gas Treatment (SBGT) system and an initiation of the reactor building, Ventilation Emergency Recirculation System (HVR) ~
These actuations occurred while operators were restoring from a SBGT operability test.
Procedure N2-OP-52 was used to restore the HVR to the normal line-up.
This procedure did not specify where test equipment was to be grounded, and the operator made an incorrect assumption rather than obtaining a procedure change for clarification.
The operator made sever'al attempts to obtain the desired voltage readings, resulting in the above noted Engineered Safeguard Feature actuations.
The operator's failure to obtain a procedure change to correct this deficiency is a violation of Technical Specification 6.8.1.
VIOLATION (50-410/89-04-01).
On February 28, an inadvertent initiation of the B Low Pressure Core Injection ( LPCI) pump resulted in rai sing reactor water level from 183 inches to 222 inches.
Surveillance testing on the LPCI pumps was in progress per test procedure N2-ESP-ENS-M?31.
Electrical maintenance personnel conducting the test requested the CSO to perform step 7.2. 1.2, which is a line-up of two power available test switches.
Due to inattention to detail, the operator and the maintenance person responsible for independently verifying the operation only lined-up the position of one switch vice the two required.
This error resulted in the inadvertent actuation of the LPCI system.
This failure to follow procedure is a violation of Technical Specification 6.8. 1.
VIOLATION ( 50-410/89-04-01)
.
For additional licensee actions to improve performance in the area of procedural compliance see section 2.9 below, On February 21, the licensee determined that the Service Water System (SWS) actuation logic for valves 2SWP*MOV50A and B
(divisional cross-connect Valves)
and valves SWP*47A&B and SWP54A&B did not meet single failure criteria as specified by 10 CFR 50, Appendix A, Criterion 34 and FSAR Sections 3. 1 and This error was the result of a design error made by the licensee's Architect/Engineer.
This error would prevent closure of either cross-connect valve during a full loss of offsite power coupled with a failure of either standby emergency diesel generator to restore power to its respective division.
The licensee implemented a design modification to the SWS which corrected the single failure deficiencies.
The inspector reviewed the Safety Evaluation Report issued by the licensee and identified no concerns.
This modification was deemed not to be an Unreviewed Safety Question per
CFR 50.59.
The inspector verified that the applicable Operating Procedures were changed to incorporate this modification and that required switch changes on the Service Mater Control Room mimic were made.
The inspector reviewed the Pre-Operational Test Procedure (N-2-POT-11-1)
and observed portions of the testing.
In summary, the inspector found that the licensee proceeded cautiously in the evaluation and resolution of this design error.
In accordance with the provisions of the Enforcement Policy guidance of 10 CFR 2, Appendix C, Section V.6.
This violation is not being cited for this licensee identified violation.
(NCV 50-410/89-04-02).
2.
Followu on Previousl Identified Items (92700, 93702, 92702)
Procedure Com liance As a result of Special Team Inspection 50-410
& 50-220/89-200 and recent poor performance in the area of procedural compliance, the licensee committed to revise current guidance and conduct training of station personnel in this area.
The NRC staff was concerned because of the apparent inability of the licensee to reduce the frequent instances of procedural noncompliance and that there was no consistent guidance in this area.
This was exemplified by the numerous and different interpretations of procedural compliance observed among station personnel.
Niagara Mohawk's commitments were documented in a letter issued from the NRC Project Directorate in NRR dated March 15, 1989.
Niagara Mohawk issued Station General Order (SGO) 89-03 on March 17, 1989 which delineated the Nine Mile Point Nuclear Station guidance and policy on procedure content and adherence.
This order also supports the Nuclear Division Management Policy (NDMP-9) on Pro-cedural Compliance'pecific training on SGO 89-03 was administered by line supervisors to plant personnel who use procedures in their jobs on site.
The inspector reviewed SGO 89-03 and the training material.
The guidance provided in the policy was comprehensive.
The inspectors interviewed numerous Niagara Mohawk employees picked at random, from Operations, Maintenance and Health Physics Departments, and questioned them about their understanding of the subject polic On February 16, 1989, the licensee determined that the overpressure relief setpoint on two Electromatic Relief Valves (ERVs) was above the Technical Specification (TS) allowable limit.
Through a review of past surveillance test results, the licensee determined that the surveillance test performed on June 13, 1986 was not completed in accordance with current TS.
TS Amendment No. 86, which became effective on June 12, 1986, incorporated the overpressure relief setpoints into the TS surveillance requirements.
The root cause of this event, as stated in Licensee Event Report (LER) 89-01, was lack of an effective management process to ensure TS amendments are implemented in a timely manner.
To correct this, the licensee has committed to performing an audit of surveillance pro-cedures to identify similar situations, if any, and to institute a
process such that all proposed TS amendments will be reviewed to identify all potentially affected documents prior to the application for amendment being submitted to the NRC.
