ML20235Y150

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Insp Repts 50-327/87-30 & 50-328/87-30 on 870506-0612. Violations Noted.Major Areas Inspected:Operational Safety Verification,Maint Observations,Previous Insp Findings, Followup of Events & IE Info Notices
ML20235Y150
Person / Time
Site: Sequoyah  Tennessee Valley Authority icon.png
Issue date: 07/13/1987
From: Jenison K, Mccoy F
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), NRC OFFICE OF SPECIAL PROJECTS
To:
Shared Package
ML20235Y130 List:
References
50-327-87-30, 50-328-87-30, IEB-78-07, IEB-78-7, IEB-82-03, IEB-82-3, IEB-83-02, IEB-83-2, IEB-84-01, IEB-84-1, NUDOCS 8707250118
Download: ML20235Y150 (58)


See also: IR 05000327/1987030

Text

{{#Wiki_filter:_ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - - UallT ED STATES DP REoof [[4'. n NUCLEAR REGULATORY COMMISSION o REGloN il g ~,j 101 MARIETTA STRE ET, N.W.

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t ATLANTA, GEORGI A 30323 %...../ ' Report Nos.: 50-327/87-30, 50-328/87-30 Licensee: Tennessee Valley Authority 500A Chestnut Street Chattanooga, TN 37401 Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77 and DPR-79 Facility Name: Sequoyah Units 1 and 2 Inspection Conducted: May 6, 1987 thru June 12, 1987 7//3/f-7 Lead Inspector: / K. M."Jenison, SenioV R'esident Inspector D' ate' Signed Accompanying Personnel: P. E. Harmon, Resident Inspector D. P. Loveless, Resident Inspector W. K. Poertner, Resident Inspector M. W. Branch, Sequoyah Restart Coordinator . B. Brady Project Engineer Approved by: 7/$/p~7 F. R. WcCoy, Ch'iefMojects Section 1 D6t( Signed Division of TVA Projects SUMMARY Scope: This routine, announced inspection involved inspection onsite by the resident inspectors in the areas of: -operational safety verification (includinC operations performance, system lineups, radiation protection, safeguards and housekeeping inspections); maintenance observations; review of previous inspection findings; followup of events; review of licensee identified items; review of IE Information Notices; and review of inspector followup items. The inspection also involved special reviews of licensee groups performing safety review. functions, the Sequoyah restart testing program and functional testing. - Results: Three violations were identified: 327,328/87-30-01; Failure to control plant activities - (paragraphs 9.b and c, and 15.o,q, and s) 327,328/87-30-02; Failure of the Nuclear Safety Review Board to perform its review function as specified in TS - (paragraph 12.e) 327,328/87-30-07; Failure to establish and implement procedures - (paragraphs 15.d, w, and x) Eight unresolved items were identified: 8707250339 g79,g9 $DR ADOCK 050003g7 PDR __ ______ - __ -

__ _ _ _ - _ _ _ - _ - _ _ _ _ _ l l' l' 2 l l 327,328/87-30-03; Reactor coolant system sight glass design - (paragraph 9 a) 327,328/87-30-04; Technical Specification bases change - (paragraph 12.e) . 327,328/87-30-05; Test personnel training _- (paragraph 13.c)- ' 327,328/87-30-06; Diesel generator circuit cards - (paragraph 15.c) 327,328/87-30-08; Heatup and cooldown rate limits -(paragraph 14.b) 327,328/87-30-09; Component cooling water system baffle testing - (paragraph 15.k) 327,328/87-30-10; Auxiliary feedwater pump flowrate - (paragraph 14.a) 327,328/87-30-11; Recovery verification of diesel generator air tank pressure - (paragraph 15.s) i

- - _ _ _ _ _ _ _ _ _ _ - _ ._ _ ___ REPORT DETAILS 1. Licensee Employees Contacted H. L. Abercrombie, Site Director J. T. La Point, Depucy Site Director

  • L. M. Nobles, Plant Manager

,

  • B. M. Willis, Operations and Engineering Superintendent

j

  • B. M. Patterson, Maintenance Superintendent

' R. J. Prince, Radiological Control Superintendent

  • M. R. Harding, Licensing Group Manager
  • L. E. Martin, Site Quality Manager

D. W. Wilson, Project Engineer R. W. Olson, Modifications Branch Manager J. M. Anthony, Operations Group Supervisor --

  • R. V. Pierce, Mechanical Maintenance Supervisor

M. A. Scarzinski, Electrical Maintenance Supervisor

  • H. D. Elkins, Instrument Maintenance Group Manager

R. S. Kaplan, Site Security Manager J. T. Crittenden, Public Safety Service Chief

  • R. W. Fortenberry, Technical Support Supervisor
  • G. B. Kirk, Compliance Supervisor
  • D. C. Craven, Quality Assurance Staff Supervisor
  • J. H. Sullivan, Regulatory Engineering Supervisor
  • J. L. Hamilton, Quality Engineering Manager
  • D. L. Cowart, Quality Engineering Supervisor
  • H. R. Rogers, Plant Operations Review Staff
  • R. H.'Buchholz, Sequoyah Site Representative

l

  • M. A. Cooper, Compliance Licensing Engineer

j Other licensee employees contacted included technicians, operators, shift f engineers, security force members, engineers and maintenance personnel.

  • Attended exit interview.

2. Exit Interview The inspection scope and findings were summarized with the Plant Manager and members of his staff on June 12, 1986. Three violations described in this report's Summary paragraph were discussed. No deviations were discussed. The licensee acknowledged t.he inspection findings. The

licensee did not identify as proprietary any of the material reviewed by the inspectors during this inspection. During the reporting period, frequent discussions were held with the Site Director, Plant Manager and other managers concerning inspection findings. 3. Licensee Action on Previous Inspection Findings (92702) l (Closed) Violation (VIO) 327,328/85-16-01; Inadequate Radiation Monitor Testing. This violation involved an example of an inadequately written _ _ _ - _ - - _ - - - _ - - - - u

- - _ - - _ _ _ - _ _ _ - - _ _ . __ _ - _ _ _ _ _ _ - _ _ _- - _ _ _ _ _ _ _ _ _______ ____ ._ __ ._ _ _ _ _ _ _ _ _ - _ _ - - __ __-_ __ 2 procedure and~a failure to adhere to the requirements of a procedure. The inspector reviewed the licensee's corrective actions as described in TVA letter (Domer/ Grace) dated July 3, 1985. This item is closed for the specific items identified in the violation. However, the generic surveillance review issue will be addressed in the resolution of Unresolved Item (URI) 327,328/86-60-10. This item is closed. (Closed) URI 327,328/87-02-07; Reactor Coolant System (RCS) Spills. This unresolved item is closed and VIO 327,328/87-30-01 opened to address the issues identified in paragraph 9 of this report. (Closed) VIO 328/83-26-01; Unit 2 Changed Modes With Acoustic Monitors Inoperable. Inspection Report 85-23 reviewed the corrective actions taken to avoid future occurrences, and found then satisfactory. The item was left open because the Technical Specifications (TS) tmendment was still under review by the NRC. On January 25, 1986, Amendment No. 35 was issued > to License No. DPR-79 for Unit 2 requiring the acoustic monitors be operable in modes 1-3. This item is closed. (0 pen) VIO 327/82-25-01; Two Emergency Gas Treatment System (EGTS) Cleanup Subsystems Not Maintained Operable. Violation 82-25-01 was written to derive corrective action for a violation of TS 3.6.1.8 requiring that two independent EGTS cleanup subsystems be operable in modes 1, 2, 3 and 4. , ! On September 11, 1982, the Unit 1 elevation 690 annulus door was left open and obstructed by test equipment when the unit was in mode 3, thus making both trains of EGTS inoperable. This was documented in inspection report 82-25 dated November 30, 1982. According to the cover letter of report 82-25, NRC Region II staff reviewed a licensee analysis of the potential radiological consequences of the violation in determining the severity level of the violation. In that the potential impact on the public health and safety was determined to be minimal, no escalated enforcement action was considered at the time. The licensee utilized a source term (potential release for LOCA) decay time of 18 hours and 15 minutes in performing the evaluation. Using this number they determined that the LOCA dose in this configuration (EGTS inoperable) would have been 240 rem to the thyroid at the exclusion area boundary. This number is below the 300 rem limit in 10 CFR 100; however, it.is well above the 32 rem that was published in the March 1979 SER for the full power design basis LOCA. During the inspector's review of this item for closure, and in consideration of LER 82-107 the inspector noted that the decay time addressed above was calculated from the time of shutdown at , 0345 hours until the time of discovery at 2200 hours. This time is not conservative in that the door could have been opened and breached within ! minutes of work approval at 1715 hours. Although the LC0 time frame may be considered from the time of discovery, a review of safety significance must utilize the more conservative number. J The sensitivity of decay time on part 100 limit calculations has been shown to be very significant. In addition, a review of FSAR calculations compared to SER numbers shows that licensee evaluations are typically less C - . - . . _ . - -- - _ _ _ _ _ _ _ _ _

