IR 05000289/1986017
| ML20207K960 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 12/23/1986 |
| From: | Blough A, Conte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20207K870 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.B.3, TASK-TM 50-289-86-17, EIB-82-02, EIB-82-2, IEB-83-03, IEB-83-3, IEIN-85-071, IEIN-85-074, IEIN-85-075, IEIN-85-100, IEIN-85-71, IEIN-85-74, IEIN-85-75, IEIN-86-014, IEIN-86-14, NUDOCS 8701090571 | |
| Download: ML20207K960 (57) | |
Text
{{#Wiki_filter:- e , U.S. NUCLEAR REGULATORY COMMISSION
REGION I
. ' Report No.
50-289/86-17 Docket No.
50-289 License No.
DPR-50 Priority -- Category C Licensee: GPU Nuclear Corporation Post Office Box 480 Middletown, Pennsylvania 17057 ' Facility At: Three Mile Island Nuclear Station, Unit 1 Inspection At: Middletown, Pennsylvania Inspection Conducted: September 8 - October 3, 1986 _ Inspectors: R. Conte, Senior Resident Inspector M. Dev, Reactor Inspector R. Freudenberger, Reactor Engineer (in training) D. Johnson, Resident Inspector M. Miller, Radiation Specialist G. Napuda, Lead Reactor Inspector J. Rogers, Resident Inspector A. Varela, Lead Reactor Engineer F. Young, Resident Inspector H. Zibulsky, Chemist Reporting Inspector: [,4b
- ON R. Co6te, Chief, Reactor Projects Date ev-Section No. lA, Division of Reactor Projects Approved By:
[[ / 6 23 % A. B16dgh,' Chief Date Reactor Projects Branch No 1 Division of Reactor Projects Inspection Summary: i Resident and region-based NRC staff conducted routine safety inspections (482 hours) of power operations, focusing on plant and organizational performance.
Items reviewed in the plant operations area, including maintenance and sur- , veillance, were: reactor coolant system leakrate; reactor building aircraft protection; reactor building airborne activity; control rod configuration change; engineered safeguards actuation system testing; fire protection implementation and event response; makeup system valve operability; and, safety system alignment.
Special focus occurred on: reporting and report review program; technical and safety review; chemistry (non-radiological); material control; and, document control.
Licensee action on previous inspec-tion findings was also reviewed.
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.. , , . . .. Inspection Results: la In general, the licensee continued to closely cv'itor power operations and especially those problems that could become safety significant; such as, the reactor building airborne radioactivity buildup and the "C" reactor coolant pump No. I seal leakoff high flow problem.
The control rod configuration change was handled well and with appropriate focus on nuclear safety. High Pressure Injection (HPI) system valves were carefully maintained, except as noted below, and these valves were in proper alignment to perform their safety function. Overall, event review was sufficiently thorough with appropriate corrective actions specified. However, procedure control problems resurfaced during this period.
Due, in part, to a lack of specific procedural measures, the reactor building aircraft protection door was open during five days following of the outage of April 1986, which is contrary to safety analysis commitments and licensee requirements (paragraph 2.2.2); however, licensee follow-up for this event did not include upgrading of the procedural controls.
Further, a number of examples were noted of failure to follow a surveillance / operating procedure and related administrative procedures on engineered safeguards (ES) actuation testing, a complex surveillance test (paragraph 2.2.5).
This resulted in a lack of complete independent verification of the proper alignment of the standby high pressure injection system and in the unintentional entry into a Technical Specification limiting condition for operation action statement for eighteen hours. Cooling water was lined up from a high pressure injection pump and another pump was not properly aligned to receive an ES signal.
In this matter, operator error occurred; but, also, managerial guidance (on how to accomplish the initial portions of the test) could not be ruled out as a contributing factor.
Preventive maintenance on fire doors appears to be effective in resolving door closing problems.
The mis position of an instrument root valve used to detect deluge actuation appears to be due to poor worker attention to detail to properly follow procedures.
This inspection confirmed preliminary findings by NRC Office of Inspection and Enforcement Performance Appraisal Team (PAT) that the licensee apparently has, in cases, failed to comply with existing TS under the previous review process (paragraph 6.2).
Further the licensee's new safety review program requires written safety evaluations for a lesser scope than that which is apparently required by TS (paragraph 6.3).
No significant safety issues have resulted because of the failures. The NRC staff continues to closely monitor procedure changes until the issue is fully discussed in a Regional meeting.
In their response to the violation for failure to follow an alarm response procedure on a waste gas release, the licensee contested the violation; and, in general, the response reflected a nonconservative approach in resolving symptoms of problems related to alarms.
The licensee will have to make a supplemental response.
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, . . Ib Further, two previously unresolved items were determined to be violations.
They were: failure to properly document the setpoint basis for containment isolation functions of certain radiation monitors (paragraph 10.3) and failure to properly evaluate a modification to a source range power cable configuration change at a reactor building penetration (paragraph 10.7).
A number of other licensee specialized programs; such as, plant chemistry (r.on-radiological), non-routine report review, material control, and document control (aside from drawings), appear to be well established and properly implemented. The licensee is responsive to reviewing industry-wide problems for applicability to their facility. Minor unresolved issues were identified.
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Introduction and Overview 1.1 NRC Staff Activities The overall purpose of this inspection was to assess licensee activities for the power operation mode as they related to reactor safety. Within each area, the inspectors documented the specific purpose of the area under review and scope of the inspection.
The inspector made this assessment by reviewing information on a sampling basis through actual observation of licensee activities, interviews with licensee personnel, measurement of radiation levels, or independent calculation and selective review of listed applicable documents.
During this period and in addition to the routine review of licensee activities, the resident inspectors focused on follow-ing up a number of unresolved issues, some of which dated back to the restart period (paragraph 10); and, in particular, they extensively reviewed the implementation of the licensee's safety review process (paragraph 6).
There was substantial review by Region I-based inspectors in the following areas: material control, including procurement; receipt, storage, and handling (paragraph 8); records and documents control (paragraph 8); and, plant chemistry (paragraph 9).
1.2 Licensee Activities ' Licensee persont.el and NRC staff continue to closely monitor the "C" reactor coolant pump seal, which continues to have higher than normal leakage (nominally 2 gallons per minute). The leakage is between 5 to 6 gallons per minute.
The licensee is monitoring the seal and presently expects to be able to continue full power operations until the planned outage scheduled in November 1986.
Inspection and appropriate repairs will be performed during the next outage.
' The licensee removed RM-L9 from service. This radiation monitor i was used to check Intermediate Closed Cooling (IC) System for inleakage from contaminated systems cooled by the IC system.
Leakage from the letdown coolers had increased to the point of saturating the detector. The licensee is presently using grab samples from the IC system to monitor the leakage from the coolers. No significant radiological problems occurred as a result of the leaking letdown cooler. This subject has been addressed in previous NRC inspection reports.
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2.
Plant Operations 2.1 Scope of Review The NRC resident inspectors periodically inspected the facility to determine the licensee's compliance with the general operat-ing requirements of Section 6 of the Technical Specifications (TS) in the following areas: review of selected plant parameters for abnormal trends; -- plant status from a maintenance / modification viewpoint; -- -- control of ongoing and special evolutions, including control room personnel awareness of these evolutions;
control of documents; including logkeeping practices; -- implementation of radiological controls; -- -- implementation of the security plant, including access control, boundary integrity, and badging practices; and, implementation of the fire protection plan, including fire -- barrier integrity, extinguisher checks, and housekeeping.
. Because of additional resident office coverage at this facility, more detailed and frequent reviews of operating personnel performance were conducted to determine that: operators are attentive and responsive to plant parameters -- ard conditions; plant evolutions and testing are planned and properly -- authorized; procedures are used and followed as required by plant -- policy; equipment status changes are appropriately documented and -- communicated to appropriate shift personnel; the operating conditions of plant equipment are effectively -- monitored and appropriate corrective action is initiated when required; , backup instrumentation, measurement, and readings are used -- as appropriate when normal instrumentation is found to be defective or out of tolerance; _ - - - _ _ _ _ _ _. _ - _ _ _ _ _ - ~ _ - _ -. .,_ _ _, -.. _ - _ -. _
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logkeeping is timely, accurate, and adequately reflects -- plant activities and status; operators follow good operating practices in conducting -- plant operations; and, operator actions are consistent with performance-oriented -- training.
Specifically, the inspectors focused attention on the areas listed below.
General / Operations Control room operations during regular and backshift hours, -- including frequent observation of activities in progress, and periodic review of selected sections of the shift foreman's log and control room operator's log and other control room daily logs -- Areas outside the control room, including important-to-safety buildings detached from main plant buildings Selected licensee planning meetings -- Reactor building sump in-leakage monitoring -- Axial Power Shaping Road (APSR) withdrawal -- -- Fire barrier integrity Condenser offgas radiation process monitor operations -- Maintenance Work planning meetings -- Preventive maintenance associated with fire deluge valve -- alignment Testing and repair of alarms associated with AH-VIB -- Radiological Controls Locked high radiation doors -- Radiation Work Permit (RWP) posting -- Survey maps --
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Surveillance Engineering Safeguard Actuation Testing -- -- Reactor Protection System (RPS) setpoint settings As a result of this review, the inspectors reviewed specific events in more detail as described in the sections that follow.
2.2 Findings 2.2.1 Reactor Coolant System (RCS) Leak Rate The inspector selectively reviewed RCS leakrate data for the month of September 1986. The inspector independently calculated certain RCS leakrate data reviewed using licensee input data and a generic NRC " basic" computer program "RCSLK9" as specified in NUREG 1107.
Licensee and NRC data are tabulated below. Although plant specific parameters are used, the program is somewhat generic, so RCSLK9 does not consider the reactor coolant pump's No. 3 seal combined leakoff (0.1044 gpm). The correlation of licensee and NRC data is as follows.
"UNIDENT = NGLR IDENT-N CORRECTED NUNIDENT = NGLR + 0.1044 - NIDENT = (NUNIDENT + 0.1044) which should equal LUNIDLK L = Licensee Unidentified Leakrate UNIDLK NUNIDENT = NRC Calculated Unidentified Leakrate N = NRC Calculated Gross Leak Rate based on RCS GLR , mass balance (which should correlate with L - Licensee Calculated Leakage Plus RCSLPL Losses Term) N = NRC Calculated Identified Leak Rate IDENT (essentially reactor coolant drain tank mass change) 0.1044 = Total leakage due to No. 3 RCP seal leakoff
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TABLE 1 RCS LEAKRATE DATA (All Values GPM) DATE N UNIDENT CORRECTED DURATION L RCSLPL N GLR (NUREG 1107) N UNIDENT L UNIDKL 9/4/86 07:11:14 0.2032 0.21 0.02 0.12 0.1230 2 Hours 9/15/86 15:50:05 0.2797 0.28 0.00 0.10 0.1105 2 Hours 9/23/86 08:08:18 0.2539 0.25 0.00 0.10 0.1049 2 hours 9/23/86 17:56:18 0.2687 0.27-0.01 0.09 0.0932 2 Hours 9/26/86 09:33:55 0.2589 0.24-0.01 0.09 0.1169 2 Hours Columns 2 and 3; 5 and 6 correlate 1 0.2 gpm in accordance with NUREG 1107 The inspector concluded that the licensee leakrate determina-tions were in good agreement with those calculated by the NRC staff program.
2.2.2 Reactor Building Aircraft Protection On or about April 28, 1986, a member of the Independent Onsite Safety Review Group (IOSRG) noticed the missile door open and reported it to the shift supervisor. About the same time, the open door was also noted by an NRC inspector.
Based on the IOSRG notification, the shift supervisor had this door closed after making sure there was no good reason for it to be open; ie, maintanance, etc. Apparently, the door had been open since the reactor startup April 23, 1986, coming out of the outage of March 1986.
The missile door is a large concrete slab on rails that is designed to protect the large equipment hatch (a part of containment structural integrity) from a design basis aircraft crash. As described in the updated Final Safety Analysis Report (FSAR) (Section 5.1.3 and Figure 5.1-1), the reactor building with the missile shield in the closed position is a structure .-. _ - -_.
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vital to the protection of the reactor coolant pressure boundary and the structure, along with others, is designed to the aircraft impact criteria.
Because the licensee identified the open door and restored it to the proper (closed) position, no further action by NRC was warranted at the time.
During this inspection, the inspector followed up to determine what licensee corrective actions had been developed to prevent recurrence of the missile door being open during power operations. The inspectors determined the following: -- The IORSG review of the matter was documented in internal correspondence and it received licensee management attention.
However, the matter was still under review by IORSG.
The licensee's Operating Procedure (0P), Revision -- 86, 'lant Heatup to 525 F," OP 1102-2, Revision 73, " Plant Startup," OP 1101-3, Revision 41, " Containment Integrity / Access Limits" did not have any obvious signoffs or procedural steps to assure that the missile door is closed before > plant conditions are reached which require containment integrity.
The inspector concluded that between April 23 and 28, 1986, during reactor power operations, containment missile protection was not maintained as committed to by the licensee in their FSAR. This is contrary to 10 CFR 50 Appendix A Criterion 4 on " Environmental and Missile Design Basis." The 10 CFR 50 Appendix B Criterion III on " Design Control" requires, in part, that applicable regulation requirements and design bases as specified in the license application (FSAR and 10 CFR 50 Appendix A) are correctly translated into specifications, drawings, procedures, and instructions (289/86-17-01).