The inspectors have reviewed licensee corrective actions to date and find them adequate.
Further details of this event are documented in LER 89-01.
In accordance with the provisions of the Enforcement Policy Guidance of 10 CFR 2, Appendix C, Section V.6 the violation is not being cited.
NCV (50-220/89-04-01).
d.
On March 30, 1989, an Enforcement Conference was held at the licensee's training center.
The subject was the result of the last three inspections by Region I examiners of the licensee's Operator Licensing Requalification Program for Unit 1, as well as, an investi-gation by the Office of Investigations into problems identified in the three inspections.
Three issues were specifically addressed:
(1)
requalification program requirements, (2) inaccurate information supplied on a total of thirteen NRC Form 398s, and (3) the breakdown of management oversight of the requalification program.
Results of the Enforcement Conference will be issued in a separate report.
1.2 UNIT 2 The unit remained in cold shutdown the majority of the inspection period unti 1 the reactor was taken critical on April 2.
The unit had been in cold shutdown since October 1,
1988 when it entered a midcycle surveillance and maintenance outage.
The primary delay in the completion of the outage was attributed to several containment isolation valves failing 10CFR50 Appendix J leakage testing and the modification of the Service Water System divisional cross connect valves actuation logic.
a.
On February 19, the unit experienced a High Pressure Core Spray initiation due to maintenance being performed on reactor water level detector 2ISC-L114A without using the proper procedur Their answers in all cases consistently reflected the content of the policy.
The training conducted by the licensee and their subsequent verification of the training effectiveness was documented in a letter from the Executive Vice President to the Director of NRR, dated March 30, 1989.
The licensee's site QA surveillance group performed a procedure compliance survey.
A six question checklist was used to assess understanding of station personnel on this policy.
The Audit plan involved interviewing about 500 personnel between various departments on site from both units.
The results reflected a
consistent understanding among the personnel interviewed.
In a few isolated instances, inconsistency in understanding the procedure
.temporary change notice (TCN) process was observed and some retraining was conducted.
b.
The inspectors observed a number of surveillance test activities.
During the performance of these activities, no noncompliance to procedures or the subject policy was observed.
The inspectors observed. several training sessions and found them to be effective.
During the training sessions the inspectors noted good employee participation.
Subsequent to the training, the inspectors noted numerous procedure changes being processed which indicates that the training was effective.
Station General Orders (SGO) are controlled in accordance with Administration Procedure No
~ AP-2.0, Production and Control of Procedures, under the Section 4. 16,. Operating Orders and Special Orders.
SGOs are considered
"Operating Orders" as defined by ANS 3.2, Administrative Controls and Quality Assurance of the Operational Phase of Nuclear Power Plants, section 5.2.3, which considers these orders as instructions of general and continuing applicability'o the conduct of business.
The inspector reviewed the current Station General Orders and determined that the effective SGOs were adequately controlled, recently updated and consistent with the guidance of ANS 3.2 and AP-2.0.
2.1 Unit 1 (CLOSED)
VIOLATION (50-220/84-15-02):
Licensee failed to document references, sources of input, reviews conducted and engineering assumptions with regard to design calculations used in Bulletin 79-02.
The inspector reviewed the licensee's actions taken in response to this violation as documented by licensee file correspondence SM1-S89-0071, dated February 21, 1989.
As a result of this finding, the licensee reviewed 30 calculations packages.
For the thirty (30) supports involved, documented loads exist or have
been generated for 16 supports; the remaining 14 support.loads could not be generated due to a lack of design basis data.
(The licensee lacks design basis data on many piping systems and supports since the facility was constructed before the issuance of 10 CFR 50 Appendix B which required the retention of such documentation.)
This data will be generated under the Design Basis Reconstitution Program which the licensee is undertaking.
As a result of the licensee's review of the 16 noted supports, calculations revealed that five of the supports were determined to require modification.
The inspector verified that Nonconfbrmance Reports'4-89-0031,
-0034,
-0035, and -0037 were issued to upgrade these supports'he inspector discussed the licensee's Design Basis Reconstitution Project with the responsible project manager.
Review of the program indicated that the project would ensure that the documentation concerns, with regard to IEB 79-02 as addressed in inspection report 84-15, would be addressed by this project.
However, the inspector noted that the program is not scheduled for completion until 1993.
Based on the licensee's actions to date with regard to this item and their actions planned with regard to the Design Basis Reconstitution Project as it impacts their Bulletin 79-02 documentation, the inspector considers the essential elements of this violation to be addressed.
NRC review of the licensee's Design Basis Reconstitution Project results will be conducted in future inspections.
This violation is closed.
(CLOSED)
UNRESOLVED ITEM (50-220/84-15-05):
Licensee should provide information which clearly shows that all factors of safety for the tensile strength of construction expansion anchors as outlined in IEB 79-02 are still satisfied for all cases where pipe support loads may have increased due to IEB 79-14.