__ __ __ _ _ _ _ ____ -____ __- -- _ - _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ 3 ! conservative than NRC reviews even when the same basic assumptions are taken. The inspector requested the TVA Site Licensing Group Manager to reevaluate those release calculations generated by TVA in response to the Violation. The adequacy of these calculations was discussed with the Site Director, Plant Manager and others. TVA was requested to perform the re-evaluation utilizing the most conservative decay time that is' applicable to the inoperability of the EGTS on September 11, 1982. The re-evaluation should be completed within 30 days of the receipt of this report. Violation 82-25-01 remains open pending this re-evaluation. (Closed) URI 327,328/87-24-04; Apparent lack of control over system and equipment status, procedural changes, and testing evolutions. This unresolved item is closed and VIO 327,328/87-30-01 opened to address the issues identified in paragraphs 9 and 15 of this report. 4. Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable or may involve violations or deviations. Eight unresolved items were identified during this inspection, and are identified in paragraphs 9, 12, 13, 14 and 15. 5. Operational Safety Verification (71707) a. Plant Tours The inspectors observed control room operations, reviewed applicable

logs, conducted discussions with control room operators, observed shift turnovers, and confirmed operability of instrumentation. The ! inspectors verified the operability of selected emergency systems, and verified compliance with TS Limiting Conditions for Operation (LCO). The inspectors verified that maintenance work orders had been submitted as required and that followup activities and prioritization of work was accomplished by the licensee. Touas of the diesel generator, auxiliary, control, and turbine buildings, and containment were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and plant housekeeping / cleanliness conditions. ! do violations or deviations were identified. , b. Safeguards Inspection In the course of the monthly activities, the inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities including protected and vital area access i controls; searching of personnel and packages; badge issuance and retrieval; patrols and compensatory posts; and escorting of visitors. _ _ _ _ _ _ . - _ _ _ _ _ _ j

_ _ _ _ _ _ _ _ _ _ _ _ _ _ , 4 In addition, the inspectors observed protected area lighting, and protected and vital area barrier integrity. The inspectors verified an interface between the security organization and operations or maintenance. Specifically, the resident inspector inspected security during outages, reviewcd licensee security event reports, and visited central and secondary alarm stations. No violations or deviations were identified, c. Radiation Protection The inspectors observed health physics (HP) practices and verified implementation of radiation protection control. On a regular basis, radiation work permits (RWPs) were reviewed and specific work activities were monitored to ensure the activities were being conducted in accordance with applicable RWPs. Selected radiation protection instruments were verified operable and calibration frequencies were reviewed. No violations or deviations were identified. 6. Monthly Surveillance Observations (61726) The inspectors observed and reviewed TS required surveillance testing and verified that testing was performed in accordance with adequate procedures; that test instrumentation was calibrated; that LCOs were met; that test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; that deficiencies were identified, as appropriate, and that any deficiencies identified during the testing were properly reviewed and resolved by management personnel; and that system restoration was adequate. For complete tests, the inspector verified that testing frequencies were met and tests were performed by qualified individuals. The following surveillance instructions (sis) were observed / reviewed: SI-275.1 Inspection of Non-Class 1E Load Circuit Breakers Fed from 1E Busses, Unit 1 SI - Essential Raw Cooling Water Pumps . SI-1,3.1 Containment Isolation Valve Leak Rate Test, Units 1 and 2 SI-46.3 Component Cooling Water Pump 2A-A SI-166.36 Diesel Starting Air Valve Test SI-102 M/M Diesel Generator Monthly Mechanical Inspections

i SI-7 Electrical Power Systems: Diesel Generators l l l 1 __-___________________a

r - ---- - - - . - . - - - . - - ____ _ _ _ _ _ _ _ _ _ _ __ _ _ . _ - - - _ _ _ _ _ _ _ _ _ _ _ - - - - _ _ _ _ _ _ l 5 .SI-196 Periodic Calibration of Upper Head Injection System Instrumentation SI-90.62 Reactor Trip /ESF Instrumentation Functional Tests Violations identified are discussed in paragraph 15 of this report. - 7. Monthly Maintenance Observations _(62703) Station maintenance activities of safety-related systems and components were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with TS. The following items were considered during this review: LCOs were met while components or systems were removed from service; redundant components were operable; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; procedures used were adequate to control the activity; troubleshooting activities were controlled and the repair record accurately reflected what actually took place; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; accivities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; QC hold points were established where required and were observed; fire prevention controls were implemented; outside contractor force activities were controlled in accordance with the approved quality assurance (QA) program; and housekeeping was actively pursued. The following were reviewed: WP 12340 WR B 233992 WP 12245 WP 12465 WP 12457 WP 12193 WP 12456 WR B 232787 WR B 211669 PM-1955-082 28-B D/G Actuator Inspections PM-1849-082 Diesel Generator 2-GENB-082-2B-B WR B 233351 WP 12298 Violations identified are discussed in paragraph 15 of this report since they relate to functional testing. 8. Licensee Event Report (LER) Followup (92700) The following LERs were reviewed and closed. The inspector verified that: reporting requirements had been met; causes had been identified;

____ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ ____-_ - __ _ 6 corrective actions appeared appropriate; generic applicability had been considered; the LER forms were complete; the licensee had reviewed the event; no unreviewed safety questions were involved; and no violations of , regulations or TS conditions had been identified. a. LERs Unit 1 327/84-054, Reactor Trip Due to Loss of Relay Rack. A review of this event determined that relay rack power supply was lost due to a blown fuse. The LER adequately described the event. 327/85-009, Inoperability of the Rod Position Indication System. This event was determined to be caused by a temporary reduction of the system's "20 volt a.c. power supply. Water was found under the . line voltage regulator. The most likely' sequence was inadvertent wetting of the regulator by workers in 'the area. Rod position was returned to normal after approximately 9 minutes. 9. Event Followup (93702, 62703) As discussed in Inspection Report 327,328/87-24, NRC reviewed three separate events that occurred at Sequoyah Unit I which involved leakage of primary coolant from the Reactor Coolant System (RCS). These events were investigated in depth by review committees appointed by the licensee as i described below. An on-site review committee was appointed by the site director and consisted of inter-disciplinary members that were headed by the supervisor of the plant operations review staff (PORS). The resultant report by that group is referred to as the PORS report. Additionally, an independent review group was appointed by the Manager of Nuclear Power, and consisted primarily of individuals assigned to the nuclear manager's review group (NMRG). Both review groups used TVA personnel as well as consultants to assist in their investigations. The NRC review effort encompassed an independent investigation of the three events as well as a review of the scope, methodology and results of the TVA investigations. The first two events occurred January 28, 1987 and February 1,1987. Both review groups were chartered to perform investigations into the events after the second one occurred. The third event took place on ' April 29, 1987, and was investigated by a third group consisting primarily of P0RS personnel. URI 327,328/87-02-07 was written following the first two events. After the third event, NRC determined that all three events, along with others identified in paragraph 15 of this report, resulted from improperly implemented procedures; demonstrating a lack of control over system and equipment status and testing evolutions. This was carried as URI 327,328/87-24-04 pending further NRC review. Specific issues pertaining to the three spill events have subsequently been discerned, and are addressed in the event descriptions below. Accordingly, URIs 327,328/87-02-07 and 327,328/87-24-04 are considered closed. i _ _ _ _ _ _ _ _ _ _ _ _ _ -

_ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ ___ ____ _ _ - 7 a. The first event occurred while the RCS was partially drained to allow for steam generator primary side maintenance. The sight glass used to determine RCS loop level became plugged by debris and corrosion products. The unit operator (UO) was unable to determine the exact level . by use of an installed TV camera and monitor, and sent an Auxiliary Unit Operator (AU0) into containment to verify level .in the sight glass. The AUD reported that level was 11 inches higher than the previous recorded level. The U0 decided to lower the level in the RCS back to the normal control level. This was accomplished over the next 2.5 hours by increasing the letdown flow rate while holding the charging rate constant. The U0 did not realize that the sight glass was plugged and was not responding properly. The observed level decrease over this period was only 2 inches in the sight glass while the actual RCS level decreased approximately 18 inches. The reactor core remained covered. The level decrease was terminated when the RHR pump displayed signs of cavitation and loss of flow, indicating that the actual level dropped below the minimum for adequate RHR pump suction. When this occurrcJ ne VO stopped the running RHR pump, and began increasing level t- ein RHR shutdown cooling to the core. His primary concern at t v .i .ne was to restore ~ adequate Irvel to enable the resumption of RPR low. Although there was indication that the sight glass was not reflecting water level properly, the U0 continued to increase watar level using the sight glass for indication. Personnel monitoring the SG work by a separate TV monitor observed the RCS level beginning to rise in the primary channel head through the open manway door. They phoned the control room and told the UO of the imminent spill of water out the manway. The VO secured from increasing the level, but the water continued to rise for approximately 3 minutes after the charging stopped. This resulted in approximately 500 gallons of RCS water being spilled out the open manway. There were no personnel injuries or contaminations associated with this event. This item will be identified as URI 327,328/87-30-03 pending further NRC review of the licensee's resolution of this event. b. The second event occurred while the RCS was still partially drained and open at the primary side manway for SG repairs. The VO on shift was stroke-time testing valves on a scheduled surveillance interval. The surveillance instruction in use for this evolution was SI-166.3, Full Stroking of Category "A" and "B" Valves during Cold Shutdown. The list of valves included 1-FCV-63-1, the refueling water storage tank (RWST) isolation valve. This valve isolates the RHR pumps from the RWST, and is shut while the RHR system is aligned to the RCS for shutdown cooling. With the RCS depressurized, opening this valve would result in RWST water filling the RCS through the RHR suction line connected to RCS loop 4, due to elevation head differences. The inspector interviewed the VO, Shift Engineer (SE) and Assistant Shift Enginer:r (ASE). As a result of these interviews, the inspector determined that the UD knew that this potential for flooding the RCS _ _ - _ _ _ _ - _ - _ _ _ _ _ - _ _ _ _ .

_ _ _ _ - - _ - _ l 8 l 1 existed, and that the procedure used did not include the appropriate isolation of the RWST from the RCS prior to opening 1-FCV-63-1. Additionally, administrative instructions associated with hold orders were' not utilized to assure proper isolation of the RWST from the drained / opened SG. The UD knew the procedure was inadequate in that j not all valves required for isolating the RCS from the RWST were ) ' included in the procedure, but did not stop the test as required and get the procedure corrected. Instead, the UO improvised a system realignment without written instructions by closing what was thought i to be the appropriate isolation valves. The ASE had full knowledge that the VO was working outside the procedure. Apparently, the SE who was in charge of the shift was not informed of the procedural problems. The UO did not refer to a flow diagram, but relied on memory alone to construct a lineup. Neither of the two series RCS suction isolation valves were included in the isolation process. As a result, there was a direct flow path from the RWST to the open, depressurized RCS when 1-FCV-63-1 was opened during the stroke test. The RCS was immediately filled, and water began flowing rapidly ' f rom the open SG manway. The event was terminated by reclosing 1-FCV-63-1. Approximately 3000 gallons of water were spilled and several workers in containment were wetted down. No injuries occurred and no personnel contaminations were identified. TS 6.8.1 requires that written procedures shall be established, implemented and maintained covering activities referenced including surveillance and testing activities of safety related equipment. Contrary to the above, SI-166.3 was not adequately implemented in that changes to the instruction were necessary for the conditions in effect at the time of the test. The instruction was nevertheless used by the operator to perform the stroke-time testing of valve 1-FCV-63-1. The operator attempted to make the instruction usable by performing an informal, unreviewed change to the instruction in the form of additional valves that were repositioned in an attempt to isolate the RCS from the RWST. Changes and revisions to plant instructions are controlled by Administrative Instruction (AI)-4, Preparation, Review, Approval and Use of Plant Instructions. The operator did not implement this instruction. Instead, an improper and uncontrolled system realignment was effected without written instructions. The failure to establish and implement procedures resulted in a loss of control of plant activities and is a violation (VIO 327,328/87-30-01). Administrative Instruction (AI)-30, Nuclear Plant Method of Operation", Section 2.2, requires that when a condition exists that could adversely affect personnel or equipment safety while an instruction is being followed, and sufficient time is available, normal change and revision methods of AI-4 are to be used. Contrary to the above, on February 1,1987, the control room operator did not implement the formal change process of AI-4 to revise _ _ _ _ _ _ _ _ _ _ _ _ _ _ -

_ _ _ _ - _ _ _ . .9 AI-166.3 upon realizing that the stroke testing of valve 1-FCV-63-1 could not be accomplished as written. This is another example of violation 327,328/87-30-01- in that SI-166.3 was not written to be performed with the RCS loops partially drained. The instruction did not provide for isolation of the RWST from the RCS. This isolation was necessary to prevent the flow of water from the RWST into the RCS and out the open primary side SG manway. Instead, the operator improvised a system realignment without written instructions that resulted in a spill of approximately 3000 gallons of radioactive water into the SG maintenance area and out onto the containment floor. TS 6.8.1 requires that written procedures be established, implemented and maintained covering the referenced activities. Contrary to this requirement, AI-3, Clearance Procedures, was not properly implemented in the four instances detailed below: (1) AI-3, Section 5.2.1.1, states that a Hold Order clearance (red tag) is the means to ensure lines or equipment remain de-energized, depressurized, and isolated so work can be safely performed and equipment protected. Contrary to the above, the clearance originally established to support the SG work in progress at the time of the event did not ensure the maintenance area was properly isolated from the elevated water source (the RWST). A Hold Order had been requested by the craft personnel performing the SG maintenance. Instead of hanging a Hold Order tag on valve 1-FCV-63-1, a Caution Order tag was placed on the valve. The Caution Order tag only required the ASE's permission prior to opening the valve. The related SG maintenance instruction (MI)-3.1, Appendix B, " Clearance Instructions," stipulated that valve 1-FCV-63-1 be closed and the control switch tagged under caution order, worded as follows: "In the event it becomes necessary to open this valve, notify SE immediately." This instruction conflicted with the requirements of AI-3, section 5.2.1.1. The inconsistency between AI-3 and MI-3.1 regarding the type of tag to be placed on the valve is an example of inadequate application of the AI-3 requirements. AI-3 does not clearly discuss the reasons for utilizing a Hold Order as opposed. to a Caution Order, nor is it specific in delineating the conditions or activities that would permit the use of a Caution Order as opposed to a Hold Order. Such ambiguities in AI-3 contributed to the inadequacies associated with implementa- tion of this clearance. (2) AI-3, Section 3.1.8, requires that a caution tag identify the abnormal conditions and may include special instructions to the _ _ _ - - _ _ _ _ _ _ _ - -

-- - _ _ _ _ _ _ 10 operator. Contrary to this requirement, the instructions on the 1-FCV-63-1 caution tag only required that the ASE's permission be otained prior to opening the valve. Ne mention of the abnormal condition or the hazards involved were placed on the tag. (3) AI-3, Sections 5.1.4 and 5.3.3, require that the clearance be issued to the person requesting the clearance and responsible for the work. Contrary to this requirement, the caution order was issued to the ASE. These instances of failure to implement AI-3, indicate a failure to control plant activities, and are considered another example of Violation 327,328/87-30-01. OSLA 58, " Maintaining Cognizance of Operational Status", Section E.1, requires that all outages or deviations associated with listed systems be logged in the configuration log. Entries are to be made regardless of outage time. Contrary to the requirements listed above, prior to the opening of valve 1-FCV-63-1 and causing the February 1,1987 RCS spill, five (5)- valves were shut by the operator in an attempt to isolate the SG maintenance area from the RWST w;thout making appropriate entries in the configuration log as required. This is a further example of violation 327,328/87-30-01. c. The third event on April 29, 1987, was a result of a valve misalignment of a normal system configuration that did not get entered on the configuration log as a deviation from normal position.