The lack of procedural controls might have contributed to why the door was found open April 23-28, 1986. The , safety significance of this event is minimal. At the time, containment isolation was operable along with structural integrity based on the last completed surveillances, except for the missile door being open.
The size of the structural opening was relatively small compared to the overall surface area of the RB volume.
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door was open for only five to six days and the likelihood of an aircraft crash was extremely remote considering the aircraft movement activity near the TMI-1 site.
'The failure to promptly upgrade administrative controls (e.g., procedures) to preclude recurrence of this event also represents another example of licensee failure to take prompt corrective action on a condi-tion adverse to quality (cited in NRC Inspection Report 50-289/86-12).
2.2.3 Reactor Building Activity During the report period, reactor building (RB) radiation monitor RM-A-2 indicated an increasing radioactive airborne concentration in the building.
During a routine RB entry, licensee' personnel discovered that pressurizer sampling valve CA-V-1 was leaking through the seal leakoff line discharging into a funnel drain connected to the RB sump. The licensee concluded that CA-V-1 seal leakoff could be one of the causes of increased RB activity. CA-V-1 could not be isolated since two other sample valves (CA-V-2 and CA-V-13), if opened, would allow back pressure to continue CA-V-1 seal leakoff. On September 11, 1986, licensee personnel capped the seal leakoff line, but a welded union in the line was found to also have leaks.
Increased RB radioactive airborne concentration is one ' of the first indications of reactor coolant system (RCS) leakage.
It is possible that high RB activity due to CA-V-1 seal leakoff could obscure a smaller but potentially more significant reactor coolant leak.
The licensee continues to closely monitor RCS leakrate calculations. No significant changes were noted for these results (see also paragraph 2.2.1).
The NRC inspectors discussed the above concerns with cognizant licensee personnel, and they will continue to routinely monitor RB radioactive airborne concentrations, along with RCS leakrate results.
2.2.4 Control Rod Configuration Change On September 2,1986, the NRC issued License Amendment No. 120 to the facility operating license for TMI Unit 1.
This amendment allows the withdrawal of axial power shaping rods (APSR's) at end-of-cycle core conditions to extend the current operating cycle.
Withdrawal of the APSR's facilitate more complete use of available fuel to extend the current fuel cycle to approximately 290 15 effective full power days. The _ _. . -,.. . . .- -..-_ _ _ -.. _-__-__
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need to extend the life of the present reactor core was due to a higher than projected capacity factor for the first year after restarting the plant. The overall result of this amendment allows continued operation until abuut November 1, 1986, before beginning the Cycle 6 refueling outage.
On September 3, 1986, the licensee began the necessary actions to support implementation of this amendment.
Applicable station operating and surveillance procedures were changed to reflect the new amendment s reactor protection system (RPS) limits. Setpoints in the RPS were changed to reflect the requirements of the amendment.
On September 13, 1786, the licensee reduced power to 60% to support APS.<'s withdrawal.
Reduction in power was performed to ensure that power distribution limits would not be exceeded during APSR's withdrawal.
The licensee then withdrew the APSR's. After various tests to ensure that the reactor core response was as predicted, the reactor power was slowly returned to 100 percent power. By the afternoon of September 14, 1986, the plant was returned to full power.
An inspection was performed to verify the licensee performed all of the surveillance tests required by the license amendment, applicable procedures had been properly changed reflecting the new reactor physics limitations as described in the License Amendment Safety Evaluation, and personnel involved were knowledgeable of the plant configuration change.
The inspector reviewed portions of the following procedures for adequacy in reference to the NRC safety evaluation for this rod configuration change.
Operating Procedure (0P) 1101-01, Revision 26, -- " Plant Limits and Precautions" -- OP 1102-01, Revision 84, " Plant Heatup to 525 F" -- OP 1102-04, Revision 41, " Power Operation" OP 1102-10, Revision 33, " Plant Shutdown" -- OP 1102-02, Revision 71, " Plant Startup" -- OP 1103-04, Revision 24, " Soluble Poison Concen-
-- tration Control"
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-- OP 1103-08, Revision 25, " Approach to Criticality" -- OP 1203-7, Revision 19, " Hand Calculations for Quadrant Power Tilt and Core Power Imbalance" -- OP 1301-01, Revision 61, " Shift and Daily Checks" -- OP 1301-9.5, Revision 20, " Reactivity Anomaly" The inspector reviewed the recalibration of the Reactor Protection System (RPS) channels to the new TS setpoints (TS 2.3) per revised SP 1303-4.1, Revision 48, " Reactor Protection System," as allowed by the license amendment. During the calibration of the "D" RPS channel there was an event of minor significance.
Subsequent to the replacement of a repaired square root extraction module for feedwater flow into the D RPS cabinet, operators sensed smoke in the control room and traced it to a transformer in ICS cabinet No.12 in the relay room. A voltage transformer which feeds the subject instrument module was smoking. Operators then deenergized the transformer. The smoke was not extensive enough to cause a fire alarm, and there was no need for fire brigade response.
The transformer and the instrument module were replaced.
Licensee response to this event was appropriate and this event did not result in a plant transient.
During the recalibration of RPS Channel "D" per SP 1303-4.2, licensee personnel observed that the full scale current setting had not been recorded on the RPS cabinet door as required by Step P of Attachment 2, SP 1302-1.1, " Power Range Calibration," during the heat balance verification performed on August 23, 1986. On reviewing the completed power range calibration surveillance, the licensee noted that the above Step P of SP 1302.1.1 had been initia11ed complete for all four RPS cabinets.
RPS cabinets A, B, and C all had the August 23, 1986, current setting recorded.
Instrument and Control (I&C) personnel determined that RPS Channel "D" full scale current setting had been set according to the heat balance setting stipulated in SP 1302-1.1. Therefore, the "D" RPS channel had been reset according to procedure but not recorded on the RPS cabinet door as required. The licensee supervision counselled the I&C technician involved concerning the importance of procedure adherence. The inspector had no additional comments on the particular problem and licensee followup action was appropriate.
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The inspector discussed the APSR withdrawal evolution and the licensee's predictions of core response with the licensee's lead nuclear engineer.
Discussions were held with several operating crews to determine the general knowledge level concerning the APSR withdrawal.
In addition, the inspector witnessed portions of the work done by the licensee to reset the RPS setpoints.
The inspector noted that the licensee had properly implemented the amendments as described in the safety evaluation.
Required procedures were changed and in place at the appropriate time to support the APSR withdrawal.
Proper review and training had occurred.
The inspector also noted that the plant had responded as predicted and the licensee had accurately charac-terized the expected changes.
In general, the licensee performed this evolution safely.
2.2.5 Engineered Safegua-ds Actuation System Testing 2.2.5.1 Background On Tuesday morning, September 23, 1986, at 3:47 a.m., makeup pump 1A (MU-P-1A) was placed in service as part of the preparations to perform Surveillance Procedure (SP) 1303-5.2, Revision 22, dated June 11, 1986, " Loading Sequence and Component Channel Test and High Pressure Injection Logic Channel Test."
In placing MU-P-1A in service, the cooling water supply to its motor and bearings was shifted from decay heat closed cooling (DC) water to nuclear services (NS) closed cooling water. This involved closing DC-V-41A, DC water supply isolation valve from the DC water system.
Because of a small Jacket coolant leak on the "A" diesel generator (EG-Y-1A), which is required to be operable and warmed up as a prerequisite to the test, the surveillance procedure was postponed. The shift supervisor directed the operating crew to restore MU-P-1A to its original alignment. At 7:47 a.m., the pump was shutdown; and, at 11:10, a.m. its cooling water was logged in the primary operator's log as shifted back to the DC system from the NS system.
During the September 23, 1986, 3-11 shift, the EG-Y-1A leak was repaired and was tested satisfactorily. As a result, SP 1303-5.2 was rescheduled for the September i 24, 1986 daylight shift.
Therefore, the same 11-7 shift was shifting the cooling water to MU-P-1A in __ ___ -. - _ __ , _ _ _ ' . . .
preparation for SP 1303-5.2, when the auxiliary operator (AO) found DC-V-41A closed and realized that it had probably been in that condition since he closed it the night before.
The A0 notified the shift foreman, who made the proper licensee internal notifications (AP 1029), corrected the discrepancy on MU-P-1A, and verified that there were no other cooling water system discrepancies with the other standby makeup pump (MU-P-1C).
2.2.5.2 Review With respect to why DC-V-41 was out of position for the plant conditions, the inspector reviewed the following licensee documents: -- Surveillance Procedure (SP) 1303-5.2, Revision 22, dated June 11, 1986, " Loading Sequence and Component Test and High Pressure Injection Logic Channel Test;" -- Operating Procedure (0P) 1104-2, Revision 60, dated September 19, 1986, " Makeup and Purifica-tion System;" -- OP 1107-3, Revision 35, dated July 25, 1986, " Diesel Generator;" -- Administrative Procedure (AP) 1001G, Revision 10, dated April 16, 1986, " Procedure Utilization;" and, -- AP 1001J, Revision 6, dated July 22, 1986, " Technical Specification."
The inspector also reviewed applicable technical specifications, the shif t logs, and Plant Incident Report (PIR) No. 1-86-09, "0C-V-41A Out of Correct Position for Plant Conditions," dated September 24, 1986.
2.2.5.3 NRC Findings The Plant Incident Report (PIR) contained a detailed explanation of the sequence of events leading to DC-V-41A being out of correct position for the plant conditions. The PIR identified the failure to properly implement procedures, poor logging of various events conducted to support the SP, and the failure to properly conduct independent verification as required by facility procedures. As noted by PIR 1-86-09, the
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auxiliary operator (AO) "... did not actually manipulate the last valve of this four valve sequence." This is a failure to properly implement Operating Procedure (0P) 1104-2, " Makeup and Purification System," Revision 60, dated September 19, 1986 (the procedure being used instead of SP 1303-5.2).
In addition, Operating Procedure (0P) 1104-2 requires independent verification of the "DC-P-1A supply cooling requirements for MU-P-1A" (non-specified alignment), which had not been performed as noted by the PIR.
The corrective actions outlined in the PIR were oriented toward personnel actions but also included putting the DC supply valves on the locked valve list.
i These actions were acceptable for the specific problems identified in the report. However, the PIR does not adequately address the manner in which the SP was conducted. The licensee's report does not address the failure to properly document the steps as they were completed on a controlled copy of the SP.
Similarly, it also does not address the poor approach used to initiate plant configuration changes performed in preparation for SP 1303-5.2.
ESAS testing is a complex test requiring manipulations and configuration changes in several systems.
Procedure SP 1303-5.2 is the procedure written to provide overall control of this complex test, including preparatory con-figuration changes.
But, in this event these plant configuration changes were instead directed by orders in the Night Order Book, causing steps of the procedure section of 1303-5.2 to be performed without officially entering the procedure.
It appeared to the inspector that , ! SP 1303-5.2 should have been entered prior to performing the plant configuration changes.
This would have caused a sheet (Appendix 1 to SP 1303-5.2) to be completed which noted the initial condition of the equipment that was manipulated by the surveillance procedure; thus, enabling the equipment to be returned to its initial condition as outlined in the restoration-to-normal data sheet along with independent verification of specific valves.
(The related OP did not have a specific alignment to verify on DC/NS valve shifting.)
After subsequent review, the inspector noted that the methodology of conducting the surveillance test was contrary to administrative procedures (AP). The AP 1001G, Revision 10, dated April 16, 1986, " Procedure . -. _ _..-., ..- - -.- . _. -- . , -.. . - - - .
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Utilization," paragraph 3.3.5.a; AP 1001J, Revision 6, dated July 22, 1986, paragraph 3.2.4; and, SP 1303-5.2, paragraph 5.9.
These facility procedures essentially require that the applicable surveillance procedure be used and initialled as steps were completed. The above examples are considered to be representative of the failure to properly implement facility procedures, which is an apparent violation of Technical Specification 6.8.1 (289/86-17-02).
As a result of the above, the licensee determined that for about 18 hours only one (of the required two) makeup pumps was operable.
One pump ("1A") was inoperable because of the isolated cooling water supply valve. The swing pump ("1B") was inoperable because it was not "ES" selected (i.e., capable of receiving an ES start signal).
The 72-hour time restriction of TS 3.3.2 for this condition was not exceeded, however. Accordingly, this event has only minor technical safety significance.
This event, considered collectively with other examples to follow procedures noted since TMI-1 Restart reflects poorly on licensee personnel attitude or respect for procedure utilization in the plant.
Further, this particular event represents a case where night orders were used in prefer-ence to the approved procedure to control the initial stages of a complex test. Thus, although personnel error occurred, managerial guidance on the conduct of this test cannot be ruled out as a contributing factor in this violation.