The inspector reviewed Sargent and Lundy Project Report No.
8103-27 which documented actions by a licensee contractor to ensure that the calculations in IEB 79-02 were not affected by support load increases calculated in response to IEB 79-14.
The results of their review indicate that only two of the IEB 79-14 walkdown files out of a sample of 74 files reviewed affected load calculations performed for IEB 79-02.
The inspector considers the licensee's approach to this problem adequate and that the licensee's resolution of the above violation will ensure that this concern is addressed.
This item is closed.
(CLOSED)
INSPECTOR FOLLOWUP ITEM (50-220/87-10-01):
Failure to perform surveillance testing within the required interva The licensee's failure to perform surveillance testing within the required TS surveillance interval was documented in Licensee Event Report (LER) 87-04.
At that time, the inspector found that corrective actions to prevent exceeding 3.25 times the required surveillance interval for three successive Technical Specification related survei llances may not be effective in all cases.
The inspector discussed the surveillance scheduling process with the licensee's scheduling department, particularly the administrative mechanism used to ensure that the above TS requirements would be met.
He also spot checked the licensee's scheduling system for scheduling the monthly surveillance test on the drywell pressure instruments required by Technical Specification Table 4.6.2.a (3).
No problems with the program were noted.
The inspector found the licensee's scheduling approach conservative in that their program may result in the performance of 13 monthly surveillances in a one year time frame versus 12 as required in order to avoid exceeding the TS requirements.
This item is closed.
(CLOSED)
UNRESOLVED ITEN (50-220/87-24-02):
Licensee to determine why the following two exceptions from the NRC Generic Safety Evaluation (GSE) for BWR Scram Discharge Volumes (SDVs)
were not obtained with NRC approval:
1) the SDV instrument volume level. instrument taps for the instrument reference legs are located at the top of the SDV piping versus the GSE specified location in the vertical section of the instrument volume; and, 2)
an exception was taken to per.forming periodic reactor scram testing at approximately 50% control rod density for verifying SDV operability.
The licensee determined that the above noted deviations to the GSE were identified and presented to the NRC in a letter on January 30, 1981.
The requirements delineated in the GSE were imposed on the licensee by Order on June 24, 1983.
However, the licensee's deviations from the GSE were not addressed by the Order.
The licensee subsequently failed to obtain approval from the NRC for these deviations from the Order.
By letter dated January 21, 1988, the licensee requested that the staff evaluate the above noted deviations from the GSE.
Subsequently, on March 17, 1988, a meeting was held between the licensee and NRR regarding these deviations.
At that meeting, several concerns regarding the design of the scram discharge volume instrumentation were raised.
Following that meeting, the licensee communicated their resolution of these concerns in correspondence to the NRC dated June 3,
1988 and August 17, 1988.
The NRC subsequently issued a Safety Evaluation Report (SER)
on October 12, 1988 which approved the above deviations, but committed the licensee to submit a Technical Specification
amendment to provide for a periodic test of the SDV to verify the operability of the SDV level instrumentation.
That TS amendment was requested on December 27, 1988 by the licensee and awaits NRC approval.
This issue has been satisfactorily resolved by the licensee.
The inspector considers this issue resolved.
(CLOSED)
UNRESOLVED ITEM (50-220/88-07-01):
Licensee to complete piping/heat exchanger stress analysis on the Reactor Building Closed Loop Cooling heat exchangers.
The licensee replaced the three Reactor Building Closed Loop Cooling (RBCLC) heat exchangers at Unit 1 under Modification No.
85-48 due to material problems with the original heat exchangers.
Due to problems experienced during the installation of anchor bolts for several of the heat exchanger supports, the licensee was forced to make changes to the design of the supports.
As a
result, the stress analysis on the RBCLC heat exchanger and piping had to be reperformed.
The inspector reviewed licensee calculations Sly 4-70-TP05 and S13.4-70-M003 which analyzed the as-built configuration of the RBCLC heat exchanger and nearby piping.
No problems were noted.
He noted that reanalysis 'of the as-built configuration of the system revealed that an additional pipe hanger needed to be installed on one of the RBCLC lines.
The inspector verified that modification change 1-85-048-LS-408 was initiated to install such a support.
This item is closed.
(CLOSED)
UNRESOLVED ITEM (50-220/88-17-03):
Licensee to review their program for determining the required setpoints for overcurrent devices on GE AK type circuit breakers and to review previously performed copies of procedure N1-EMP-GEN-R151 to determine if any corrective action is needed to ensure that the noted breakers were able to function.
As a result of this inspection, the licensee revised procedure Nl-EMP-GEN-R151 to require that if the
"As Found" conditions of the breaker setpoints do not fall within allowable tolerances, the Electrical Maintenance Supervisor will be informed.
This supervisor will then determine what actions are to be taken.