Prior to this RCS spill, the operators were refilling the RCS after i the SG work had been completed. The refill was to be followed by pressurizing the RCS to 325 psig, the minimum pressure for RCS pump i operation. The reason the pumps were to be -un, was to " sweep" air and gasses through the system to allow thorough venting. The operators had checked the configuration log for deviations from the normal RCS alignment, but one talve (1-HCV-68-594, the prc;surizer spray line drain isolation valve) was open, which was not the normal aligned portion. This deviation from normal alignment was not listed as a deviation in the configuration log. As water level in the RCS was raised, air and gasses were being vented through a power operated ) relief valve (PORV). When water began flowing through the PORV, the operator shut it and continued charging water to raise RCS pressure to 325 psig. When the RCS pressure began rising, water flowed out the open 68-594 valve, through an attached hose, onto the side of the pressurizer and down onto the containment floor. There was no indication of leakage until en auxiliary reactor building floor and equipment drain sump level alarm occurred. This sump receives water , from floor drains, among several other sources. The operators i checked the sump level i r.di cato r s , found level above normal , but thought that the source of water to the sump was probably instrument i i l __-----------_--J

_ _ _ _ 11 sense line leakage, and continued the pressure increase. After reaching 325 psig, the operators began matching charging and indicated letdown flow rates to stabilize RCS pressure. When this was done, however, pressure began decreasing immediately, because of the unidentified leakage out of valve 68-594. Several attempts at 4 matching charging and letdown yielded the same result. This was postulated as a calibration error on the charging line flow rate instrument, which had a work request written on it for recalibration. Approximately 30 minutes later, a high containment moisture alarm occurred. At this point the operators realized a leak existed. They immediately began depressurizing the RCS and investigating the- location of the leak. Water was observed streaming from the hose attached to valve 68-594. An operator shut the valve and terminated the leak. Approximately 5000 gallons had spilled onto the containment floor. No personnel injury or contamination occurred. OSLA 58, " Maintaining Cognizance of Operational Status", Section E.1, requires that all outages or deviations associated with listed systems be logged in the configuration log. Entries are to be made regardless of outage time. Contrary.to the above, pressurizer spray line vent valve 1-HCV-68-594 was positioned cpen prior to the refilling of the RCS on April 29, 1987, following SG maintenance wcrk. This deviation from the normal i valve alignment was not entered in the configuration log. Consequently, the operators were not cognizant of the open position t of this valve, and this resulted in an RCS spill of approximately 5000 gallons onto the containment floor during refilling and pressurization of the RCS. This loss of control over plant activities is another example of Violation 327,328/87-30-01). 10. IE Bulletins (92701) IE Bulletins' are documents issued by the NRC which require certain specific actions of the addressee. The inspector has reviewed the actions taken by the licensee as a response to the below listed IE bulletins. The inspector verified that: corrective actions appeared appropriate; generic applicability had been considered; the licensee had reviewed the event and ' that appropriate plant personnel were knowledgeable; no unreviewed safety questions were involved; and that violations of regulations or TS conditions did not appear to occur. (Closed) 327,328/78-BU-07, Protection Afforded by Air-Line Respirators and Supplied-Air Hoods. Sequoyah was not a licensee at the time of issuance of this Bulletin. During the licensing process the licensee's respiratory protection program was reviewed and determined to be adequate. Therefore, no further action is required. This item is closed. The following items were reviewed by the inspectors and determined not to be applicable to Sequoyah: ) ! - __ ._ l

_- _ - _ _ _ _ _ _ _ - 12 (Closed) 327,328/82-BU-03,. SCC in Thick Wall Recirculation Piping at BWRs. (Closed) 327,328/83-BU-02, SCC in Recirculation Piping at BWRs. - (Closed) 327,328/84-BU-01, Cracks in Boiling Water Reactor Mark I Containment Vent Headers. 11. Inspector Followup Items Inspector Followup Items (IFIs) are matters of concern to the inspector which are documented and tracked in inspection reports to allow further review and evaluation by the inspector. The following IFIs have been reviewed and evaluated by the inspector. The inspector has either resolved the concern identified, determir.ed that the licensee has l performed adequately in the area, and/or determined that actions taken by the. licensee have resolved the concern. (Closed) IFI 327,328/85-26-05, Functional Test Criteria for Condensate- Demineralized Waste Evaporator. This issue is oeing addressed in the corrective actions to Violation 327.,328/86-28-01 which was reviewed and found to require additional inspection and evaluation effort in Inspection Report 327,328/87-08. This item is closed. (Closed) IFI 327,328/85-26-08, Verification of Setpoint Change on Radiation Monitor RM-90-10.B. The setpoint of this particular radiation monitor was evaluated by the licensee to be too close to the spurious readings achieved when the monitor was placed into service. While placing the Auxiliary Building (AB) general supply fans in service, three AB isolations occurred. The licensee reset the setpoint and verified that it continued to meet the requirements of TS 3.11.2.1 by performing SI-291, Readjustment of Setpoint for Radiation Monitors With Variable Setpoints - Units 0, 1 and 2. This item is closed. (Closed) IFI 327,328/85-46-06, Control Room Ventilation. This issue concerns the functional test of the Control Room Air Intake Chlorine Detection System. This issue will be resolved under URI 327,328/86-32-07 which is being evaluated during the surveillance instruction review inspection (Inspection Report '7,328/87-36). (Closed) IFI 327,328/85-46-11, Adeq'uacy of Containment Setpoint Based On Measuring and Test Equipment Accuracy. This issue involved a negative safety margin for containment pressure and certain reactor trip setpoints based on the Westinghouse setpoint methodology. The inspector reviewed the current Westinghouse setpoint methodology and a resolution to the , t setpoint questions forwarded to TVA in Westinghouse letter (Williams /Abercrombie) dated October 8, 1986. The inspector had no further questions. This item is closed. (Closed) IFI 327,328/86-15-03, EDG Discrepancies. The licensee has taken steps to correct the discrepancies identified by the inspector. This item is closed.


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._ _ - _ _- _ - _ _ _ - _ _ _ L L 13 (Closrd) . IFI 327,328/86-19-08, Housekeeping in EDG cabinets. Trash and' debris has been removed from the control and pcwer cabinets. This item is closed. r (Closed) IFI 327,328/86-37-02, Bifurcating Pipe in Auxiliary Feedwater Line. Division of Nuclear Engineering (CNE) has evaluated this item and K has determined that a negligible amount of head loss was added due to the pipe reduction. Engineering calculations were revited to account for this additional head loss. This item is closed. (Closed) IFI .327,328/84-16-01, Reliability and Use of Positive Displacement Charging Pumps. The IFI had noted two concerns. First, the Positive Displacement Pump was not safety related. Second,.the inspector was concerned with the period of time required to return the Centrifugal Charging Pump to operable status. The licensee requested and received a one time emergency TS change .to TS 3.5.2 allowing an additional 36 hours in which to repair- a centrifugal charging pump. The inspector surveyed other plants in the Region and determined that the plant configuration with one non-safety Reciprocating Charging Pump was acceptable. This item is closed. 7 (Closed) IFI 327,328/86-28-08, Hold Order Requirements. The inspector was concerned with the proper usage of the Hold Order / Clearance Procedure ") following an event when an electrician. began work on an energized valve he thought was de-energized. Additional problems have been observed and are described in Violation 327,328/87-30-01. The review of the program will be accomplished following implementation of ' corrective actions to the violation. Therefore, this inspector followup item is closed. (Closed) IFI~327,328/85-47-02, Review of Procedure Revision and ADI-27 for Update after Workplan. The inspector reviewed this item and evaluated the adequacy of the AOI-27 revision. A portion of the procedure revision question was reviewed by special inspection 87-36 and the. remainder of this item was closed in special inspection 327,328/86-62, (Closed) IFI 328/84-35-04, Review of Fuel Handling Instruction FHI-7, k Refueling ' Operation. The inspector had questioned the adequcy of the l procedure to protect spent fuel from being damaged following fuel transfer system failure. These concerns were identical -to those of another inspector that opened URI 328/84-32-01. This URI was later upgraded to