2.2.6 Fire Protection Implementation 2.2.6.1 Preventive Maintenance Procedure The inspector reviewed Preventive Maintenance Proce-dure (PMP) U-27, Revision 0, dated June 19, 1985, " Functional Testing of Fire Doors," to determine whether it adequately conformed with applicable regulatory requirements and to ascertain whether it is technically adequate to ensure that the fire doors will perform as designed. As part of this review, the inspector also examined the following documents: Surveillance Procedure (SP) 1303-12.20, Revision 4, -- dated December 20,1985, " Fire Door Inspection - Control Building and Diesel;" SP 1303-12.21, Revision 5, dated September 18, -- 1986, " Fire Door Inspection - Primary Side;" and, l
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SP 1303-12.22, Revision 4, dated December 11, -- 1935, " Fire Door Inspection - Screen House."
The inspector determined that the procedure includes appropriate precautions to ensure that proper correc-tive actions will be followed if a fire door is found to be not functional. Also sufficient procedures, acceptance criteria, and notes are incorporated to ensure the doors that are tested will perform as required, and the applicable technical specifications will be addressed.
An error was identified on the data sheet. The data sheet identified door number C131 as a redundant door separating the turbine building the the control building stairwell.
In fact, door C131 is in the auxiliary building. The inspector questioned why door C131 was improperly identified and, after reviewing preventive maintenance procedure U-27, the licensee made a Procedure Change Request (PCR) to correct the error.
The inspector determined that PM U-27, " Functional Testing of Fire Doors," was adequate to ensure that the fire doors inspected are in an operable condition.
The licensee's personnel were cooperative and responded quickly to review and correct the error identified on the data sheet of the procedure.
2.2.6.2 Turbine Building Deluge System Alarm Control Valve Position On September 24, 1986, at 6:56 p.m., an alarm control valve (FS-V-1258) for fire protection deluge valve (FS-V-170) in the turbine building (for non-safety related fire services) was found in the closed position. The licensee identified this during the implementation of Job Ticket CK 676, which was generated because the alarm apparently malfunctioned during the conduct of an internal (non-TS related) operations surveillance (OPS-S191).
The alarm control valves associated with the fire protection deluge valves provide a method to isolate the indication when the fire protection deluge system actuates for testing purposes. When the alarm control valve is closed, there will be no alarm associated with the actuation of the associated deluge valve.
However, the deluge valve will actuate as designe __ _
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The alarm control valve misposition (with respect to Operating Procedure 1104-458) was logged in the Shift Foreman Log, but the root cause was not given.
Apparently, other JT work was to install new instrument root valves to reduce the susceptibility for corrosion. As each valve was worked, it was then to be left in the open position. Apparently, FS-V-1258 was left closed, however.
Subsequent to this finding, similar alarm isolation valves that had been replaced were verified by the licensee in the other safety-related areas and no others were found to be closed.
Further, SP 1303-12.13 does the same FS system flushing surveillance as OPS S191, but the SP is used for safety related areas. This SP was satisfactorily completed and up to date. Without the benefit of a more detailed review, the inspector concluded that non-important-to-safety aspect of OP 1104-45B was not properly implemented to assure proper position of FS-V-1258.
This is another example of failure to properly follow procedures.
2.2.6.3 Inadvertent Actuation of Fire Protection Sprinkler System C At 7:37 p.m. on September 24, 1986, Fire Protection Sprinkler System "C" on the 281-foot elevation of the auxiliary building was inadvertently actuated while performing SP 1303-12.13. At the same time, reactor building purge valve AH-V-1B was being exercised and reactor protection system surveillance (SP 1303-4.1) on the "B" channel was in progress. Coincident with the deluge actuation and the above-noted tests, several control room alarms actuated.
The alarms received in the control room were: -- Fire Detectors PLF 1-7 and 1-18 (attributed to the deluged actuation by the licensee; no flow in the RB steam generator fan H&VA 1-10; -- no flow in the RB OP floor "A" supply fan - H&VA -- l core flood tank heat contacts - H&VB 6-3; -- l station battery "1B jround; and, -- high temperature readings from TS 694 H&VA 3-10 -- (the high temperature alarm, H&VA 3-10, could not
be cleared and a wor) *equest was submitted to ' correct the problem), i
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The licensee believes the station battery ground alarm to be due to operational check of AH-V1B, which appar-ently caused a voltage spike. The remaining alarms that were not explained above pass through a common junction box in the area of the sprinkler that actuated. Although they were found dry, small amounts of moisture could have caused the alarms as purported by the licensee.
The deluge actuation occurred because the deluge ' " flapper" valve was apparently open (not checked closed) before un-isolating the section of piping.
The surveillance test that caused valve manipulations was for periodic draining of that section of piping.
The applicable surveillance procedure will be revised to assure checking the position of the actuation (flapper / valve) before pressurizing that section of piping.
The inspector reviewed the licensee's Plant Incident Report (PIR) No. 1-86-10, dated September 29, 1986, on these events. The review of the event was thorough and the above-noted corrective action was appropriate.
Licensee explanations for the alarm actuations were plausible.
The inspector had no additional comments on these events.
2.3 Conclusion In general, the licensee continued to closely monitor power operation problems that could become safety significant.
Examples are: the RB radioactive airborne concentration buildup; No. 3 reactor coolant pump seal leakoff high flow; and, letdown cooler in-leakage. The control rod configuration change was handled well with appropriate concern toward safety.
Overall, event review was sufficiently thorough with appropriate corrective actions specified. However, procedural control problems resurfaced during this period.
The RB aircraft protection door does not appear to be under procedural control in the general operating procedures to assure that the updated FSAR commitment to keep the door closed during operation is properly implemented. As a result of certain hindrances to the satisfactory completion of Engineered Safe-guards Actuation System (ESAS) testing, NRC staff identified poor procedure utilization and control of the applicable complex surveillance test. Although personnel error contributed to failure to reopen a safety related cooling water supply valve, that failure was, in part, due to not using the applicable SP as steps were completed.
The licensee's related plant incident report was oriented toward the personnel performance proble * . . .
Preventive maintenance on the fire doors appears to be effective in resolving door closing problems.
3.
Makeup System Valve Operability 3.1 Scope of Review The inspector conducted a review of the licensee's procedures for maintenance and surveillance testing for the makeup (MU) system valves that are included in the licensee's 10 CFR 50.55a(g) inservice testing (IST) program. This program was submitted to the NRC in a letter, dated July 10, 1984, and was, subsequently, supplemented by a letter from Hukill, GPUN, to Stolz, NRC, dated March 3, 1986.
In a letter, dated October 3, 1986, Stolz to Hukill, the IST program for the second ten year interval was approved with an explanation of the disposition of certain exemptions to the code that were requested by the licensee.
The inspectors review encompassed the effect of certain testing exemptions that were requested for the MU system valves included in the IST program. The inspector reviewed the following documents related to testing and maintenance of MU system valves: -- Surveillance Procedure (SP) 1300-3H, Revision 21, dated August 18, 1986, " Makeup Pump and Valve Functional Tests;" SP 1300-3R, Revision 15, dated September 9,1986 "IST of -- Valves During Shutdown;" SP 1303-11.26, Revision 13, dated March 18, 1986, " Reactor -- Building Isolation, Valve Cycle Test;" and, SP 1303-11.8, Revision 16, dated May 2, 1986, "High -- Pressure Injection."
The inspector also reviewed Drawings C-301-660/661 for MU system valves and various job ticket summaries related to MU system valve maintenance.
3.2 Findings The licensee's IST program for MU system valve as present!v documented is properly established and implemented.
Test
- was accomplished as required and test results reviewed, revealed no major discrepancies in valve operability as evidenced by consistent valve stroke times.
The maintenance records reviewed confirmed that, in general, the MU system valves included in the IST program had experienced few problems. The licensee has also included many of the MU system valves in their motor-operated valve test program to trend partial valve degradation that would not be evidenced by normal preventive maintenance methods. The inspector conducted a walkdown
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of accessible portions of the MU system. A visual inspection of the rubject valves also revealed good material conditions as evidenced by cleanliness, lack of rust / boric acid buildup, and lack of external leakage.
3.3 Testing Frequency and IST Program Exemptions The inspectors review of test requirements for certain valves that were requested by the licensee to be exempt from some provisions of the ASME Section XI test code revealed the following facts. The check valves in the high pressure injec-tion lines to the RCS cold legs are full stroke tested on a refueling outage basis. These valves, MUV-107A-C, MUV-94, 95, 86 A/8, and MUV-220 are now required by NRR to be tested each cold shutdown if the time intervals since the last test exceeds ninety-two days. This is a standard test frequency specified by the ASME XI Code for this type of valve. The licensee will be required to modify their procedures and surveillance schedules for these valves. The NRR safety evaluation for the IST program, which was included in the October 3, 1986, letter also contained many other denials of relief from the ASME Code.
Final disposition of the test frequency for these non-exempted components, MU system valves included, will remain an unresolved item pending licensee revision of procedures and schedule changes to incorporate the non exempted components into the IST program (289/86-17-03).
It should also be noted that those valves listed above were never exempted from testing at the cold shutdown frequency because of previous NRR denials of the licensee's exception requests. Namely, these valves should have been tested during the eddy current outage of March 1986.
However, these valves have continually been in an appeal status by the licensee for which no NRC staff action occurred until October 3, 1986.
The October 3,1986, letter exempted them from cold shutdown testing until the next startup after Cycle 6 refueling.
The inspector noted that the licensee performed poorly in not providing the proper justification for exemptions and/or in not seeking interim relief from performing applicable testing coincident with the appeal process.
4.
High Pressure Injection Safety Function Alignment 4.1 Review The inspector reviewed Operating Procedure (OP) 1104-2, Revision 60, dated September 19,1986, " Makeup and Purification System," to ascertain whether it is in accordance with regulatory requirements and whether its technical adequacy is consistent with desired actions and modes of operation with regard to the system's high prassure injection functio * . . .
As part of this review, the inspectors also examined the following documents: GAI Drawings C-302-660, Revision 12, " Makeup and Purifi- -- cation," and C-301-661, Revision 23, " Makeup and Purifi-cation;" -- TMI-1 Operations Plant Manual, Section B-5, Revision 1, " Makeup and Purification;" and, ANSI N18.7 - 1976, " Administrative Controls and Quality -- Assurance for the Operational Phase of Nuclear Power Plants."
In addition to the above, the inspector, with assistance from an auxiliary operator (AO), verified selected portions of the valve lineup contained in OP 1104-2, " Makeup and Purification System" which pertains to the high pressure injection mode of operation of the makeup and purification system.
The inspector also verified that selected instrument calibration dates were current by reviewing instrumentation history logs maintained by the licensee's Instrumentation and Control Department.
4.2 Findings The inspector determined that the procedure's instructions were compatible with checklist information and provisions for signoffs were evident. Appropriate limitations, precautions, and notes concerning equipment and administrative operability requirements and appropriate technical specification requirements were also incorporated into the procedure. The valve checklist for normal operation and the Piping and Instrument Diagram (P&ID) were compatible and agreed with each other.
During the valve position verification performed by the inspector, with assistance from the A0, no incorrectly positioned valves were identified.
The areas entered by the inspector were maintained in a neat and clean manner.
Necessary radiological controls were in place.
The review of the instrumentation histories yielded no problems with the calibration of the instrumentation associated with the makeup and purification system's high pressure injection mode of operation.
The A0 was knowledgeable on how to correctly check the position of various valves.
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4.3 Conclusion The inspector determined that OP 1104-2, " Makeup and Purifica-tion System," is adequate to control safety-related operations (High Pressure Injection mode of operation) of the makeup and purification system within applicable regulatory requirements.
No adverse conditions were found during this particular review that would affect plant safety.
5.
Reporting / Report Review Program 5.1 Non-Routine Reporting Program The inspector conducted a review of the licensee's non-routine reporting program.
The following aspects of these programs were reviewed: verification of administrative controls for review of -- off-normal events to assure identification of safety-related events; verification of administrative controls for reporting -- safety-related events internally and to the NRC; verification that administrative controls have been -- established to review maintenance and surveillance activities to assure identification of violations of technical specification limiting conditions for operation; verification that administrative controls have been -- established for completion of corrective action related to . safety-related operating events; i verify that the above-mentioned controls include provisions -- for recognition and reporting of 10 CFR Part 21 events; and, verification that responsibilities have been established -- for implementing the above items.
The inspector also verified that administrative controls have been established for review of vendor bulletins and circulars and Licensee Event Reports (LER's), which includes:
requirements for directing applicable documents to appro- -- priate organizations for corrective action and verification of completion; and, establishment of responsibility for accomplishing the above -- tasks.
! , . - - - ,___ _.. _ _ _. _ _. -.., .m- _ ,,, _ _ _ - - - -. _.,. -. _.. _, _,,, ,-.,7._ ._.,.__.m_, _ _ _.,. ~ _m * . . .
The inspector reviewed the following documents and procedures that the licensee has generated that establish the administra-tive controls and delineate responsibilities for the non-routine reporting programs.
5000-ADM-7316.03 (EP-021), Technical Manuals -- Administrative Procedure (AP) 1044, Revision 16. " Event -- Review and Reporting Requirements" 5000-ADM-1291.02, Revision 2, (LP-009), " Safety Reviews" -- 1000-ADM-1291.01, Revision 1, " Procedure for Nuclear Safety -- and Environmental. Impact Review and Approval of Documents" The inspector concluded that administrative controls had been established to promptly review and evaluate off-normal events.