The inspector also raised a concern in Inspection Report 88-17 with the fact that the procedure contained data recording sheets for maximum and minimum pickup for Long, Short and Instantaneous time delay setpoints but were not filled out.
The licensee's response
stated that the information on the setpoint database was not avai l-able from Engineering at the time of the inspection.
As a result, Document Change Request (DCR) Nl-88-001-LG-131 was issued to request that tolerances on the maximum and minimum pickup for Long, Short and Instantaneous time delay setpoints be provided by the licensee's engineering group.
The inspector reviewed DCR Nl-88-001-LG-131 and noted that tolerances for the time delay setpoints were provided.
The inspector reviewed the changes to procedure Nl-EPM-GEN-R151, Rev.
0 as well as completed copies of the procedure for the following breakers:
Feeder to Power Board 161B Emergency Service Water Pump
Emergency Service Water Pump
- Power Board Supply from R1041 No problems were noted.
This item is closed.
2.2 Unit 2
(CLOSED)
INSPECTOR FOLLOW ITEN (50-410/87-22-10):
This item remained open pending further licensee resolution of deficiencies in initial corrective actions.
Deficiencies in initial corrective actions were identified by the NRC and these concerns were documented in Inspection Report 50-410/88-18, Sect. 2.2.b.
Subsequent to the identification of the deficiencies, the licensee initiated efforts to confirm the full extent of the problems noted and to develop comprehensive corrective actions.
As a result of their efforts, changes were made to procedure N2-EMP-GEN-518,
"Temporary Restoration of Power for Post Accident Sampling".
The changes affected the methodology for restoring Division I or II power to the various Post Accident Sampling System (PASS) solenoid valves as well as the number and types of jumpers required to restore power.
After changing N2-ENP-GEN-518, the licensee then verified the ability to obtain various post accident samples via the PASS using the normal post accident sampling procedure N2-CSP-13.
A temporary procedure was written, N2-TP-89-1, Rev. 0, which used N2-CSP-13 to obtain samples from the PASS under normal power conditions, and then to obtain them under abnormal power conditions (i.e. loss of Division I or II power) with the necessary jumpers installed per procedure N2-ENP-.GEN-51 Additionally, the total times for installation of jumpers (when required),
obtaining and transporting samples and sample analysis were recorded for historical purposes and for verification that the three hour sampling time requirements of NUREG 0737, Item II.B.3 were met.
In all cases, the test demonstrated that samples utilizing the PASS can be obtained, and the requirements of NUREG 0737 are met for normal and abnormal power conditions.
This item is closed.
Review of List of Station Controlled Lists The licensee Administrative Procedure AP-8.8 and associated control documents provide lists of primary and secondary containment penetrations and snubbers requiring periodic inspection in accordance with the facility"s Technical Specifications.
The procedure is currently in the review cycle and is intended to be used on an interim basis until a final computerized listing is developed.
Ouring a plant walkdown, the inspector randomly selected the following equipment and components, and verified that they were accurately incorporated in the control documents:
Electrical Penetrations Valves/Blind ~Flan es Snubbers
CES Z22E 2 CES"Z02E 2 CES"Z56E 2 CES*Z59E 2 SFC~V203 2 SLC*V8 2CSL"V29 2 RHS-PSSP 2 RHS-PSSP
RHS-PSSP 2 CSL"PSSP In summary, the inspector found that the licensee's controlled lists were accurate (for the sample selected)
and no concerns were identified.
Backlo of 0 en Occurrence Re orts At the conclusion of the first two weeks of the Headquarters Special Team Inspection (January 30 through February 10, 1989),
the team identified that there were numerous open Occurrence Reports (ORs) for both Units 1 and 2.
At the time of the interim exit on February 10, the significance of these open ORs and their potential impact on the pending restart of Unit 2 was not reviewed.
To assess the significance of these open ORs, the inspectors conducted a more detailed review of these ORs during the week of February 20, 198 The inspectors reviewed the 339 open ORs for Unit 2 which were initiated from as early as February 1986.
The inspectors selected 44 open ORs for the licensee to prepare additional information for more detailed assessment.
The associated documentation and verification of plant impact were assessed by the licensee and then provided to the inspectors for review.
The inspectors concurred with the licensee that the
ORs selected did not impact plant readiness for restart.
Two minor followup items were identified by the licensee during their review of the
ORs selected.
These items were promptly resolved and, in addition, the licensee determined that.a 100 percent review of all open ORs would be conducted prior to Unit 2 restar t to ensure no other items were overlooked.
The inspector concluded that the open Occurrence Reports did not impact restart of Unit 2.
Significant items or occurrences were properly elevated and resolved via generation of additional reporting mechanisms or nonconformance type documents, as appropriate.
The inspectors determined that these numerous open ORs were not closed out for administrative purposes rather than spec~fic hardware or programmatic reasons.