VIO 328/8.4-3rr-01. The violation was formally closed in Inspection Report 85-44. Item'84-35-04 is closed. (Closed) IFI 328/84-35-03, Determination of cause and correction of fuel- transfer system failure. This item was closely related to URI 328/84-32-03. The URI was upgraded as part of VIO 328/84-36-01. This violation incorporated all of the concerns in the IFI. This violation was , formally closed in Inspection Report 85-44. Accordingly, IFI 84-35-04 is j closed. 1 - -- - - - - - - - - - - - - - - - - - - _ a

_ _ , _ - _ l 14 12. Safety' Review Function (40700, 40701) A review of the varied groups performing licensee safety review functions l was conducted. The following groups were reviewed: ISEG - Independent Safety Engineering Group (TS required) PORC - Plant Operations Review Committee (TS required) NSRB - Nuclear Safety Review Board (YS required) RARC - Radiological Assessment Review Committee (TS required) NERP - Nuclear Experience Review Program (TVA commitment) PORS - Plant Operations Review Staff (PORC subcommittee) NMRG - Nuclear Manager's Review Group (licensee initiative) NSRS - Nuclear Safety Review Staff (previous licensee initiative) The charters of the individual committees, intercommittee relationships 6.i communications, ed compliance with regulations were inspected. In u uition, the review'6:so included an examination of several events which are described in paragr2nh 9 of this repo-t. a. Independent Safety Engineering Group (ISEG) During this inspection period, the licensee was in the precess of changing the ISEG organization from a group of five full-time dedicated engineers on site to an organization which has three full-time dedicated enginecrs on site and two full-time engineers shared among all TVA nuclear sites off site. NRC approval for this change is currently being requested via proposed T5 ammendment. As a result of this organizational change and the fact that the new ISEG organization was fully implemented at the time this inspection was conducted, only the current ISEG organ *zatica was inspected. The following documer.;s were reviewed: TVA letter (Gridley/Youngblood) dated May 27, 1986 (L44860527301) Administrative TS Changes Reflecting New - Organizational Structure TVA letter (Gridley/ Office of Special Projects) dated May 15, 1987 (L44870515821) - Implementation of ISEG ISEG Implementation Charter ISEG Implementing Procedures 0604.05 - ISEG Evaluations 6.1-Ir0 - Selection of ISEG Topics 6.1-2r0 - Conduct of ISEG Reviews 6.1-3r0 - Reporting of ISEG Reviews 6.2-4r0 - Tracking of ISEG Findings _ _ _ _

- _ _ - _ . -- [? - " ! [ ] u 15 , j 6.1-5r0 - ISEG Surveillance l- activities L 6.1-6r0 - ISEG Personnel I. Training ! 1 ISEG position descriptions ISEG member resumes l TVA organization chart including ISEG The ISEG reports to the Manager of Nuclear -Safety and Licensing (MNSL). through the Manager of Nuclear Safety (MNS). Both the MNSL ana the MNS'are corporate positions which are located in Chattanooga, TN. The ISEG provides written reports to the NSRB: and TVA line management at-the completion of specific investigations. The ISEG is scheduled to meet with NSRB, PORC, NMRG, NERP, TVA generic licensing and TVA line management at routine intervals. There appears to be clear lines of responsibility and authority within the ISEG and between.the ISEG and other groups. There appears to be nearly a complete overlap between the ISEG, NSRB, and NMRG with respect to the areas which can be investigated and the depth of a potential investigation. There is also an area of overlap between the generic licensing group and the ISEG with respect to the review of NRC issuances. The overlaps as they exist now do not appear to cause any organizational difficulties or loss of safety review function performance.

Senior TVA management receives information, presented by the ISEG, at the Site Director, NSRB, and MNSL levels. Information is not generally presented by the ISEG directly to the Mant.ger of Nuclear . Power or the TVA Board of Directors. One area of. potential difficulty was identified by the inspector. The new ISEG has not yet developed an auditable system to , ensure compliance with the requirements of the TS. This was discussed with the MNS who stated that a system wou'd be developed, b. Nuclear Experience Review Program (NERP) The NERP was established by the licensee to comply the with TMI task action plan I.L.S of NUREG-0660. The following documents were reviewed during the review of the NERP: NERP charter NERP procedures 0601.01 - Nuclear Experience Review DVP 6.1-2 - Nuclea, Experience Review _ _______-_ ___ _

.. . 16 NERP position descriptions NERP personnel resumes. TVA organizational chart including NERP TVA' has undergone a recent organizational change involving the NERP. The present program was in effect at the time of the inspection however, information on the long term effectiveness of the program was not available. The lines of authority and responsibility within the NERP appear to be clear. and well defined. Implementing procedures appear to meet the intent of TMI task action item I.C.5. The NERP reports to the MNSL through the MNS both of which are corporate positions located in Chattanooga, TN. The NERP does not routinely provide upper TVA management levels with information outside of its normal reporting function. Two potential interface problems were discussed with the MNS. The ' first issue involved .the ' interface with the generic licensing group which reports to the Manager of Nuclear Licensing. The generic licensing group is responsible for NRC IE Bulletins and generic letters and the NERP is not. The organizational interface splits the- responsibility for I.C.5 requirements between two groups. The'second issue involves the requirement to provide a periodic internal audit of .the experience review process to ensure that the feedback program functions effectively at all levels. In order to affect this audit the NERP may need the assistance of other organizations. c. Plant Operations Review Staff (PORS) The inspection in this area was to determine whether clear lines of responsibility exist and to review and verify implementation of charter requirements for the group. To accomplish this objective the inspector reviewed the groups responsibility as outlined in SQN-25-0451549D, " Position Description". The P0RS group is not a TS required groep. However, they do perform several safety review functions. The listed responsibilities included the following: Investigating noted problem areas of special events on request of the Plant Manager or Plant Operations Review Committee. Assessing the cause of the event and recommending corrective action or assessing effectiveness of ongoing corrective action. Ensuring the timely evaluation and tracking of potential reportable occurrences (PR0s). Ensuring proper disposition of PR0s and evaluation of deportability in accordance with applicable Federal regulations. - - _ _

- _ _ _ _ _ 17 Ensuring proper preparation and timely submission of Licensee Event Reports for the Diant Manager's signature in accordance with NRC regulations. Ensuring proper preparation of noncoutine special reports as required by 'S for the Plan' Manager's signature. Ensuring preparation of various performance reports required by NRC and TVA. Directing the plant program for handling all conditions adverse

to quality received from the other organizations including preparation / approval of all safety evaluations and determining deportability. Ensuring proper coordination and preparation of technically involved Unreviewed Safety Question Determinations (USQDs) when requests are made by plant sections. Developing and implementing the plant program for TS interpreta- tions. The PORS group reports to the plant manager and serves as a- sub- committee to PORC when performing investigations into operational events. There are no formal instructions established to resolve conflicts between PORS findings and any other groups investigating the same event. Several LERs describing operational events including those identified in paragraph 9 of this report were reviewed to evaluate the effectiveness of the PORS effort. The events reviewed and the inspector's findings are listed below: LER 1-87-016, Loss of 6.9 KV Shutdown Board. TMs LER appeared to have accurately captured the event and the description was clear and informative. 1 LER 1-86-045, Inadvertent Diesel Generator Start. This LER ' appeared to have missed the real root cause of the event. Specifically, the LER attributed the cause of the event to be a problem with (MIS-5, 5 amp fuses) where the inspector determined the root cause to be a failure to properly tag out the circuit under maintenance. This was discussed with the licensee and the licensee cisagreed with the inspector's positions. This issue will be further reviewed in IR 327,328/87-43. l LER 1-87-012 & Revision 1, Loss of RHR Cooling and Reactor l Coolant Spill Event of January 28, 1937. The LER that described this event used plant elevations to express reactor vessel water level in the partial drained mode. This is inconsistent with industry practice as elevations are meaningful only to a _ _ _ _ _ _