The in place controls were adequate to identify safety-related events that required reporting in accordance with station technical specifications and applicable sections of the Code of Federal Regulations (10 CFR 50.72 and 50.73). With respect to corrective actions noted as a result of the event, the licensee's program does control and track the completion of the noted deficiencies.
In general, the inspector noted the in place program contained adequate provisions to recognize, report, and correct non-routine operating events.
5.2 NRC Information Notice Followup
The inspector conducted a review of the licensee's programs for evaluating Information Notices (IN) that are generated by the Office of Inspection and Enforcement (IE). The licensee maintains an Action Item Tracking System (AITS), which is controlled by 1000-ADM-1216.03, " Regulatory Correspondence Control." This procedure controls the followup of IE IN's, along with other types of regulatory correspondence. When an IE IN is received by the licensee it is assigned an action item number. The IN is assigned to a cognizant engineer in opera-tions, onsite engineering, or maintenance, whose area of expertise most closely relate to the subject of the IN. A written response is prepared and concurred by the appropriate organization.
The inspector review of this area of licensee management revealed that review of IE ins was adequately administered by the licensee. The inspector reviewed the responses to five IE ins that appeared to be applicable to the licensee's equipment. These five IE ins were a sample of approximately 100 notices issued during the last twelve months.
The responses reviewed were generally adequate and addressed the areas of concern in the IE IN. The inspector's review of these five ins is discussed below along with any concerns raised by the inspector as a result of licensee evaluations.
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IN 86-14, Auxiliary Feed Pump Turbine Overspeed Problems - -- This notice informed the licensee of problems with governor speed control of steam-driven auxiliary feed pumps. Water condensing in the lines could cause rapid opening of the turbine governor valve and subsequent steam flow could cause an overspeed of the turbine.
Subsequent delay in bleeding of governor oil pressure would cause a significant delay in re-opening the governor valve.
The licensee responded that their Worthington fly weight governor system would not be subject to the phenomena listed above as there is no oil pressure control. The problem with steam condensation upstream of the governor valve has been resolved by requiring the A0's to blow down the system once each shift.
There has been no history of turbine overspeed failures at TMI-1.
Licensee response and corrective action for this IE IN appeared to be adequate.
IN 85-100 - Rosemont Delta-P Transmitters Setpoint Shift - -- This IN informed licensees of a potential problem with Rosemont delta-P transmitters (1153 series). When subject to pressure changes significantly greater than that used during calibration, the detector may experience a "zero shift" when system pressure increases.
This may cause inaccurate indication depending on system pressures existing at the detector.
The licensee uses Rosemont 1153 series delta-P detectors in several applications at TMI-1.
The most significant of these were OTSG level indicators, MU-tank level, high pressure injection (HPI) line flow transmitters, and reactor coolant pump (RCP) seal injection lines.
All transmitters were evaluated as having acceptable inaccuracies due to "zero shift," except the detectors used in the HPI lines. These detectors were adjusted to indicate correctly at the high pressures experienced during inservice conditions.
It was acknowledged that at lower pressures and lower flow rates there may be significant inaccuracies in the control room indicator. The licensee accomplishes a full flow test of the HPI pumps using these flow transmitters during refueling outage surveillance testing where significantly lower pressures and flow rates will be experienced.
The inspector will evaluate the indication and associated inaccuracies of this indication during the coming refueling outage testing.
This item will remain unresolved pending the outcome of that testing (289/86-17-04).
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IN 85-75 - Incorrect Post-Modification Testing - The IN in- -- formed licensees of potential problems concerning inadequate post-maintenance testing after modifications to systems for environmental qualification upgrades.
The licensee evaluated these concerns and basically stated that for this type of problem, incorrect instrumentation connection to the system that could cause incorrect indications of the system parameters have not occurred at TMI-1.
The evaluation stated that given the method by which modifications are accomplished and the various reviews accomplished, this would not be a concern at TMI-1.
Also, periodic Technical Specification surveillance testing would tend to be a cross-check of instrumentation indication in the systems that are tested. The inspector determined that this review, although brief in nature, addressed the subject. The inspectors periodically review testing accomplished for modi-fication or periodic surveillance testing and have observed no problems of the type described in the IE IN.
IN 85-74 - Station IE Vital Battery Testing and Maintenance -- - This IN informed the licensee of several problems that have occurred as a result of improper battery testing and maintenance.
Examples were improper load testing in accordance with IEEE 450 Standards, pilot cell rotation, vendor instrJctions, and battery charger redundancy.
The licensee evaluation addressed each specific item and adequately addressed the concerns. Battery capacity testing and load duty cycle testing are the subject of a previous unresolved item at TMI-1. The licensee currently is evaluating their long-term battery test program as a result of previous inspector concerns.
IN 85-71 - Interpretation of Containment Integrated Leak Rate -- Testing (ILRT) - This notice informed licensee of problems with the correct evaluation and interpretation of containment leak-rate testing performed in accordance with 10 CFR 50 Appendix J.
The licensee's evaluation revealed that using the guidance pro-vided in the IN the results of their "as-found" 1984 ILRT may be unsatisfactory. This condition would affect the frequency of ILRT testing depending on the results of the ILRT that will be conducted in the 1986/1987 "6R" test (next outage). The licensee revised their current ILRT procedure to flag this fact and cause a re-evaluation of the previous test results. The inspector concluded that this corrective action was satisfactory and this area will be reviewed during the upcoming scheduled RB integrated leakrate tes.-- . .. _ -. - - .... . .* . ..
5.3 Conclusion No specific issues were identified during this period. However, past inspections identified problems with non-routine event.
logging. For licensee internal reports, the program is adequate, but the system is highly dependent on the rigorous implementation by personnel to take the initiative to record details of non-routine events.
< For reports to NRC, the program is adequate and, overall, the licensee is responsive to industry wide problems.
6.
Technical and Safety Review
6.1 Background The second Performance Appraisal Team (PAT II) conducted a programmatic review of the licensee's technical and safety I review program (NRC Inspection Report 50-289/86-14). The resident inspectors worked with team members in this area.
Among other findings in this area, the team found that the licensee apparently failed to implement Technical Specifications (TS) in providing a detailed written safety evaluation (SE) for important-to-safety changes to procedures.
Further, it was ' identified that a new system went into effect September 1, 1986, , and this system provided less written safety evaluations for not ! only the important-to-safety scope but, also, the safety-related scope. The scope of system classification is defined in the NRC-approved licensee Quality Assurance Plan (QAP). Details on the PAT findings will be provided in the PAT report.
As a result of the finding on the new safety review system, the , i resident inspectors initiated a review of procedure change requests (PCR's) and procedure temporary changes as described , below in paragraph 6.5.
i j Further, in light of the potential significance of the PAT II I findings, the resident inspectors continued followup of this
l area after completion of the PAT inspection. Details are provided in the following paragraphs.
Because this followup supplements the PAT review, further followup and enforcement i determination will be coordinated with the followup of PAT II.
6.2 Technical / Safety Review Implementation (Prior to September 1, < 1986) PAT II Team members and the resident inspector reviewed procedure changes and special temporary procedures issued prior to September 1, 1986 to: l l - ,.,,--,,---e- ,,, ,. - _ _ - -... ~,,,, -. - -,,.,. -... -..,,,. - _.,...... _.. . - - - -..,,,, - ~,
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verify that written safety evaluations of changes to -- important-to-safety system procedures were completed as required by TS 6.8.2/6.5.1.12 using the 10 CFR 50.59 criteria; assess the quality of the evaluations appropriate to the -- circumstances of the changes; verify the related Administrative Procedure (AP) 1001A, -- Revision ll, " Procedure Review and Approval" was properly implemented; verify compliance with Administrative Procedures; and, -- 1000-ADM-1291.01, Revision 1, " Procedure for Nuclear Safety and Environmental Impact Review and Approval of Documents."
The procedure change review included randomly selected Procedure Change Requests (PCR) (permanent type changes) and Temporary Change Notices (TCN) (which are generally temporary but could lead to permanent changes).
The issued Special Temporary Procedures (STPs) for 1986 by the operations department were also reviewed.
In general, the licensee properly implemented AP 1001A in light of the numerous changes reviewed by the inspectors.
For the most part, the safety evaluations were adequate and they ranged from short explanations to more detailed explanations on why no unreviewed safety questions existed. These evaluations were appropriate to the circumstances.
Some marginally acceptable safety evaluations were noted and were most likely related to the performance level of the individuals writing or reviewing the SE's and related, in part, to the quality of their training in this area. Overall, the inspector identified no significant safety impact as a result of a poor safety evaluation of changes to a facility procedure.
By this procedure review system (issued prior to September 1, 1986, AP 1001A, Revision 11) a written safety evaluation was required for changes to any important-to-safety (ITS) system procedures. However, this was not always implemented. The licensee's Quality Assurance (QA) Department identified a number of instances where PCR's or TCN's were classified not important-to-safety (NITS) when they changed ITS procedures. This was still an outstanding issue between QA and plant personnel at the close of the PAT II inspection.
The inspectors independently identified the following STP's (essentially new procedures) classified as NITS when they manipulated ITS systems.
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STP No. 1-86-0001, dated January 5,1986, Flushing M'J-V-140, completed January 9,1986 and February 8,1986 _. -. _ _ _ _ _ _ _.. _ _, . _ _ _ _ _ _ _ _ _ _ _ _ _ _
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STP No. 1-86-0010, dated April 8, 1986, "A" 0TSG Portable -- Recirculation Skid Operation (not implemented) STP No. 1-86-0014, dated May 15, 1986, PAT Team Data
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Collection for EF-P-1, completed May 22, 1986 STP No. 1-86-0015, dated May 16, 1986, Dilution of IC
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System to Lower RM-L9 Count Rate (not implemented) STP No. 1-86-0016, dated May 28, 1986, Leakage Test of the -- "B" Waste Gas Decay Tank, completed May 30, 1986 STP No. 1-86-0025, dated September 3, 1986, RC-P-1C Bucket -- Check, completed September 3, 1986 (using the new procedure review system)
- Also noted by PAT II As an example, STP 86-001 dealt with the flushing of a valve in the makeup and purification system and it permitted essentially boron free water to be injected into the RCS for a very short time while the plant was operating.
Further, a "take-down" hose connection (low pressure rating) could have been subject to full RCS pressure if there was a valve misalignment. Overall, the procedure had sufficient precautions and limitations to guard against adverse problems. But, licensee personnel did not subject this new temporary procedure to a 10 CFR 50.59 type analysis. Apparently, AP 1001A was not properly implemented.
As a further example, the STP 86-0014 was classified NITS, and it was intended to resolve a PAT I concern on steam condensation in the steam lines for the emergency feedwater pump (EFP). The applicable surveillance test was used for data collection but special valve manipulations occurred by the STP.
Licensee personnel responded that the classification process for procedure changes was a judgement call permitted by TS and AP's.
The inspector then reviewed the regulatory basis correspondence for License Amendment No. 77, which initiated the licensee's somewhat unique independent technical and safety review process, and discussed the matter with representatives of NRR. Based on this review, the inspector concluded that the classification of new procedures and procedure changes was not optienal. As a management directive, the licensee's "Q" List (ES-011) classifies those systems as ITS, NITS, and nuclear safety related (NSR).
Therefore, new procedures and procedural changes to ITS systems need to be classified ITS and properly evaluated in accordance with TS 6.8.1/6.5.1.12 using the guidelines of 10 CFR 50.59. Accordingly, for the STP's listed above, the lack of a written safety evaluation to support their review and approval is contrary to TS 6.8.2/6.5.1.12 (289/86-17-05).
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The PAT II members and the inspector also noted that several modification control procedures issued by the Technical Functions Division were no longer classified ITS/ NITS /NSR but classified as to whether or not the activity is "Within QA Scope" or " Safety Review Required". The inspector questioned the licensee on why essential modification control procedures would not receive a safety review, especially when these procedures control the imple-mentation of safety-related modifications. Since these procedures come under the scope of TS 6.8.1 and 6.8.2, this represents ad-ditional examples of new procedures not receiving a written safety evaluation during the licensee's review and approval precess. The licensee stated that the QA review is a comparable review.
The in-spector disagreed and noted this to be addition examples of apparent violation of TS 6.8.2/6.5.12.
6.3 Technical / Safety Review Implementation (After September 1, 1986) During the PAT II, the inspectors became aware that a new review and approval system was to be effective September 1, 1986. The inspector reviewed the related corporate and site administrative procedures governing the new system, along with the 10 CFR 50.59 evaluations for the corporate procedure. The procedures were: 1000-ADM-1291.01, Revision 2, effective September 1, 1986, -- " Procedure for Nuclear Safety and Environmental Impact Review and Approval of Documents;" and, AP 1001A, Revision 12, effective September 3,1986, -- " Procedure Review and Approval."
The 1291.01 procedure is corporate based and it applies to safety review for documents related to procedures / procedure changes, modification, and test / experiments. The AP1001A applies to site specific procedure changes.
Exhibit 7 of 1291.01 and Figure 4 of AP 1001A are essentially the same and are similarly titled " Safety / Environmental Determination and 50.59 Review," which will subsequently be referred to as the l " Form 1" (see attachment 1 as an example).