The licensee is aware of this backlog of OR closeouts and is taking action to reduce the backlog and better track timely closeout of them.
The inspectors will monitor licensee progress in this area.
Review of Station Tem orar Modifications Administrative Procedure AP-3.3.2 provides for the control of temporary modifications and associated tests, maintenance, and operations of safety related and non-safety related plant equipment and systems.
This procedure is currently in the review cycle for the purpose of implementing corrective actions for procedural inadequacy identified in NEO Surveillance Report 88-1010.
The inspector reviewed several temporary modifications to determine the licensee's procedural compliance.
The temporary modifications appeared to have been properly controlled, conducted and documented.
Only minor document discrepancies were noted.
For example, different safety evaluation forms for
CFR 50.59 review were used on an interchangeable basis which indicated lack of uniformity in documentation and proper training on the part of the originators and the reviewers.
The inspector did not have any further questions.
Review of Station General Order 89-01 The inspector reviewed Station General Order (SGO) 89-01 for technical adequacy.
The licensee had issued the SGO order to provide administrative guidance for scheduling and performing Technical Specifications (TS) related surveillance test Accordingly, the window of extension of three consecutive TS survei llances has been restricted to 3. 15 instead of 3.25 times the single surveillance interval allowed by the facility's TS.
Any deviation from the regular TS surveillance is documented for review and approval by the station management.
The inspector reviewed selected completed surveillance tests and discussed the scheduling and planning activities with the cognizant coordinators.
The tests were conducted on schedule.
However, the inspector noted that control of 15% surveillance extension discussed in SGO 89-01 was not translated into the station computerized planning and scheduling activities for surveillances.
Instead, the Technical Specifications limit of 25;.'xtension for three consecutive survei llances was determined to be the controlling parameter in the computer tracking system.
The resident inspectors discussed the finding with the licensee.
The licensee noted the problem and plans to take corrective action to fix the program.
The Nuclear Quality Assurance Operations (NQAO) surveillance group reviews surveillance and test procedures used by Operations and I&C groups.
In addition, the NQAO surveillance group conducts scheduled and unscheduled survei llances of their controlled activities, issues surveillance reports, and trends nonconformances and deficiencies identified during NQAO surveillances for management review and escalated action.
The inspector discussed with the cogn'izant NQAO surveillance supervisor the conduct of NQAO survei llances, and reviewed selected surveillance reports including QA checklists.
These surveillance activities were adequately documented.
The NQAO oversight of surveillance activities appears to be adequate.
3.
Plant Ins ection Tours (71707, 71710)
During this reporting period, the inspectors made tours of the Unit
and 2 control rooms and accessible plant areas to monitor station activities and to make an independent assessment of equipment status, radiological conditions, safety and adherence to regulatory requirements.
The following were observed:
3.1 Unit
Tours of the "corner" rooms in the Reactor Building resulted in the inspectors questioning the design and current as-built configuration of the core spray and containment spray strainer assemblies and their associated concrete support pedestals.
Specific concern was raised over the fact that several of the strainer assembly flanges do not rest on the concrete pedestals but are "free floating" above the pedestal.
The licensee has been requested to clarify the original design intent for strainer assembly flanges and pedestal supports and
whether it is acceptable, through analysis, for the weight of a strainer assembly to be supported by the connected piping, rather than
,by its associated concrete pedestal.
Additionally, the licensee was requested to respond to the concern that the studs (imbedded in the concrete pedestal)
which pass through the assembly flanges are threaded, rather than smooth as would normally be expected.
The licensee was asked to provide documentation that this design is adequate and will not prevent free movement of the strainer assembly.
Lastly, the inspectors observed that steel re-bar in one of the pedestals was exposed and that the concrete on the top of one of the other pedestals had crumbled away in one section.
The licensee was requested to evaluate this concern.
The inspectors are awaiting licensee response to the
'above items and will document their review in a later inspection report.
The inspectors also performed an inspection tour of the drywell and North corridor on the Reactor Building 237 foot elevation.
Radiation Protection assistance was quite good and Radiation Protection technicians facilitated entry and exit to and from the drywell as well as the tour of the drywell.
The inspectors noted that general housekeeping has improved considerably from previous tours (reference IR 50-220/88-17).
Excess scaffolding and equipment has been removed and grafitti at the drywell entrance area has been removed.
In general, cleanliness throughout the plant continues to improve.
One area in which housekeeping practices could be better was the Emergency Condensor Isolation Valve room on the 281 foot elevation in the Reactor Building.
This was brought to the licensee'
attention for action.
3.2 Unit 2 The inspector observed control room activities, including shift turnover, and a Division II Emergency Diesel Generator operability surveillance test.
The control room was adequately manned, control activities were properly coordinated and conducted, and the control room operators were attentive to and responsive to the current status of the plant.