- - _ _ _ _ _ _ 18 L specific Plant. A better way of' describing water level is using reactor vessel nozzle center line as the "0" point and using +/- inches from this point. Although an LER revision did address the actual loss of RHR and reactor' coolant spill, the original LER did not address the fact that the low water level condition which caused the loss of one RHR pump would also cause the loss of the other RHR pump as both pumps use a common suction line. This event is described in more detail in paragraph 9.a of this report. LER 1-87-013, Reactor Coolant Spill event of February 1,1987. The LER's categorization of root cause and corrective actions appeared to have missed the fact that if the valve had been danger tagged for equipment and personnel protection, the events should not have occurred. This information was discussed with plant personnel who indicated that a management decision was made to not tag the valves. This, item is addressed in more detail in section 9.b of this report. The inspector also reviewed the process used at Sequoyah for determining reporting requirements under 10 CFR 50.72, 50.73, 20.403 etc. This process is described in Administrative Instruction (AI)-18 Revision 46, " Plant Reporting Requirements." The requirements of the plant procedure match the regulatory requirements. However, the examples listed in the AI do not include the clarification of the regulation contained in NUREG 1022, 1022 supplement 1 and 1022 supplemeat 2. Additionally, AI-18 did not include the statement contained in 10 CFR 50.72(a)(3) which requires' notification of the NRC immediately after notification of the appropriate state and local agencies and not later than one hour after the licensee declares one of the emergency cl uses. The AI did, however, require the notification of thr fr; within one hour af ter the licensee declares I one of the emergei."- classes. The inspector verified that the Radiological Emergency Plan implementing procedures required notification of state and local officials. l 1 d. Plant Operations Review Committee (PORC) j The PORC acts as a multi-disciplinary advisory committee to the Plant Manager on matters related to Nuclear Safety. PORC membership and alternates are designated in TS Section and 6.5.1. The following documents were reviewed: TS Section 6.5.1 Final Safety Analysis Report Section 13.4 ANSI-N 18.7 1976 50I-21 PORC Charter AI-4, Preparation, Review, Approval and Use of Plant ' Instructions The PORC uses the plant operations review staff (PORS) to do _ _ - - _ _ _ _ - - - _

_ _ _ _ 19 preliminary review and preparations of reports covering reportable events. In addition, PORS can conduct investigations for PORC (like a subcommittee). PORC has several preliminary . review processes it employs prior to a procedure review in PORC. Preliminary review consists of either review by three qualified reviewers (one of which must be from site QA) or review by a minimum of five sections plus the plant manager or his representative (traditional informal PORC). Comments from these preliminary reviews are provided to the PORC members for review along with the changes they generated. The inspector reviewed PORC meeting minutes for 1987 PORC meeting minutes have not been signed by the PORC chairman since February 8, 1987. Typi g of PORC meeting minutes has about a two month backlog. The licensee identified that additional typing - staff has been obtained to reduce the backlog. A date for catching up the processing of PORC minutes was estimated by the licensee to be July 15, 1987. Transmittal of the meeting minutes to NSRB as required by the TS will follow. The inspector reviewed how PORC functioned in the investigation of the January 28- and February 1,1987, steam generator spills and the April 29,1987 pressurizer spill. For the steam generator events, the plant manager charged the Plant Operations Review Staff (PORS) Supervisor with conducting an investigation into the spills. The verbal charters of the investigating group was that peripheral issues were not to detract from investigation of the main events. The team was assumed to be functioning as a PORC subcommittee by the team leader although he had not specifically been told that. The PORS supervisor provided interim recommendations to the plant manager and site director on February 5, 1987, to allow continuance af staam generator tube work. These interim recommendations were reviewed by PORC, which then issued the final report on April 7, 1987. The final report follows the verbal charter for investigation of the main event although some peripheral issues were briafly mentioned. Discussions of the final report for the steam generator spills entailed about three hours of time at the April 7, 1987, PORC meeting. The inspector could not establish that peripheral issues, such as operations shift supervisory involvement (discussed in the Nuclear Manager's Review Group (NMRG) report issued May 1, 1987), were discussed in any detail during the PORC meeting. The inspector did confirm that after review of the MMRG report by the plant, the issues that were not covered in the PORS report were taken for action and assigned to the appropriate department for review and comment. PORC recommended that the corrective actions and recommendations from the P0RS report be assigned for action. The pressurizer spill event of April 29, 1987, was handled in the exact same fashion as the steam generator spill events. The . - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

_ _ _ _ _ _ _ - _ _ _ . l 20 investigation team was chartered by the Plant Manager; no PORC meeting minutes were found that specifically chartered the group as a subcommittee; and direction was to concentrate on root cause for the main event. In addition, P0RS was told the investigation needed to be completed in a short period of time. The final report was dis- cussed at PORC on May 18, 1987, for about 30 minutes. The existence of a QA Audit on cor. figuration control requested by the plant manage- ment and a CAQR on the results of the QA Audit were added to the report by PORC. A decisi% to evaluate and audit configuration control methods had alreaoy been made by plant management which resulted in a minimum of discussion at the PORC meeting. The inspector was unable to establish that these investigation-teams. were actually chartered as PORC subcommittees. The plant manager at the NRC entrance meeting, when questioned about the composition of the team, stated that they were functioning as a subcommittee of PORC. When interviewed later, he stated that they were never formally chartered; however, due to composition and function, they were like a PORC subcommittee. The PORC Charter, Standard Practice SQA-21, requires that subcommit- tee reports be recorded in the minutes of formal PORC meetings, and actions derived from subcommittee recommendations shall be so identified. In addition, . SQA-21 states that PORC shall maintain writter, minutes of each PORC meeting that, at a minimum, document the results of all PORC activities performed under the responsibility and authority provisions of this' procedure, lhe' designation of a sub- committee to investigate an event is the result of a PORC activity and should be designated in the meeting minutes both at the time of charter and when the report is presented. Although there was some confusion over the chartering of the investigation teams, the licensee agreed that subcommittees shall be designated in the PORC meeting minutes, e. Nuclear Safety Review Board (NSRB) On June 9, 1987, the inspector met with the Chairman and selected members of the Sequoyah Nuc~ aar Saf ety Review Board (NSRB) for the purpose of verifying that the requirements of TS are being satisfied. Specifically, the NSRB is a board requhed cy section 6.5.2 of the Sequoyah TS. The TS requires that the board review certain plant activities which include: Safety evaluations for changes to procedure, equipment or systems undec 10 CFR 50.59 Safety evaluations for test or experiments under 10 CFR 50.59 Proposed changes to procedures, equipment or systems which involve an unreviewed safety question .. - - _ _ _ _ - _ _ _ _ . __

_ _ _ __ _ _ _ ._ _ 21 -Proposed changes to TS or to the operating license and viola- tions of codes, regulations, orders, TS, license. requirements or of internal procedures or. instruction having nuclear safety significance l ' Licensee event reports (LJRs) Reports and meeting minutes of the PORC and the RARC Section 6.5.2 8 of the TS also requires the NSRB to be cognizant of audits for specific activities. L Section 6.5.2.10 of the Sequoyah TS requires that meeting minutes be prepared, approved, and forwarded to the Manager of Power within 14 ' l days following each meeting. The TS further requires that the l results of the reviews listed above be sent to the Manager of Power within 14 days following completion of the review. In - order to assess the NSRB effectiveness and to verify TS compliance', the inspector reviewed revision 12 of the Charter for the NSRB (RIML42870116 801) dated January 21, 1987. This charter is the vehicle used by TVA to implement the requirements of TS and provides additional information as to responsibility, structure, and personnel qualification for the NSRB. The NSRB charter requires in section 6.5.6 that meeting minutes be sent to the Manager of the Office of Nuclear Power with copies of the General Manager, TVA Board and other appropriate managers. Details of the inspectors review along with comments and observations are provided below: (1) A review of charter requirements and the previous year of meeting minutes determined that meeting frequency meets the requirements of TS 6.5.2.5 and a quorum was present with the exception of the meeting held September 23 and 24, 1986. Currently, there are only 5 members and the chairman who has been appointed in writing by the Manager of Power with 7 alternate members officially designated. Additionally, 5 advisors have been appointed in writing; however, their title does not satisfy the requirement of alternate. During the September 23 and 24, 1986 meeting, only the chairman and two members plus one unofficial alternate were present. However, all five advisors were listed as present. TS 6.5.2.6 requires the minimum quorum to be more than half the NSRB membership or 'at least 5 members which ever is greater. Without counting the advisor, the September 1986 meeting was held without a quorum, in that, a minimum of 5 members including alternates were not listed as present. This meeting was ! recognized by the chairman as an unofficial meeting and issues were rediscussed at a subsequent meeting. Since TS require a ! ) . _ _ - _ . _ _ _ l