Exhibit 8 of 1291.01 and Figure 5 of AP 1001A are essentially the same and are
similarly titled " Safety Evaluation," which will subsequently be referred to as " Form 2" (see attachment 2 as an example).
i Form 1 is essentially new and Form 2 is essentially the traditional 50.59 analysis with the accompanying written safety evaluation (SE) justifying whether or not an unreviewed safety
question exists.
. The licensee claims that the completion of Form 1 with all negative answers to questions 3 through 6 constitutes a written determination that no unreviewed safety question exists.
, Licensee representatives acknowledge the possibility that certain changes to nuclear safety-related procedures would get
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only a Form 1 completion.
The inspector considered that to adequately answer the "yes/no" questions of Form 1, Form 2 is needed.
Form 2 provided a safety evaluation which (1) addresses the test questions defined in 10 CFR 50.59 for determination of unreviewed safety questions; and, (2) documents the bases for this determination. The inspector stated that the new system does not adequately implement current TS (6.8.2/6.5.1.12) because these TS required a written safety evaluation for ITS changes using the 10 CFR 50.59 criteria. The safety evaluation is essentially embodied in the Form 2 in which it appears would be seldomly used for ITS and NSR changes.
The inspector reviewed the related 10 CFR 50.59 safety evaluation for the procedure revision to 1290.01 that incorporated the new system.
Little analysis was provided in the evaluation on how the new system complied with current TS.
In fact, the inspector noted that the new system would have SE's conducted on a lesser scope than as required by TS. The inspector concluded that the new system should have been presented to the NRC staff in the form of a TS change request.
The licensee did not submit a T5 change request and the related 50.59 SE was inadequate, in part, to assure proper implementation of current TS. Accordingly, this is apparently contrary to 10 CFR 50.59 6(1) (289/86-27-06).
The licensee has initiated a verbal request to discuss this new system with Region I management.
They have tentatively dis-agreed with the above-noted apparent violations.
Region I will be acting upon the licensee's request in conjunction with followup of the PAT II report (when issued) and this report.
6.4 Other Procedure Review Comments An ongoing NRC staff concern over the past year of operations at TMI-1 was individual procedural step inadequacies being apparent in various inspector reviews. Questions were raised on the overall adequacy of the current technical and safety review process to produce better procedures.
During the PAT II review, the following observations were made.
There is a very heavy involvement by middle managers in the -- review process because many of these individuals are signing off responsible technical review (RTR) sections.
Their attention and involvement is noteworthy but the inspector questioned how much time these individuals have, in light of their positions, to do thorough reviews to assure individual step inadequacies are adequately corrected.
The governing procedures (Corporate 1291.01 and Ap 1001A) -- provide little guidance on what constitutes a thorough RTR -
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or ISR review. Only a mandate to do an "in-depth" review exists without further explanation.
Various reviewers have different concepts of what consti- -- tutes an in-cepth review.
The recently introduced terms ' licensing " basis document" are not specifically identified by the licensee, yet RTR's are responsible to be aware and knowledgeable of these documents to incorporate them into their safety evaluations.
The licensee's training program does not appear to compen- -- sate for the weaknesses noted above.
Resident inspector followup during and subsequent to PAT II led to the following additional observations.
There appears to be misuse of the independent review concept -- from within the same division / department (however, this is still in compliance with TS). As an example, the inspector questions why operations department would write, review, and approve new procedures like special temporary procedures without, perhaps, plant engineering department review. Although operations personnel are very knowledgeable of the plant, a more indepen-l dent review outside operations department would seem to be more i beneficial in providing an objective review on the work of personnel who are very close to a problem or production i activity.
Operations or productions pressures may well be a fcetor in -- the quality of review by an individual writer or reviewer, coupled with the lack of guidance on what constitutes an ! "in-depth" review, t . The inspector concluded that any one or a combination of the
above factors seems to have contributed to the procedural step inadequacies noted throughout the year.
The licensee collegial i review initiative appears to be too removed from the specifics , to identify problems with the details. Overall, no significant I safety impact has resulted yet, but the above performance ! factors could lead to a more serious procedural inadequacy.
! This area will continue to be routinely reviewed by Region I.
6.5 Review of Licensee's Procedure Changes [ On a sampling basis, the inspector reviewed Procedure Change ( Requests (PCR's) and Temporary Change Notices (TCN's) to station procedures that were processed during this period.
This review was conducted to ensure that procedure changes being processed j under the licensee's program as described cbove did not have an adverse affect on safe plant operations.
Each sampled PCR or TCN was reviewed for the purpose, content of the change and the L - - - . - - -
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technical merits of the change.
In addition, the inspector I reviewed the changes to ensure that the changes would not cause another approved procedure to conflict with the proposed changes to other procedures.
The inspector reviewed fifty-three generated PCR's and ten TCN's. The changes ranged from minor editorial changes to changes to address APSR's movement.
See section 2.2.3 on APSR's withdrawal.
Within the review, the inspector did not find any changes that would have caused an adverse affect on safety. All PCR's reviewed were properly completed. No inconsistences were noted for any reviewed TCN's or PCR's. However, most of the PCR's reviewed were still being processed under the licensee's old system. All TCN's were processed on the new system. This area will continue to be reviewed on a sampling basis as new PCR's begin to be processed under the new program.
6.6 Conclusion The licensee apparently has failed to comply with existing TS under the previous review process (issued before September 1, 1986). No significant safety impact has resulted because of these failures.
The NRC staff continues to closely monitor procedure changes until the issue is fully discussed in the Regional meeting.
Further, the licensee's new safety review program (issued after September 1,1986) requires written safety evaluations for a lesser scope than that which is apparently required.
7.
Plant Chemistry 7.1 Analytical Procedures Evaluation During the inspection, standard chemical solutions were submitted by the inspector to the Itcensee for analysis. The standard solutions were prepared by a contractor for Region I and were analyzed by the licensee, using normal methods and equipment. The analysis of standards is used to verify the various plant systems with respect to the Technical Specifications and other regulatory requirements.
In addition, the analysis of standards is used to evaluate the licensee's analytical procedures with respect to accuracy and precision.
The results of the standard measurements comparison indicated that three-out-of-fif teen comparisons were in disagreement under the criteria used for comparing results (see paragraph 7.2 below). The boron disagreement was due to sampling error. The ! i
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ammonia disagreement was due to the NRC sample being less than the licensee's lowest standard.
The fluoride disagreement was due to error in the calibration at the low end of the curve.
The inspector observed that analytical procedures utilizing specific ion electrodes had calibration curves that were not statistically fit to the data points but were graphically approximated. This produced errors in the low concentrations of fluoride and ammonia.
The licensee agreed to use a statistical method to draw the calibration curve.
The licensee was using two independent standard solutions for calibration and measurement control. This affords the licensee a means of cross-checking and verifying the integrity of the standard solutions.
The control charts were generated with an acceptance criteria of i 2 sigma and an unacceptable parameter of i 3 sigma. The charts were expressed as percent recovery. The inspector suggested that the control charts be in actual analyses of the standards so that subtle changes in the measurement system may be identified.
The licensee indicated that they will investigate the differences when generating the control charts.
7.2 Capability Test Results Chemical Licensee Ratio Parameter NRC Value Value__ (Lic./NRC) Comparison __ Results in Parts Per Million (ppm) Boron 1014 1 15 1095 1 0.6 1.08 i 0.02 Disagreement 5040 i 130 5004 i 20 0.99 1 0.03 Agreement 3047 i 26 3074 1 0 1.01 1 0.01 Agreement Chemical Licensee Ratio Parameter NRC Value Value__ (Lic./NRC) Comparison __ Results in Parts Per Billion (ppb) Chloride 10.3 i 0.7 9.3 i 0.6 0.90 1 0.03 Agreement (lonChromo-27.7 1 2.8 29.3 2 0.6 1.06 1 0.11 Agreement tograph) 69.7 i 3.0 71.3 i 1.2 1.02 t 0.05 Agreement . - . . .. .
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4 Chemical Licensee Ratio Parameter NRC Value Value_ (Lic./NRC) Comparison _ Results in Parts Per Billion (ppb) Fluoride 48.1 1 2.0 45.0 1 0 0.94 0.04 Agreement (Sp. Ion 149 7.0 140
0.94 1 0.04 Agreement Electrode)
1 2.0
10 0.76 1 0.05 Disagreement Hydrazine 19.3 1 1.6 19.8 1 0.1 1.03 0.09 Agreement 52.4 1 1.3 49.5 0.7 0.94 1 0.03 Agreement 100 1 2.0 97.5 1 2.4 0.98 1 0.03 Agreement Ammonia 119.9 t 3.3 116 1 3.5 0.97 0.04 Agreement (Sp. Ion 356.3 110.6 303.3 1 2.9 0.85 0.03 Disagreement Electrode) 1168 119 1050 5.0 0.90 1 0.05 Agreement NOTE: Criteria for Comparing Analytical Measurements This provides criteria for comparing results of capability tests.
In these criteria the judgement limits are based on the uncertainty of the ratio of the licensee's value to the NRC value.
The following steps are performed.
(1) The ratto of the licensee's value to the NRC value is computed Licensee Value (ratio = NRC Value ); (2) The uncertainty of the ratio is propagated.1 If the absolute value of one minus the ratio is less than or equal to twice the ratio uncertainty, the results are in agreement.
( 1-ratto S 2 uncertainty) 5Z = x, then Szz + Sx2 + s 2 - ~ZT
y y
- (From: Bevington, P. R., Data Reduction and Error Analysis for the Physical Sciences, McGraw-Hill, New York, 1969)
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7.3 Post-Accident Sampling Capability - NUREG-0737: II.B.3 The effectiveness of the licensee's nonradiological post-accident sampling and analytical program was reviewed against NUREG 0737, Task Action Plan Item II.B.3, and the licensee's post-accident procedure N1832, Revision 0.
The inspectors submitted standard chemical solutions to the licensee for the analyses of boron and chloride, using their described methods for post-accident sample analysis.
(a) The system provides for a grab sample analysis of chlorides by a Dionex Ion Chromatograph. The licensee's acceptance criteria for chloride is within 10 percent between 0.5 and 20 ppm and within 0.05 ppm below 0.5 ppm.
The results of the NRC standard showed that the system was adequate. The results are in parts per billion (ppb).
Ratio NRC Values Lic. Values (Lic./NRC) Comparison 289 1 37 231 1 0 0.80 1 0.10 Agreement 449 1 14 439 1 0 0.98 1 0.03 Agreement 644 1 18 597
0.93 1 0.03 Agreement (b) The system provides for a grab sample analysis of boron by the mannitoborate titration procedure, N1904. As the pracedure is written, the lower range of boron concentration that could be analyzed is 500 ppm.
In a letter, dated November 22, 1983, from H. D. Hukill, Director TMI-1, to J. F. Stolz, Chief of Operating Reactors Branch No. 4, Division of Licensing, a commitment was made to purchase a fluoroborate probe for determining boron concentrations at about 25 ppm. The post-accident sample would have to be diluted to minimize personnel exposures and meet G0C 19 specifications. Diluting the sample in order to reduce exposures does compromise the detection capability.
In the evaluation of the licensee's capability of analyzing boron, the NRC inspectors provided the licensee with standards with the lowest boron concentration at about 600 ppm. The results of the NRC standards showed that the system was adequate for the range of boron concentrations tested. The only disagreement was probably due to sampling error. The licensee's acceptance criteria for boron is within i 5 percent above 1000 ppm and i 50 ppm below 1000 ppm. The reported values are in parts per million (ppm).
Using the licensee's acceptance criteria, the compariton results are:
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Ratio NRC Values Lic. Values (Lic./NRC) Comparison 985 i 10 1044 1 7 1.06 0.01 Disagreement 596 1 10 633 i 14 1.06 0.03 Agreement 4870 i 60 5017 1 25 1.03 1 0.01 Agreement The boron measurement system with analytical range capability of 25 to 6000 ppm, as committed to, is unresolved and will be evaluated using NRC standards at a subsequent inspection (289/86-17-07). A response to this item describing what analytical procedure will be used and when the system will be operable is required.
8.
Annual Quality Assurance Program Review The effectiveness of the implementation of the licensee's Quality Assurance (QA) program was assessed by reviewing safety-related activities in the functional areas of procurement; receipt, storage and handling; and, document control and records retention.
8.1 References Three Mile Island (TMI) Nuclear Station Unit No. 1 Administrative Procedure (AP) 1001C, Revision 5, " Drawing Distribution Control;" TMI AP 1064, Revision 2, "TMI-1 Record Management Program;" i GPU Nuclear QA Department, Section Procedures Manual, 6110-QAP-7202-04, Revision 0, "TMI QA Mod /01 Training Requirements" GPU Nuclear QA Department, Section Procedures Manual, 6110-QAP-7215.01, Revision 1, " Administration of Material , Nonconformance Reports and Receipt Deficiency Notices" GPU Nuclear TMI Warehouse Procedure Manual, 7230-ADM-1000.01, Revision 0, "TMI Warehouse Organization Responsibility" , GPU Nuclear TMI Information Management Center Administrative Procedure Manual, 7132-ADM-1211.01, Revision 1, " Record Management System" GPU Nuclear TMI Warehouse Procedure Manual, 7230, ADM-6420.05, Revision 0, "AMMS Receiving Process" GPU Nuclear TMI Warehouse Procedure Manual, 7230-ADM-6430.06, Revision 0, " Warehouse Cleanliness and Housekeeping" > ..