The inspectors monitored portions of plant start-up activities and identified no concerns.
The inspector observed that the licensee properly plotted the heat-up rate as required by Technical Specifications.
Operators proceeded cautiously during start-up and were cognizant of the status of all equipment and annunciator,
Surveillance Review (61726)
The inspectors observed portions of the surveillance testing listed below to verify that the test instrumentation was properly calibrated, approved procedures were used, the work was performed by qualified personnel, limiting conditions for operations were met, and the system was correctly restored following the testing.
4.1 Unit
While performing routine plant inspections, an NRC inspector noticed that the pressure gages on the refueling floor for the West-side and East-side main steamline plugs were indicating 65 psig and 35'psig, respectively.
The inspector questioned the disparity between the two gages and upon further investigation, determined that operation of the main steamline seal plugs is governed by IEC procedure Nl-IP-1. 14, Steam Line Plug Pressure Panel Installation.
Review of this p'rocedure and the changes made to it revealed several discrepancies:
Temporary Change Notice (TCN)-1, made on February ll, 1988, changed the steamline plug pressure monitoring frequency from weekly to daily.
However, numerous instances were identified by the inspector where pressure checks were not taken daily.
Further, from mid-June 1988 until March 1989, readings were taken on approximately a weekly basis (vice daily as required)
until the procedure was formally changed in March 1989 via TCN-2, to allow pressure readings to be checked weekly.
The requirements of AP-2 for procedural changes was not adhered to.
The pen and ink version of TCN-1 written on February 11, 1988, and attached to the working copy of the procedure, did not reflect the formal as-issued TCN.
Further, verbal authorization was given by an I@C supervisor to lower pressure on the East-side steam line plug to 30 psig plus or minus 5 psig in direct conflict with the procedurally required pressure of 80 plus or minus 5 psig.
The change was formalized three days later by use of a one-time-only (OTO)
change, yet instructions were not issued in that change as to when pressure should be returned to the normal value.
The OTO change contained inadequate instructions; further, it did not appear to have been adequately evaluated for the safety sigriificance of lowering of pressure to 30 psig plus or minus 5 psig.
The vendor technical manual for the steamline plugs indicates the seals on the plugs should be left at 90 psig; yet the licensee made no apparent evaluation for lowering pressure and the effect this could have on steamline plug integrity.
Procedure S-MI-GEN-004 was not used for exceptions made to the vendor manua The above observations were discussed with the Unit 1 Superintendent at a weekly meeting.
Subsequent to that meeting, the licensee confirmed that the procedures, Nl-IP-1. 14, S-MI-GEN-004 and AP-2, had not been adhered to as required by the. Technical Specifications.
Further, the Unit
IKC Supervisor was relieved of his duties and a
new I&C Supervisor assigned.
The Engineering Department contacted the steamline plug vendor and determined that if the seal assembly on the plug was lost, the mechanical seal feature of the plug would prevent leakage.
The vendor recommended plug pressure be set at 40 psig above the static head of water to which the plug is exposed.
This change was formalized by use of S-MI-GEN-004.
Procedure Nl-IP-1. 14 was rewritten and issued as procedure Nl-IDP-W-001-022 and is now performed completely on a weekly basis for steam plug pressure readings.
Installation and removal of the plugs are now controlled by two separate procedures.
The failure to follow procedure Nl-IP-1. 14 is a violation.
VIOLATION (50-220/89-04-02)
The inspector observed sampling of the Service Water System conducted by a Chemistry Department technician in accordance with procedure Nl-CSP-25M, "Service Water Effluent Sampling and Analysis".
The inspector verified that the portion of the procedure for obtaining samples in the field was used, that the technician was knowledgeable in the use of the procedure and that the technician had reviewed and understood the recent training on procedural compliance.
The inspector observed equipment calibration, service water sampling and the start of the sample analysis.
The Chemistry Technician was knowledgeable of the service water sampling requirements as well as other chemistry sampling requirements and analyses performed at Unit 1.
The inspector had no further questions or concerns in this area.
4.2 Unit a
~
The inspector observed the emergency diesel generator (EDG)
operability surveillance test conducted in accordance with procedure N2-OSP-EGS-M001 and verified the acceptance criteria was met.
The test personnel were adequately briefed prior to the test and the test procedures were properly followed.
During the test the inspector noted that the fuel storage tank level indicator alarm window had malfunctioned, and the EDG speed (rpm)
indicator in the control room panel did not match the actual speed indicated in the diesel room panel.
The operator issued two work requests to correct the problems.
No deficiencies or deviations were identified in the test.
The inspector observed the performance of Operations Surveillance Procedure No.
N2-OSP-ADS-R001 which checks ADS valve operability and position indication.
Good procedural adherence was noted by the inspector.
Safety relief valve 2MSS*PSY127 failed to
indicate open during testing.