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GPU Nuclear TMI Warehouse Procedure Manual, 7230-ADM-6440-01, Revision 0, " Issuing Program" GPU Nuclear TMI Warehouse Procedure Manual, 7230-ADM-6440.02, Revision 0, " Issuing of Material - M & S (Stock)" GPU Nuclear TMI Warehouse Procedure Manual, 7230-ADM-6470.01, Revision 1, " Shelf Life" GPU Nuclear TMI Warehouse Procedure Manual, 7230-ADM-6480.01, Revision 0, " Preventive Maintenance" Material Management Department Policies and Procedures Manual, 7200-ADM-6200.22, Revision 0, " Purchase Order Control" Interim Material Management Department Policies, MMD-10, Revision 2, "QA Review / Approval of Purchase Orders and Contacts" Material Management Department Policies and Procedures Manual, 7200-ADM-6231.1, Revision 0, " Purchase Requisition Requirements and Format" 8.2 Procurement The licensee has established and implemented Administrative Procedures 7200-ADM-6231.1, 7200-ADM-6200.22, and MMD-10, which delineate the preparation and review of quality related procurement activities.
The Material Management Department (MMD) is responsible for procurement functions; such as, source and bid evaluation, administrative control of purchase orders, and maintaining optimum inventory levels.
The engineering and QA evaluation of suppliers / vendors includes their ability to provide material, equipment, and services that comply with technical, design, manufacturing, and QA requirements.
An approved vendor's list has been established and is periodically updated and controlled by the QA procurement group.
The inspectors reviewed the licensee's procurement process by verifying selected purchase orders (P0's) were consistent with station procurement requests, FSAR commitments, and specification requirements. Also, receiving inspection reports, material issue slips, etc. were reviewed to verify that they reflected established requirements. The following P0's associated with job orders (J0's) that included installation of replacement components / parts were reviewed: l {
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Purchase Order Stock Number Item Job Order 003615 204-021-8500-1 Diaphragm CJ031 40704 843-007-2150-1 Packing CJ068 037065 845-758-0200-1 Needle Assembly CJ068 036547 848-020-2375-1 Washer CJ068 037065 840-815-2110-1 Nutlock CJ068 036065 838-445-3390-1 Gland Packing CJ068 002705 886-940-4500-1 Union CJ117 113990 059-709-3500-H Terminal Block CJ126 019072 878-610-5500-W Heat Shrink Tubing CJ126 007120 773-172-9000-1 Splice CJ126 025628 941-114-3025-H Wire CJ133 010853 854-912-9000-1 Terminals CJ133 003991 Direct Turnover * 0-Rings CJ270 003181 459-007-4500-1 0-Rings CJ270 029980 843-007-1370-1 C-Ring CJ661 229200 459-013-5500-1 0-Ring CJ205 007185 847-021-7320-1 Valve CJ358 23781 957-362-00-12 CRD Motor Switch CG513 002898 204-004-4000-1 Diaphragm CF496 034972 Direct Turnover * Undervoltage Relay CI729 PP-019528 Direct Turnover * Undervoltage Relay A25A-G1450
- Purchased for a specific application and no stock number assigned.
No violations were identified; however, an unresolved item is discussed below.
The in-depth review of corrective maintenance work under JO CJ126 indicated that the electrical repair for RC-4, " Hot Leg Butt Splice" was done using Raychem heat shrink tubing that was purchased by the licensee's Oyster Creek Nuclear Plant (P0 019072). This item was received, inspected, and accepted there on December 11, 1984, and, subsequently, transferred to TMI-1 for the subject work done during April 1986. The licensee was unable to retrieve TMI-1 documentation on the acceptability and traceability (e.g., QC inspection) of this tubing prior to the concicsion of the inspaction. This item is unresolved pending licensee's retrieval of documentation; such as, material requisition, material receipt and inspection, material transfer, etc., for the Raychem heat shrink tubing (289/86-17-08).
8.3 Receipt, Storage, and Handling The inspectors reviewed the licensee's administrative, warehouse, and QA procedures 7230-ADM-1000.01, 7230-ADM-6420.05.
7230-ADM-6430.06, 7230-ADM-6440.01, 7230-ADM-6470.01,
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6110-QAP-7215.01, and 7230-ADM-6480.01. These procedures describe administrative controls, responsibilities, and methodology to conduct receipt inspection, storage, and handling of safety-related items, including shelf life and preventive maintenance, as applicable.
Quality Control (QC) inspectors conduct receipt inspection and discrepancies, if any, are documented on nonconformance reports so that proper evaluation and disposition are accomplished. A number of such reports were reviewed and it was noted that problem resolutions were adequate and timely.
The qualification and certification records of sampled QC inspectors were current and met or exceeded the requirements of ANSI N45.2.6-1978 for their particular assignments. The warehouse was toured to verify implementation of procedures and requirements; such as marking / tagging, segregation of non-conforming and uninspected items, environmental and housekeeping conditions, preventive maintenance, and shelf life provisions.
Preventive maintenance is scheduled and performed on appropriately stored items as evidenced by verification that the following were on the schedule and did receive periodic maintenance.
Item Stock Number , Storage Location Motor 422-501-1000-1 1B11B141 Motor 191-827-9295-1 1813G132 Motor 422-518-4500-1 1E10A010 Operator 842-838-6500-0 1E10A042 Pump 542-058-3900-0 1E10C032 Valve 847-021-1570-1 IF05M030 The storage conditions, identification and shelf life, as applicable, were examined for those items listed above, in paragraph 8.1 and the following.
Purchase Stock Number Item Location Order 847-021-9515-1 Asco Solinoid Valves ID02LO83 43172, 98180 847-021-1610-1 Asco Valves ID02K117 02910 149-016-7000-H Asco Solinoid Coil ID03A211 033226 397-001-1500-1 Asco Rebuild Kits 1002C047 63645 No violations were identified; however, an unresolved item is discussed belo.. . .
Asco valves (Stock Nos. 847-021-1610-1 and 847-021-9515-1) that were purchased " commercial grade" under provisions of 10 CFR 21 were not included in the shelf life program.
These valves contain non-metallic internal parts that are subject to deterioration through aging. Discussions with plant engineers responsible for determining shelf life of such parts, a review of source documents on shelf life provisions, and a. records tracing of valve issuance /use indicated that no valves with overaged parts had been installed.
Rebuild kits for these valves also were not included in the shelf life program.
Although some parts in these kits were overaged, none had been issued for use with such parts.
No safety concern existed because these items were not issued for use in a shelf life expired condition and the other non-metallic parts sampled (see above) were subject to shelf life controls.
When informed of these omissions, licensee management took immediate measures to correct this program weakness.
Licensee representatives stated that the Stores Department will develop a listing (s) of commercial grade Asco valves that are currently in the warehouse. This information will then be provided to plant engineers with a request for an evaluation to determine the shelf life of these valves. Based on the evaluations, these valves will be appropriately incorporated into the shelf life program. Also, the rebuild kits will be included in shelf life controls.
This is an unresolved item pending verification that these actions have been completed in a timely manner (289/86-17-09).
License management verified this commitment during the exit interview.
8.4 Docume * Control and Records Retention AP 1064 delineates requirements and responsibilities for generating, validating,, transferring, storing, handling, and retention of quality-related records.
Each department or activity assigns an individual as the records coordinator to ensure that records are processed as required.
These individuals are responsible for the primary interface with the Information Management Center (IMC) for development and maintenance of document lists and record retention schedules; transmittal of records to the IMC and interface with IMC computer-assisted records information and retrieval system (CARIRS) for record indexing, processing, and training.
Records are microfilmed and film copies are distributed as needed.
The implementation of the CARIRS program was evaluated during the retrieval of the records (e.g., purchase orders, job orders, QC inspections) that were requested (also see paragraphs 8.1, and 8.2).
The records vault was examined and it was noted that it has two separate chambers each with temperature, humidity, and fire l i l
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control devices. Access to the vault is controlled by a list of authorized entrants displayed at the entrance.
The microfilming facility was toured and activities were witnessed.
Procedures and other documents that were utilized and discussed in paragraphs 8.1, 8.2, 8.3, and herein were verified to be current and in the program.
No violations were identified.
8.5 QA/QC Interface The QA organizational responsibilities are delegated to an onsite QA Modification / Operations group and to corporate based QA groups with an onsite audit group that reports to the offsite QA audit group. The QA Modification / Operations group reviews onsite engineering operations and other support activities, including QA monitoring, quality problem trending, receipt inspection, etc. The corporate based QA groups provide vendor surveillance, audits, and program support for onsite QA/QC.
The document review, involvement in the procurement process, audits, inspections, and QA monitoring of activities associated with the areas discussed in paragraphs 8.1, 8.2, and 8.3 indicated an adequate level of QA/QC involvement.
No violations were identified.
8.6 Conclusion The licensee is properly implementing program requirements and , commitments for the above reviewed areas.
9.
Reactor Building Tendon Surveillance Reports 9.1 Introduction - Purpose and Scope This review covers the contractor's report and GPUN's evaluation of the tenth year tendon surveillance for the TMI-1 containment building. This is the fourth in a series after the structural integrity test in 1975. The containment building (reactor building) tendon surveillance program is a systematic means of assessing the quality and structural performance of the post-tensioning system to verify the containment structural integrity.
Tendon surveillance testing consists of sheathing filler inspection, anchorage inspection, tendon liftoff measurement, tendon wire continuity testing, inspection and tensile testing of tendon wire, and tendon retensioning and resealing.
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The tenth year tendon surveillance at TMI-1 began in May 1985 and was' completed June 1985 by INRYCO, Concrete Systems Division of Inland Steel Company.. Tendon surveillance testing was governed by NRC-approved Amendment No. 59, dated October 31, 1980, to the TMI-1 Technical Specifications. The number of tendons randomly selected and scheduled.for this inspection was three dome, five horizontal,.and three vertical, in compliance with the NRC Regulatory Guide 1.35 (proposed Revision 3) and TMI Technical Specification Section 4.4.2.2, " Containment Structural Integrity / Inservice Tendon Surveillance Requirements." Four other tendons were fully inspected in addition to the eleven scheduled for inspection.
Two of these were tested as a result of a commitment from the previous five year surveillance. The other two were tested as a result of low lift-off force on one of the scheduled horizontal tendons. An additional ver-tical tendon was visually inspected to correct an inadequate documen-tation of buttonhead condition during the previous five year inspec- ' tion. -Extra attention was paid to the vertical tendons as a result of corrosion problems found in a similar tendon system at Farley Nuclear Plant, addressed in NRC IE Notice 85-10. The methods for conducting the tendon surveillance by INRYC0 were prescribed by GPUN's detailed SP 1301-9.1 and INRYC0 developed surveillance procedures approved by GPUN.
9.2 The surveillance procedure consisted of the following elements: visual and laboratory examination of sheathing filler -- samples from each of the surveillance tendons; inspection of the anchor assembly and adjacent concrete of -- each of the surveillance tendons for deleterious conditions; such as corrosion, cracks,. missing and broken wires, or off-size buttonheads; measurement of the threads on the anchorages to ensure -- proper strength capacity is met when coupled with a stressing adaptor; -- measurement of the lift-off force for each of the surveillance tendons; removal of a minimum of one wire from one surveillance -- tendon (which had to be detensioned) of each group-(horizontal, dome, and vertical) for examination and testing; -- retensioning of these three surveillance tendons and measuring the corresponding tendon elongation;
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visual, inspection for corrosion, pitting, or any significant -- physical change of wires removed from tendons; testing of wires removed from tendons for yield strength, -- ultimate strength,and total elongation; and, -- evaluation of test and inspection results to assess the general condition of the post-tensioning system.
In addition to the sixteen tendon inspections, nine dome tendon anchorage areas were baseline inspected. GPUN has committed to reinspect these during the next five year surveillance in accordance with TMI's Technical Specification 4.4.2.1.5 to determine if crack growth in the concrete can be detected. This is a followup inspection for the ring girder extensively repaired during the initial construction.
9.3 Contractor Report Summary The INRYC0 two volume report on their investigation of the present condition of the post-tensioning system of the TMI-1 containment building is observed to be complete.
The results of the investigation are discussed in detail in the body of the report.
In summary, the following conclusions are observed and adequately substantiated.
-- The sheathing filler (grease) had acceptable levels of water-soluble ions (chlorides, nitrates, and sulfides) and water.
-- In no case was water found present during removal of a grease can or inside a grease can.
All anchorage components had acceptable corrosion levels -- and no cracks. All buttonheads were found acceptable.
Cracks in the concrete surrounding the bearing plates were within allowable tolerance.
-- The hydraulic jacks used for liftoffs, detensioning, and retensioning tendons, and for breaking wire samples were found to be in a properly calibrated status during the surveillance.
All tendon liftoffs were found acceptable.
-- All wire samples tested were found acceptable in diameter, -- strength, and corrosion levels.
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Those tendons that were detensioned for wire removal were -- retensioned and their elongations and liftoffs were found acceptable. All tendons were resealed and regreased to adequate levels.
A comparison of the findings of this surveillance with the -- original installation revealed that the tendons are experiencing normal force losses. Normal losses consist of tendon wire relaxation and concrete creep resulting from their stressed condition.
Based on the results of the tenth year physical tendon surveillance test reported herein, the conclusion is reached that no abnormal degradation of the containment structure post-tensioning system is indicated for TMI-1.
9.4 GPUN Evaluation Contractor Report A review was performed by GPUN's evaluation of INRYCO's 1985 tendon surveillance investigation of the TMI-1 containment building post-tensioning system. The GPUN evaluation consists of the following: -- tendon wire bundle physical condition; corrosion protection system performance; -- -- condition of anchorage area concrete; -- tendon stress level; anchorage assembly physical condition; -- -- dome tendon anchorage areas baseline inspection; and, , -- vertical tendon extra inspection in reference to NRC IE Notice 85-10, Farley Nuclear Plant corrosion problems.
GPUN provides evaluation of INRYC0 collection of data for each above item, their compliance with the contractor's detailed procedures for the conduct of each test, equipment calibration, and comparison of surveillance test results with the original tendon and tendon assembly installation data. GPUN's overall summary conclusion indicates that the post-tensioning system for the TMI-1 reactor containment building is in good condition, the functional capability of the system has not been diminished, and the system shows no detectable evidence of the occurrence of any deterioration. The test results also indicate that the inspected tendons have maintained an acceptable level of prestressing force fulfilling the design requirements ten years after the structural integrity tes.. . ..
9.5 NRC Findings / Conclusion The NRC inspector concurs with the above conclusion. No violations ' were identified.
10.
Licensee Action on Previous Inspection Findings The inspector reviewed licensee action on previous inspection findings to assure that the licensee took appropriate action, either in response to the findings or by self-initiative, and that those actions were timely.
10.1 (Closed) NRC Bulletin 82-02 (289/82-B0-02): Degradation of Threaded Fastener in the Reactor Coolant System (RCS) Pressure Boundary of PWR Plarits. Degradation of threaded fasteners within the RCS boundary was noted in several nuclear plants.
In IE Bulletin 82-02, the NRC directed five specific actions.
By licensee's letter, dated August 3, 1982, TMI-1 responded to Items 3 and 5.
These two items were reviewed and found accept-able in NRC Inspection Report 50-289/83-22.
The licensee's letter, dated December 5, 1985, responded to the remaining items of the bulletin.
Item 1 required the licensee to develop and implement maintenance procedures where procedures previously did not exist.
Item 2 required inspection of threaded fasteners associated with RCS boundary when the corresponding fastener was removed for scheduled component inspections.
Item 4 required documentation of the examinations performed on the required fasteners.
The inspector reviewed the licensee's final response to IE Bulletin 82-02, plus the previous response.
The inspector compared the licensee's response to the requirements of the bulletin as stated above and found the licensee had adequately addressed the issues as described in the bulletin. The inspector reviewed the response for completeness and concluded the licensee had answered all the questions or complied with all requirements of the bulletin. The required procedures have been implemented.
Documented inspection results were enclosed in their response.
The inspector considered this bulletin closed.
l 10.2 (Closed) NRC Bulletin 83-03 (289/83-BU-03): Check Valve Fail ures in Raw Water Cooling Systems of Diesel Generators. A review of operating experience, data, and License Event Reports (LER's) by the NRC showed numerous check valve failures occur-ring in systems important to safety in nuclear power plants.
In IE Bulletin 83-03, the NRC directed six specific actions associated with this problem be taken by the licensee.
Licensee's letter, dated February 11, 1986, provided the final response to the bulletin for item 5.
The remaining items were previously reviewed in NRC Inspection Report 50-289/83-22.
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Action Item 5 required a report of the initial valve integrity verification for diesel generator check valves.
The inspector reviewed the licensee's submittal addressing Item 5, with no significant problems identified The inspector concluded that the letter adequately addressed this item and considered this bulletin closed.
10.3 Closed) Unresolved Item (289/84-08-02): Technical Basis for Setpoints of Radiation Monitors Used to Isolate Certain Reactor Building (RB) Penetrations. A technical basis for the monitor setpoints (RM-G16 through RM-G21 and RM-L1) to isolate associated RB pipe penetrations was not available at the time of the NRC inspection for modification RM-58. The SDD 642-A, Table 2, listed the setpoints for isolation signals in terms of specific microcuries per cubic centimeter (uCi/cc) in the monitored pipe, but the design basis for these setpoints was not clear in the SDD. The applicable test procedures reflect actual setpoints for the isolation functions of: 1000 millirem per hour (mR/HR) for RMG16-20, 10,000 mR/HR for RM-G21, and 8,000 counts per minute (cpm) for RM-LI.
By the end of that 1984 inspection, licensee representatives could not provide a correlation between these actual setpoints in terms of mR/Hr (general area radiation near pipe) to the SDD setpoints in terms of uC1/cc (radioactive concentration inside the pipe).
The licensee agreed to review this area. As October 3,1986, a ! detailed analysis was still not complete as to purpose, method, assumption, design input, references, and units of the monitor setpoint.
This is contrary to 10 CFR 50 Appendix B, QAP Appendix C, and ANSI 45.2.11, paragraph 4.2 (289/86-17-10).
Since the above issue was not resolved by October 3, 1986, it also represents another example of licensee's failure to take prompt corrective action on a condition adverse to quality, an issue for which the licensee was previously cited (NRC Inspec-tion Report 50-289/86-12).
10.4 (Closed) Unresolved Item (289/85-19-01): Steam Generator Primary-to-Secondary Leakrate Shutdown Limit. The inspector previously noted that the licensee's procedure (Surveillance Procedure 1301-1) lacked specificity of licensee's actions upon an indication of primary-to-secondary leakage in excess of 6 gallons per hours (gph) above baseline (0.1 gph). Also, it was noted that operations would be permitted for up to 72 hours with leakage between 6 and 12 gph.
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In response to this concern, the licensee committed to review SP 1301-1 for technical adequacy. The inspector reviewed the existing procedure on September 29, 1986, and found that the procedure had not been changed. At the exit interview on October 3, 1986, the inspector noted that the licensee had not been responsive in updating the procedure with respect to current test information.
The Director of TMI-1 committed to change the procedure within two weeks. The licensee subsequently performed the review and revised the procedure on October 9, 1986.
The inspector reviewed Revision 64 to SP 1301-1 to determine that the change was reasonably consistent with the intent of the license condition (2.c.8.(2)). The licensee now imposes a requirement to validate within 24 hours test results indicating primary-to-secondary leakage of 6 gph above baseline. This would alleviate any unnecessary transients on the plant and it reasonably meets the intent of the license condition to shut down the plant with abnormal leakage (defined by license condition to be 6 gph above baseline).
The inspector concluded that the change to the procedure adequately addressed the original concern and is consistent with the intent of the applicable license condition.
10.5 (Open) Unresolved (289/85-27-08 and TMI TAP I.C.6): Independent Verification of Equipment Control Measures. By 14RC letter, dated January 9, 1986, the licensee was to describe in detail their commitments to implement the guidelines of TMI TAP Item I.C.6, " Guidance on Procedures for Verifying Correct Performance of Operating Activities." This request was made because the accompanying NRC Inspection Report identified that the licensee was implementing measures that apply to less than full scope of safety-related equipment. The program was somewhat consistent with the TMI-1 restart hearing commitments, but related restart hearing correspondence and documentation was also confusing in terms of the scope of equipment that would have independent verification measures applied.
During this inspection period, the inspector reviewed the licensee's response letter, dated April 29, 1986. The licensee's letter described the originally approved program as " basically sound and well conceived" and the attachment to the letter was "not intended to replace our previous program description; it is intended only to describe our review process." The scope of expansion of the program centered around the containment integrity checklist and EFW alignment, since this system was not yet fully safety grade.
Further, a major (critical) components list within a subset of full safety-related scope would be issued January 31, 1987. Also the element
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Nos. (2) and (4) of TMI TAP I.C.6, dealing with authority to release equipment and notification of control room operators, were not addressed. The inspector determined that the licensee's letter did not fully satisfy the NRC Region I request for a complete description of their program to satisfy TAP Item I.C.6.
The inspector concluded that the letter was not completely responsive to the NRC staff's concern; therefore, an additional licensee submittal will be needed before NRC Region I can complete its review of this item.
jp The licensee acknowledged the above but, also, stated that many of the inspector's concerns would be addressed by a draft administrative procedure (tentatively designated AP 1067) that, among other program elements, would promulgate the component list described above.
The inspector reviewed the draft AP 1067, and he observed some of the concerns would be resolved upon issuance of the AP. However, the inspector also noted that now the AP is somewhat inconsistent with the licensee's program description as provided in the April 29, 1986, letter.
The inspector's residual concerns are addressed below.
(1) Maintenance and Surveillance Testing TAP I.C.6 (1) expands the scope of equipment control measures to include surveillance testing in addition to maintenance. The licensee's program description (I.B.(2) of Attachment I to licensee's letter, dated April 29,1986) includes the surveillance testing aspects.
However, the equipment control measures affected by the independent verification program are not identified -- these should be included, at least by reference, to applicable administra-tive procedures. The equipment control measures that should be addressed are component tagging (all types - red, yellow, blue) temporary modifications; such as, lifted leads, jumpers, mechanical modifications; startup from outage valve lineups; and, restoration to normal from maintenance and/or surveillance testing.
Further, the licensee states that independent verification would not be done for equipment taken out of service for only a brief time and no other activities take place which could affect operability. An example given is putting a component in pull-to-lock for oil sampling.
The inspector questions the definition of a brief time in light of potential shift turnover problems.
(The brief time should not exceed a shift and licensee representatives were agreeable to that definition.) Independent verification would also have to be accomplished as an additional measure of safety and should be documented perhaps, at least, in a - - - - -, _, . -. _
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48 control room log.
It is not acceptable to completely waive independent verification even for such simple tasks.
The licensee's program needs to address these aspects.
(2) Authority to Release Equipment TMI TAP I.C.6 (2) provides guidance on the acceptance of delegating equipment release authority to an onshift senior reactor operator (SRO), but the shift supervisor (SS) is to be kept fully informed.
This element is not addressed in the licensee's programmatic description.
It appears though that the element is in place in several AP's.
The licensee should provide a description (or by reference) of these release authority provisions in the program description.
(3) Second Qualified Person and Significant Radiation Exposure TMI TAP I.C.6 (3) recommends that a second qualified individual should verify correct implementation of equip-ment control measures.
The licensee's letter does not describe how this is to be implemented. The draft AP 1067 is consolidating the measures and providing good guidance on how the verification is to be accomplished and also addresses radiological concerns. A summary of the measures should be provided in the program description (or AP procedural requirements included in the program descrip-tion).
(4) Changes in Equipment Status TMI TAP I.C.6 (4) provides guidance that control room operators be informed on equipment status changes and effects of such change. Although apparently discussed in Administrative Procedures, this is not addressed in the licensee program description.
(It does appear to be adequately covered by various Administration Procedures, but the licensee should review their AP's to confirm this.)
(5) Independent Verification TMI TAP I.C.6 (5) provides guidance that the independent verification by a second qualified operator be accomplished on return to service of equipment important to safety unless functional testing can prove proper functional alignment.
For the most part, the licensee addresses this essential element of their program, but several questions remain on the adequacy of that coverage with respect to safety-related scope and on how extensive the outage valve lineup independent verifications will b c.
.
First, the licensee's response letter divides the safety-related scope of systems into five categories: (1) Passive Structures, Systems, and Components; (2) Support Systems for Which the Risk / Consequences are not Significant; (3) Systems Monitored During Normal Operation; (4) Electrical Equipment (grouped with the system it supports); and, (5) Actuated Accident-Mitigating Systems for Which Additional Assurance of Availability is Necessary.
Essentially, the licensee's program description applies independent verification only to the Group (5) systems noted above, which appears to be related to the licensee's critical valve definition. Group (3) is not independent verified because they are monitored extensively during normal operations.
The licensee considered independent verification of the remaining (essentially support) systems would not be appropriate.
The inspector concluded that the licensee provided insufficient justification to eliminate Groups (1) to (4) from the indepen-dent verification. This makes the licensee's definition of critical valves (Group 5) suspect. The missile door for the reactor building (RB) (Group 1) (see paragraph 2.1.2) is an example of apparently not providing an equipment control measure, along with independent verification, to implement an assumption in the Final Safety Analysis Report. The restoration to normal from a waste gas release [ Group (2)] is another example where additional independent verification measures would be appropriate.
Upon review of the draft AP 1067, the inspector found that the enclosure provided a listing of critical valves in nuclear safety-related and a very limited important-to-safety system scope to be independently verified. The inspector concluded that the draft AP is inconsistent with the licensee's program description.
The licensee did not appear willing to commit to the expanded scope of AP 1067 in their program description to > I.C.6.
The adequacy of selective safety-related/important-to-safety components inclusion into the independent verification program will be reviewed by Region I.
A detailed technical re-view of AP 1067 will be conducted upon review and approval by the licensee.
It is essential that the licensee include an ex-panded scope of AP 1067 into their program description.
Related to the scope of equipment control measures, the licensee does not include an independent verification of system align-ments coming out of an outage. The draft AP 1067 includes independent verification requirements only for the components listed in the enclosure to AP 1067. The program description in
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50 . the licensee letter should be made consistent with the AP 1'067 methodology. The completeness of the critical valve line up for which independent verification is to be applied will be further reviewed by Region I as noted above.