The licensee determined the valve to be inoperable due to the improper functioning of the acoustic monitor system input and took appropriate action in accordance with technical specifications.
An emergency Work Request was issued to troubleshoot and resolve the problem.
The inspector identified no concerns with licensee actions I. ~e" ~pili V ii i
f77 On a sample basis, the inspectors directly examined portions of selected safety system trains to verify that the systems were properly aligned in the standby mode.
The following systems were examined:
5.1 Unit
Emergency Diesel Generators Core Spray
=
Containment Spray Emergency Cooling No concerns were identified.
Additional'ly, the four concerns noted in the last inspection report (89-02) with regard to walkdowns of the core spray system have been resolved to the satisfaction of the inspector.
5.2 Unit 2
- Service Water System
- Automatic Depressurization System No concerns were identified.
6.
Review of Licensee Event
~Re orts
~LERs (90712,92700)
The LERs submitted to the NRC were reviewed to determine whether the details were clearly reported, the cause(s)
properly identified and the corrective actions appropriate.
The inspectors also determined whether the assessment of potential safety consequences had been properly evaluated, whether generic implications were indicated, whether the event warranted on site follow-up, whether the reporting requirements of 10 CFR 50.72 were applicable, and whether the requirements of 10 CFR 50.73 had been properly met.
(Note: the dates indicated are the event dates)
6.1 Unit
a.
The following LERs were reviewed and found to be satisfactory, however, the identified corrective actions will be monitored and reviewed in a subsequent report:
LER 89-01, February 16, 1989; Technical Specification Violation Due to Improper Calibration of Overpressure Relief Setpoints on Electromatic Relief Valves.
The root cause of this event was the lack of an effective management process to ensure TS amendments are implemented in a timely manner.
This LER is discussed in Section 1 of the report.
6.2 Unit 2 The following Unit 2 LERs were reviewed and found to be satisfactory and are considered closed.
Each LER contains a
Technical Specifica'tion Violation that was identified by the licensee.
In accordance with 10 CFR 2 Appendix C, Section V.6, no Notice of Violations are being issued for these events.
LER 88-27, Technical Specification Violation (TS) due to Failure to Submit a Special Report Because of Personnel Error.
The event date was July 7, 1988.
NCV 50-410/89-04-03.
LER 88-36, Failure of a Transfer Switch Contact to Return to Normal Results in an inoperable Diesel Generator and a Violation of Technical Specifications.,
The event date was July 21, 1988 (NCV 50-410/89-04-04).
LER 88-41, Failure to include an explanation of the inoperability of a Liquid Radwaste Effluent Monitor was in Violation of Technical Specifications.
Event date was August ll, 1988 (NCV 50-410/89-04-05).
LER 88-51, Shutdown Cooling Isolation during EPA Surveillance Testing resulted in a Technical Specification Violation due to a design deficiency and a lack of support for Pre-Job Review.
Event date was August 13, 1988 (NCV 50-410/89-04-06).
LER 88-53, Technical Specification Violation on a late 125 DC Battery Surveillance, due to Personnel Error.
Event date was September 27, 1988 (NCV 50-410/89-04-07).
LER 88-58, Technical Specification Violation on a late Average Power Range Monitor Surveillance, due to programmatic deficiency.
Event date was October 7, 1988 (NCV 50-410/89-04-08).
7.
Licensee Action on NRC Bulletins (90712)
The inspector reviewed licensee records pertaining to the NRC Bulletins identified below to verify that: the Bulletins were received and reviewed for applicability; written responses were provided, if required; and the corrective action taken was adequat.1 Unit
20 e
~Fol iowa On MRC Bulletin BB-O7, Power Oscillation Manual Scram By letter dated September 12, 1988, the licensee informed the NRC of completed and proposed actions in compliance with the requi rements of NRC Bulletin 88-07.
Accordingly, Nine Mile Point Unit 1 (NMP-1) had briefed reactor operators and shift technical advisors on the LaSalle Unit 2 incident involving a dual recirculation pump trip and subsequent excessive neutron flux oscillations while in natural circulation.
Also, procedure Nl-ROI-3 was established which recognized the onset of uncontrolled neutron flux oscillation and described remedial
.
action to manually scram the reactor.
The inspector discussed with the NMP-1 reactor analyst and the cognizant training coordinator the licensed operators'-training program developed to discuss the content and actions taken in response to NRC Bulletin 88-07.
The licensed operator requalification training program provided training on procedure Nl-ROI-3.
In addition, the Training Department has committed to institute the procedure in the licensed operators initial classroom training.
However, the station simulator has not yet incorporated the unstable neutron flux oscillation in the simulator training module.
Review of the licensee's documentation regarding the installed neutron detection capability indicated that the neutron monitoring system (NMS) supplied by GE provides adequate instrumentation for operator information needed to mitigate core instability.