, In order to resolve this. issue, the licensee will need to describe more fully how they meet TAP I.C.6 when addressing the elements.noted above. The critical valve listing of draft AP 1067 needs additional clarification but it should be implemented e and independent of Region I's review for adequacy of the licensee methodology to independently verify a subset of . ' safety-related equipment. This item remains open.
j . , 10.6.(0 pen) Violation (289/86-06-01): Failure to Properly' Implement Facility Procedures. The licensee responded to this violation . ' in letters, dated August 11 and 26, 1986. With regard to Items 2 (SR0 leaving the control room above 200 F) and 3 (reactor i coolant bleed tank valve mis positioning), the licensee ac- !. knowledged the violation and conducted appropriate corrective actions.
The licensee attributes these failures to communica-tion / coordination problems. As a result, a confidential
internal memorandum, dated April 30, 1986, to shift supervisors j from.the Plant Operations Director was issued and discussed with shift supervisors, who were reminded of their overall command ' and control responsibilities. The memorandum was also reviewed and approved by the Operations and Maintenance Director and the Director of TMI-1.
Further, all operating crews were briefed by September 15, 1986, on internal-operation memorandum, dated August 11, 1986, from
the Plant Operations Director, and this memorandum promulgated the j.
notice of violation issued with the inspection report.
, ' I The effectiveness of these measures will be closely reviewed by
the NRC Resident Office, especially during significant changes in plant operational modes; such as, during the upcoming entry
into cold shutdown conditions for the refueling outage (November 1, ' 1986).
I The licensee disagreed that Item 1 of the violation was a r failure to follow procedures. The item dealt with operator failure to stop a waste gas tank release when the associated effluent release monitor reached and exceeded the first alarm (alert) setpoint, which was contrary to the related alarm , response procedures. The licensee asserts that the shift + supervisor made a conscious decision not to follow the alarm - response procedure because of his own mental evaluation of the i significance and that the instrument reading stayed only
slightly above the setpoint and that there were no other i ' abnormal symptoms. The licensee claims that these actions were in accordance with AP 1001G, " Procedure Utilization," which ! i.
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permits the operator some flexibility in responding to alarm procedures to cover situations where other actions are not necessary; such as, alarms coming in a calibration testing.
The licensee response referenced AP 1001G. This section of AP 1001G states: " Response to Alarm Procedures shall be followed to the degree appropriate.
Due to the wide variety of responses and the varying degree of detail in these procedures, the need to consult the procedure depends on the nature of the alarm. Some alarms are indications of normal or expected conditions.
Some other alarms are due to instrument malfunctions (nuisance alarms) as determined by their repeated occurrence while appropriate parameter indications suggest no valid reason for the alarm.
These alarms may be bypassed provided operating parameters associated with the alarm are monitored with increased frequency and an Out-of-Service sticker is placed on the alarm window if the condition has not been corrected before shift turnover."
In response to the TMI-1 accident violations, the NRC staff has previously accepted the guidance quoted above as consistent with NRC regulations. Accordingly, the procedural action would not have to be taken if the alarm indicates a normal, expected condition or instrument malfunction. Since the radiation release permit expected a count rate less than the alert setpoint, the inspector concluded that it was unexpected and the alarm response procedure should have been followed; namely, shutdown the release and evaluate the condition. There was a problem to be corrected; that is, the first alarm setting was too low.
The licensee's position with respect to alarm procedure adherence does not provide sufficient assurance that a conservative approach will be taken in responding to plant annunciators. Accordingly, the licensee will be requested to respond further in terms of providing specific corrective actions and measures to prevent recurrence.
10.7 (Closed) Unresolved Item 289/86-06-02}: Inoperable Channel of Nuclear Source Range Instrumentation. The 10 CFR 50.59(b) requires, in part, licensee perform a written safety evaluation to assure that changes in the facility, as described in the SAR, do not involve an unreviewed safety question (defined by 10 CFR 50.59a(2). To implement this requirement, the licensee has AP 1021, Revision 2, dated November 27, 1984, " Plant Engineering Modification," (paragraph 3.2.2) Technical Functions (TF) Engineering Procedure (EP)-016, Revision 1-00, dated January 18, 1985, " Nuclear Safety / Environmental Impact Evaluation." In Exhibit 3, EP-016, paragraph 3.3, requires, in part, that the
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4 written safety evaluation for facility changes describe how the proposed change will or will not affect the safety function by addressing: system performance (paragraph 3.3.1).
The licensee apparently failed to meet these requirements as noted below.
Prior to and during the reactor coolant system deboration to critical activity on April 21 and 22, 1986, one of two channels of source range instrumentation (NI-1) was made inoperable by changing the high voltage power supply cable connector at-reactor building penetration No. 202E. This was accomplished in accordance with a controlled (but outdated) drawing and without a proper evaluation on system performance.
This represents an example of an apparent violation of 10 CFR 50.59(b); AP 1020, paragraph 3.2.2; and, EP-016, Exhibit 3, paragraph 3.3.1 as described above (289/86-17-11), 10.8 (Closed) Deviation (289/86-06-04: Failure to Retrain Supervisory t Personnel in Radwaste Operations. A notice of deviation was issued to the licensee for failure to retrain radwaste supervisory personnel on a two year frequency as committed in an October 8, 1979, response to IE Bulletin 79-19. One supervisor had exceeded the two year maxi-mum interval by approximately two additional years.
The licensee revised their Radwaste Supervisor Training Program Procedure No.
6210-ADM-2622.01 to require that the training division notify the
Supervisor, Waste Disposal in writing at the beginning of each quarter of all personnel who will reach their retraining requirement during that quarter. The inspector reviewed the procedure change and determined-that the licensee had adequately completed corrective action for this deviation. Additionally, the supervisor ' successfully completed retraining on May 9, 1986.
10.9 Summary In summary, the licensee was slow to effectively resolve the , issues on the steam generator primary-to-secondary leakrate procedure and the independent verification program (IVP). The i licensee was not completely responsive to the NRC staff's request on how the IVP met TMI TAP I.C.6 apparently due to misunderstanding the staff's letter. The licensee needs to completely address how they implement TAP I.C.6 and resolve i discrepancies between the licensee's program description and the licensee's draft administrative procedures.
Region I will continue to review the scope of equipment to be independently verified.
, l The licensee's response to the failure to follow procedures ' violation was acceptable, in part. With respect to the proper use of alarm response procedures, the licensee response is unacceptable for which the licensee will have to submit a supplemental response.
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The licensee is responsive to followup on industry wide problems as noted on various actions taken from vendor bulletins and NRC staff information notices. There appears to be an effective tracking system for a number of outstanding old NRC Bulletin actions that were completed this year in accordance with commitments made and accepted by NRC staff.
As a result of this review, the inspector concluded that the licensee's actions for the most part were timely and appropriate for the circumstances, excepted as noted above.
11. Exit Interview The inspectors discussed the inspection scope and findings with the licensee management at a final exit interview conducted October 3, 1986.
Interim exits occurred on September 26, 1986 (plant chemistry) and September 30, 1986 (plant operations). Senior licensee personnel attending the final exit meeting included the following: J. Colitz, Plant Engineering Director, TMI-1 H. Hukill, Director, TMI-1 C. Incorvati, TMI-1 Audit Supervisor, Nuclear Assurance M. Nelson, Safety Review Manager, TMI-1 M. Ross, Plant Operations Director, TMI-1 C. Smyth, TMI-1 Licensing Manager M. Snyder, Preventive Maintenance Manager, TMI-1 R. Toole, Operations and Maintenance Director, TMI-1 A representative of the Commonwealth of Pennsylvania, Ajit Bhattacharyya, also attended the interim exit of September 30, 1986.
The inspection results as discussed at the meeting, are summarized in the cover page of the inspection report.
Licensee representatives indicated that none of the subjects discussed contained proprietary or safegucrds information.
Unresolved Items are matters about which information is required in order to ascertain whether they are acceptable, violations, or deviations.
Unresolved items discussed during the exit meeting are addressed in paragraphs 3, 7, 8, 10.
Inspector Follow Items are significant open issues warranting followup by the inspector at a later time to determine if it is acceptable, unresolved, a violation, or a deviation.
Inspector follow items discussed during the exit meeting are addressed in paragraphs 5 and 1 a 1,1.' ATTACHMENT 1 e,. , (IR 86-17) . ~ Nuslear
GPU Nuclear Corporate Number
Policy and Procedure Manual 1000-ADM-1291.01 \\ Title Procedure for Nuclear Safety and Environmental Impact Revision No.
T Review and Approval of Documents
, EXHIBIT 7 tuclear < SAFETY / ENVIRONMENTAL DETERMINATION AND 50.59 REVIEW o mew = c.v.s.o.vua.: g or % l l ooccerie T.no - Th s Determination (or equrvaient) is recuired for all documents in SecDons I and il of the Matnces in Corporate Procedure 1000ADM-1291.01: 1.
Is this document type listed on the Matnx? Cyes CNo if the answer to question 1 is yes. proceed to answer question 2. If the answer to cuesten 1 is no. then Pro-cedure 1000 ADM-129101 is not acphcaele. No documentaten is recuireo. Refer to Secton 415 for further .nformacon and guidance.
2.
Is this a substanuve revision to the occument? For examples of non-substaatve revisions. refer to Secton 21 Yes CNo if the answer to question 2 is yes. then Procedure 1000-ADM 1291.01 is applicable. Proceed to answer ques-tions 3 througn 7 and perform the Safety / Environmental Determination and 50.59 Review to determine the ex-
tent of procedure apphcacility and to assess the need for a wntten sa'aty evaluaticn. If the answer to ques-non 2 is no, then Procedure 100040M-129101 is not aconicable and documentation of tnis decision is not )' required.
1 Does :nis document have the potential to adversety affect nuctear safety or safe plant operations? Refer to Section 4 2.
Cyes INo 4.
Does the document or change require revisen of the system / component desenption in the FSAR or otherwise require revision of the Tecnnical Spectficanons or any otner Uconsing Basis Document? Cyes CNo i Does the document or change recuire revisen of any procedural or ocerating description in the FSAR. or , ' otrerwise require revision of the Technical Spect'ic4tions or any otner Ucensing Bas:s Occument? ZYes INo ( & Are tests or expenments conducted whicM are not desented in the FSAR, the Technical Specificatens. or any other Ucensing Bas s Document? !Yes CNo ) 7.
Does this document involve any potential environmental impact? Refer to Seccon 14.
Cyes INo _.. If any of the answers to quescons 14.1 OR 6 are yes. proceed to EXHIBIT 8 and prepare a wntion safety evaluaton. If the answers to 14. 5. AND 6 are no. this precludes the occurrence of an Unreviewed Safety ouest on or Technecal Soecifications enange. If the answer to cuesten 7 is yes. or if in douet. forward the document to the Radiological and Environmental Cont ets Division or to Environmentat Lcensing for detailed evaluanon.
signeruree Dates Posamr Sesoa **anager moscar.o.a.e Tecnn.cai mee.er - L .- omerm en an , AXC224s 24e 1520K E7-1 INFORMATION ONLY - _ - .
f (,, ', ATTACHMENT 2 (IR 86-17) - ~ Nuslear A rGPU Nuclear Corporate Number . Policy and Procedure Manual 1000-ADM-1291.01 ) Title Procedure for Nuclear Safety and Environmental Impact Revision No.
Review and Approval of Documents
EXHIBIT 8 > Nuclear SAFETY EVALUATION r - - un.
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< The purpose of this Safety Evaluaten is to provide me basis for cetermineg whomer mis document or enange inese an unreviewed Safcy ouemen or impacts on nucioar safcy.
The Aallowing questons must be answered and reason (s) for each answer must De orovided. A simple statement of conclusaon in itsett is not sufficient. The scope and cootn of each reason snould be commensurate anth the safety segnincance and complex @ of the proposed cnange.
t.
fs the margin of safety as defined in Ucensing Basis Documents other than the Technical SpecificaDons reduced? Cyes CNo 2.
Will impiomontabon of the document adversety af'oct nuclear safety? Cyes ZNo The following quespons compnse the 5039 consicerations and evaluation to determine if an Unreviewed Safcy ouesten exists:
is the probabdity of occurrence or the consequences of an accicent or malfuncnon of equipment important to safety previously evaluated in the Safety Analysis Report increasoc7 ~Yes CNo . 4.
is the possabdity for an accident or malfuncuon of a different type man any evaluated previously in the Safet l Analysis Report created? Cyes ZNo i is the margin of safety as denned in the basis for any Technical Specif! canon reduced? Cyes ZNo Reasons for answers above (This consatutes a wntten safety evaluaten. Use additional sheets if necessary$ if any answer ateve is "yes". an impact on nuctear safety or an Unroviewed Safety ouesnon exists. Revise or redesegn, or forward to Lcensing with any accational documentacon to support a request for NRC approval pnor mem-e_g _ -
==- .. g...i - i . s wi w "- - %.m ":, IRS 4SFIO.4 %."i.___ ,' comer _ _., e __ 152M E8-1 INFORMATION ONLY . . . -. _ _ - - _ _ - -. }}