The licensee also stated that the original NMS installation and subsequent modifications had not altered the ability of the NMS instrumentation to indicate neutron flux oscillation and initiate an automatic scram.
In response to NRC Bulletin 88-07 Supplement 1, the licensee's letter dated February 1,
1989 stated that the GE interim stability recommendation will be incorporated in the operating procedure and subsequent training will be provided to the licensed operators prior to the plant restart.
The licensee representative also indicated that NMP-1 is a low power density operating plant and, as such, some of the GE recommendations are not applicable.
However, the licensee is committed to review the BWROG generic long term corrective actions and will implement plant specific changes.
Based on the above review and discussion with the licensee representative, the inspector determined that the licensee's interim actions to address neutron flux instability are adequate.
The inspector does not have any further questions at this tim e b.
Bulletin 85-03 (Unit I):
As requested by Action Item e. of Supplement 1 to Bulletin 85-03,
"Motor-Operated Valve Common Mode Failures During Plant Transients Due to Improper Switch Settings,"
the licensee's response, dated May 26, 1988, identified the additional valves to be addressed in the MOV maintenance program in response to the original bulletin.
Review of this response indicates that the licensee's selection of the additional valves to be addressed in their program in response to the original bulletin meets the requirements of action item e. of the Supplement to the Bulletin and is acceptable.
The results of the inspections to verify proper implementation of this program wi 11 be addressed in a subsequent inspection report.
7.2 Unit 2 a.
~Fol 1owu On MRC Bulletin 88-07, Power Oscillation Manual Scram By letter dated September 12, 1988, the licensee informed the NRC of completed and proposed actions in response to the requirements of NRC Bulletin 88-07.
Accordingly, Nine Mile Point Unit 2 (NMP-2) had briefed reactor operators and shift technical advisors on the LaSalle Unit 2 incident involving a dual recirculation pump trip and subsequent excessive neutron flux oscillation while in natural circulation.
Also, Procedure N2-OP-29 paragraph H, Off Normal Procedure, was revised to recognize the onset of uncontrolled neutron flux oscillation and described remedial action to manually scram the reactor.
The inspector discussed with the NMP-2 reactor analyst and the cognizant training coordinator the licensed operators training program developed to discuss the content and actions taken in response to NRC Bulletin 88-07.
The licensed operator requalification training program had provided training on Procedure N2-OP-29.
In addition, the Training Department has committed to institute this procedure in the licensed operators'nitial classroom training.
The station simulator training program also incorporated the unstable neutron flux oscillation in the training module and provided training to the NMP-2 licensed operators.
Review of the licensee's documentation regarding the installed neutron detection capability indicated that the neutron monitoring system (NMS) supplied by GE provides adequate instrumentation for operator information needed to mitigate core instabilities.
The licensee also stated that the original NMS installation and subsequent modifications had not altered the ability of the NMS instrumentation to neutron flux oscillations and initiate an automatic scra The inspector verified that Procedure N2-OP-29 had addressed the GE interim stability recommendation described in Generic Letter 88-07 Supplement 1.
However, generic long term corrective action is still under BWR Owner Groups (BWROG) evaluation.,
The licensee has committed to review the BWROG evaluation and implement plant specific changes, as appropriate.
Based on the above review, the inspector determined that the licensee interim action to address the neutron flux instability issue is adequate.
The inspector does not have any further questions at this time.
8.
Assurance of ~valit (30702, 30703, 83723)
As noted in IR SO-410/88-18, licensee initial response to correcting identified deficiencies in the Post Accident Sampling System PASS was inadequate and one more example of the NRC's stated concern that licensee initial corrective actions are often incomplete.
However, licensee followup to the identified deficiencies was thorough, comprehensive and complete.
The additional steps the licensee took to actually install jumpers, verify that samples could be obtained and still meet the requirements of NUREG 0737 are commendable.
Licensee actions to correct the deficiencies the second time around should serve as a model for how initial corrective actions should be performed.
The procedural compliance violations documented in this report indicate a significant weakness in the use and adherence to procedures.
However, the NRC notes that these violations occurred before the licensee conducted training as requested by the NRC following the Special Team Inspection.
Licensee performance subsequent to the training will demonstrate its effectiveness.
The NRC will closely monitor the use of procedures and procedural compliance in future inspections.
The inspector asked licensee management (including (}uality Assurance)
at the exit meeting why prompt and effective corrective actions were not taken to correct procedural compliance problems.
The licensee responded that the corrective actions taken in the past with regard to the use of procedures was too narrowly focused on each individual event rather than the broader implications.
Corrective actions regarding the Unit 2 design error in the Service Water System discussed in Section 2.d were thorough and well executed by the licensee.
9.
Exit M~ieetin s
(30703)
At periodic intervals and at the conclusion of the inspection, meetings were held with senior station management to discuss the scope and findings of this inspection.
Based on the NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain Safeguards or 10 CFR 2.790 information.