l 22 meeting only every 6 months the requirements were satisfied, in that, the current schedule of meetings is every 2 months. l l (2) The current method used by the NSRB to meet the review function l required by TS 6.5.2.7 does not appear to satisfy the requirements of the TS and is inconsistent with the NRC's policy. The TS requires a minimum quorum of the NSRB be present when the board performs its review and audit function outlined i in the TS. The current practice of the NSRB is to send a copy I of the document requiring review along with a coversheet to the ! NSRB members and advisors requesting comments or approval. Proposed TS changes, operating license changes, and issues i involving an unreviewed safety question are considered by the l board to require approval prior to submittal so the cover sheet l for those items request a technical review and approval. The j other review and audit cognizance requirements of TS are handled the same way except they are issued with a cover sheet which allows the reviewer to request that any safety issue identified be added to the next NSRB meeting agenda. The above method of review / approval involves ballot review and does not require the issue to be discussed in a meeting forum. This practice is not allowed by the NRC and does not satisfy the requirements of TS. This is a violation, VIO 327,328/87-30-02. Additionally, the inspectors consider that the use of advisors to perform these reviews does not by itself satisfy the quorum requirements of TS. (3) The current charter, revision 12, requires that meeting minutes and memoranda be issued within 14 days to the Manager of Power with copies to the General Manager and TVA Board. Through discussions with the chairman of the NSRB this is not currently being done. The minutes and memoranda are given to the Manager Office of Nuclear Power (MONP) and he determines distribution. The inspector was unable to verify distribution from the MONP to the General Manager and TVA Board. Additionally, the May 12 and 13, 1987, meeting minutes which were issued to the MONP office are still being revised by the NSRB. Per discussion with the chairman of the NSRB these revisions are being.made by his board to only revise format and not to alter the technical content of the minutes. Failure to dit. tribute information as outlined in the NSRB charter is a further example of Violation 327,328/87-30-02. (a) During the inspection, the inspector identified that TS Bases Change, TVA Number 87-14 (RIM L44 870417 802), was issued to the NRC by TVA without neceiving prior review by the NSRB. Discussion with NSRB personnel indicated that the Seouoyah staff does not consider a change to the TS bases as a change to TS and therefore a prior review / approval by the NSRB is considered unnecessary. Pending further discussion between the inspector and OSP Headquarters, this will be considered an unresolved item (327,328/87-30-04).

___ __ _ _ 23 f. Nuclear Manager's Review Group (NMRG) and Nuclear ifety Review Staff .(NSRS) The NMRG was established by the licensee to replace the NSRS as the result of management changes instituted by the current Manager of Nuclear Power. The following ' documents were reviewed during the review of the NMRG and NSRS: NMRG and NSRS charters NMRG and NSRS position descriptions NMRG personnel resumes TVA organizational chart including the NMRG Through a review of the charters and activities of the NSRS and the NM7.G it was determined that the activities of the two groups and the experience levei requirements of the personnel performing the activities were essentially the same. No change in the type of activities or the' depth of investigations was identified by the inspector. A review of the functional independence of each of the groups was conducted' NSRS reported to the TVA board and NMRG reports to the Manager of Nuclear Power. There appears to have . been a loss of independence from TVA line management when the transition from the NSRS to NMRG occurred. This loss of independence does not appear to affect the depth of the team investigations, the type of findings or i the ability to evaluate issues in multidisciplined areas. The ) transition from the NSRS to NMRG appears -to have improved line I management responses to NMRG issues in the areas of timeliness and effective corrective actions. The activities of NMRG appear to support the TVA line management goal of reinforcing line management responsibility for corrective actions. 4 A discussion was held with present and past supervisors of the NMRG to determine how information and technical findings are identified to the TVA board. This is accomplished through issue of NMRG reports. The inspectors determined that editorial changes were initiated by TVA line management for inclusion in tne NMRG reports. However, .NMRG personnel interviewed stated that the changes did not affect the findings or the quality of the reports themselves. The inspector had i no further questions. The inspectors noted during their review that a large personnel turnover in review committee membership took place following the change from the NSRS to the NMRG. The reason stated by TVA manage- ment for this turnover from the old NSRS staff was that transfers were made for personal reasons. No conclusion were reached by the inspectors. _ _ _ _ - - - - - - - - )

) 24 13. Testing a. Restart Testing Program lhe Sequoyah restart test program is described in Section 111.11 of the Sequoyah Nuclear Performance Plan (SNNP). The program described lacked detail, since the details are still being developed. As stated in the SNPP, the program was fashioned after the program implemented at the Davis-Besse Nuclear Plant and many of the key managers associated with the TVA's program development were involved in the Davis-Besse effort. In order to better understand the program development, the inspectors have met with key TVA and contractor personnel on a continuing basis. The program described in section III.11 of the SNPP contained the following scope and implementing elements: Scope The restart test program is being developed to ensure that the safety-related functions required to mitigate FSAR chapter 15 events, have been or will be proven by testing prior to or during restart. Implementat. ion Appropriate program administrative and test procedures will be developed and used to supplement the normal plant program and procedures. Restart test groups will be established and staffed by experienced TVA te:;t personnel supplemented by experienced test personnel from outside contractors, as required. FSAR chapter 15 safety functions will be developed and specified by the Division of Nuclear Engineering (DNE) personnel. The FSAR chapter 15 safety functions will be listed and cross-referenced to an existing test document to ensure that the functions have been adequately demonstrated by previous testing. Any function not deemed to be fully tested will have test requirements developed and implemented by test procedures. A Joint Test Group (JTG) will be established to provide an overall review of the restart test pregram. Tests required by the restart test program will be coordinated by the restart test manager with the plant manager or his designee to ensure efficient, safe, and thorough testing. The restart test manager will provide on-shift test coordination for restart testing in support of the shift engineer. . . . . . . . . ._ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _____-_ _ _ _ _ ___ _ A ___ _

- _ _ _ _ _ . _ _ 25 The inspectors conducted a detailed review of the stated program to determine if program scope and implementation is appropriate and accomplish the goals established in the SNPP. The inspectors review and comments were divided into two areas; program scope and program control and implementation. Program Scope TVA's commitments in the SNPP, the inspectors comments, and TVA's position are listed below. Section 111.11.2 of the SNPP implies that TVA has determined that program scope would be limited to the safety-related functions of FSAR chapter 15 eccident mitigation systems as defined by the Design

Baseline and Verification Program (DB&VP). The inspectors determined that the DB&VP program was divided into two phases and included safe shutdown systems as well as chapter 15 accident mitigation systems. Additionally, several systers (i .e. j flood mode boration, and rod control systems) were not included in l the program scope. The implementing procedure, SIL-2, indicated that

the program scope would include all design functions and not just the ! ' safety-related functions. A meeting was held on May 22, 1987, with the Restart Test Manager and his staff to discuss the above concern along with additional inspector comments. TVA reiterated the fact that the program scope included all system design functions and not just the safety-related function as stated in the SNPP. Additionally, the licensee stated that the need to include the flood mode boration system and the rod control systems would be evaluated. The licensee also indicated that safe shutdown systems were included in the program scope. The program description in the SNPP is being supplemented by TVA in a separate letter, whic'n TVA indicated will address system design functions and safe shutdown systems. Conclusions: After incorporation of the inspector's comments, the program scope, which will include all major system design functions when properly applied to the safe chutdown as well as the FSAR chapter 35 accident mitigation systems, should re-establish confidence in the ability of systems to perform their required function. Program Control and Implementation The inspectors reviewed implementation of the program controls which were discussed earlier in this section. The following program implementing procedures were reviewed:

_ _ _ _ _ _ _ 26 SQA-197 revision 0, Restart Test Program. SQEP-63 revision 0, Restart Test Program-Fuctional Test Requirements AI-4 revision 60, Preparation, Review, Approval, and Use of Plant Instructions AI-12(Part 1) revision 0, Corrective Actions STI-I revision 2, Special Test Instructions SIL-1 revision 0, Qualification Program for Restart Test Directors SIL-2 revision 1, Functional Review Process SIL-3 revision 2, Joint Test Group SIL-4 revision 0, Chronological Log SIL-5 revision 0, Preparation of Function and Test Analysis Reports Comments and recommendations were discussed with the TVA Restart Test Manager during meetings held on.May 22, 1987, and June 1, 1987. The comments and recommendations are listed below: Test control and conduct needs to be closely coordinated between the restart test group and operations to ensure that TS requirements are adhered to during testing. The restart test program technically is under the control-of the site director's organization. The inspector requested that better controls be established to ensure that the Plant Manager's organization and safety committee are kept informed. Section III.11 of the SNPP implies that the JTG will review and present for Pirnt Manager and PORC review and approval all decisions which indicate that a function does not require retesting. This process is not reflected in the implementing procedures and is not shown on the process flow network. The JTG should review and approve all program procedures, and the PORC and plant manager should review and approve the procedures which detail the program sco pe ., as well as the specific system special test procedures. STI-1 should be either revised or augmented to provide better - controls over the handling of test deficiencies, test interruptions, closure of test packages with test deficiencies still open, documentation of retest, etc.. Special training for test directors in the conduct of testing should be provided. l The restart test manager addressed the above comments and indicated I that they would be factored into his test program. However, he did clarify that it was not their intent to have the PORC and plant manager review and approve the decision to not retest a function, as 1 _ _ _ _ _ - - _ _ _ _ _ _ -__

___ _ __ , 27 TVA feels it would inundate the committee and is not required. The inspector agreed with this decision. Since the functional test matrix review process involves the review of surveillance test procedures, the inspector requested a meeting between the restart test manager and the Surveillance Instruction (SI) upgrade manager. The purpose of the meeting was to ensure that the two programs clearly interfaced with each other and means have been established to document and resolve any identified SI problems. The licensee agreed to document the meeting in a memorandum of understanding between the two groups. Additionally, the licensee agreed to use the results of the restart test program as one input to the SI enhancement program which is discussed in the SNPP. Conclusions: After proper controls are established to govern interface between the restart test group and the plant operating staff, and between the JTG and'PORC; and after additional controls over the conduct of testing are incorporated, the program as described in Section III.11 of SNPP should be fully implemented. . Additional inspections are planned to review the application of the test matrix review to system design functions. Also inspections to verify adequate test control and conduct will be scheduled after TVA establishes the integrated test schedule. b. Post Modifications Testing During an inspection in July 1986, (Inspection Report 50-327,328/86-43) the inspector identified a violation regarding post modification testing. In their response to the Notice of Violation and request for additional information dated October 31, 1986 (RIM L44 861031 805), TVA committed to conducting a review of all work plans issued subsequent to the Post Modifications Task Force review. The results were reviewed by the NRC during special testing inspections conducted March 16-27, 1987, and April 13-17, 1987, (Inspection Report 50-327,328/87-18). The TVA review identified approximately 175 Engineering Change Notices (ECNs) that did not specify adequate functional testing requirements. Of these 175 ECNs, 60 were found to have been tested by a subsequent test although not as a result of the modification. The remaining (approximately 115) modifications were determined to need additional testing to verify and document functional operability of the equipment involved. The TVA systems engineering group is coordinating with the engineering group to schedule and complete testing. Subsequent to the October 31, 1986 letter, TVA has determined that other functional tests should be coordinated oy this group. The current number of - _ _ _ _ - _ _ _ . _

.. . _ - _ - 1 28 ' . . tests that have been identified is 148 electrical and 13 mechanical. Currently 96 electrical and 2 mechanical test have been performed and additional testing is scheduled on the plants P-2 schedule. Five of these test will be performed subsequent to plant heatup. The inspector will follow the scheduled testing and will verify that the five tests scheduled subsequent to heatup are properly coordinated and support TS operability requirements. c. Conduct.of Testing During this inspection period, the inspector was requested to review the licensee's commitment on qualifications and training of testing- personnel. This review was prompted, in part, as a result of the surveillance inspection (Inspection Report 327,328/87-36) where the inspectors determined that the personnel performing several tests may not be adequately trained / qualified to perform those tests. As a result of the inspectors' observations on test conduct / control, TVA decided to establish a Task Force to review the qualification and i ' training of test personnel. The inspector reviewed the licensee ' commitments on training and qualification of testing personnel contained in the TVA QA topical report TVA-7R75-1A Revision 9. Table 17D-2 of the report lists an alternate commitment to Regulatory Guide 1.58, revision 1, " Qualification of Nuclear Power Plant Inspection, Examination, and Testing Personnel". TVA stated that personnel qualification would be established by job description. The inspector determined through further review that revision 1 to Regulatory Guide 1.58 excluded preoperational, startup, and operational test personnel from the requirements of ANSI N45.2.6-1978. This revision of the regulatory guide did however, indicate that these requirements were being incorporated into a revision to Regulatory Guide 1.8, " Personnel Selection and Training". When the inspector reviewed the licensee's commitment to Regulatory Guide 1.8 in Table 17D-2 of the QA Topical Report, it was noted that the licensee only committed to revision 1 which endorses ANSI N18.1-1971. This standard does not provide specific requirements for testing personnel. A more appropriate revision of ANSI N18.1 would have been the superseding ANSI /ANS 3.1-1981 which does specify qualification and training requirements for testing personnel. The inspector requested a discussion with TVA QA personnel and requested two examples of the qualification and training records for personnel performing testing activities at Sequoyah. This item is identified as unresolved item 327,328/87-30-05 pending review of the results of the TVA Task Force and pending discussion with QA personnel and review of qualification / training records. 14. Independent Inspection a. During 1984 the licensee replaced the auxiliary feedwater pressure -. _ _ _ _ _ _ - _ - - _ _ - _ _ - _____ . _ - _ _ - _ _ _ _ _ - _ _ _ -

-- _ . - . 29 ' control' valves with cavitatirg venturis. As a result of this. modification the system ' flow resistances were increased and the differential pressure values specified in the TS for proving operability were no longer applicable. The differential pressure . requirements to deliver the same amount of flow to the steam generators was increased as a result of this modification. During the post modification testing of the cavitating venturis the licensee determined that the 2A-A auxiliary feedwater pump would not deliver 440 gpm to the steam generators e a result of the increased flow resistance created by the installation of the cavitating venturi. The licensee performed an evaluation and determined that 400 gpm would be an acceptable value. The licensee declared the 2A-A auxiliary feedwater pump operable baM on this analysis and. returned the unit to power operation. Although the TS for the AFW system does not specify a flow rate, the bases for the AFW system states that the value required is 440 gpm. The DP values specified in TS were also based on a 440 gpm flowrate. 10 CFR 50.59 states that the licensee may make changes to the facility without prior commission approval unless it involves a change to the TS or an unreviewed safety question. 10 CFR 50.59 also states that a change shall be deemed to- be an unreviewed safety question if the margin of safety as defined in the basis for any TS is reduced. The licensee submitted a TS change to the NRC to delete the DP requirements from the TS. This change 'was denied by the NRC and the licensee is in the process of making another submittal. This item is identified as unresolved item 50-327,328/87-30-10 pending further NRC review. b. During a review of potentially reportable occurrence (PRO) reports the inspector observed that the heatup rate specified in TS 3.4.9.1 is not consistent with TS figure 3.4-2. TS 3.4.9.1.a states temperature and pressure shall be limited in accordance with the limit lines shown on figure 3.4-2 during heatup with a maximum heatup of 100 degrees in any one hour period. Figure 3.4-2 limits the heatup rate to 60 degrees an hour. This item is identified as l unresolved item 50-327,328/87-30-08 pending further NRC review. 15. Functional Testing Review (61726, 61700) ] a. On April 28, 1987, the inspector observed preventive maintenance (PM) procedure 1897-087, " Accumulator Isolation Valve Low Level Activation i Level Switches", which is performed in accordance with SI-196, i " Periodic Calibration of Upper Head Injection System. { Instrumentation" The PM package requires the instrument technician i to establish 767 psig pressure in the system and then to increase { slowly the differential pressure toward the setpoint (129.12 ,+ 1 l inches of water). The switch was wired to a flashlight for testing ! continuity. when the switch closes. The differential pressure is ! increased and when the switch actuates the flashlight comes on. On j the first run the differential pressure was increasec to 141" without I actuating the switch. The instrument technician rcn the pressure L down to 90" and checked the wiring for adequate connection. The 1

____ _ ____ _ __ I a 30 -i technician then began to gradually increase the differential-pressure and the flashlight was illuminated at 124.60". Three additional runs were performed to ensure the accuracy of the test results ( which were out of the TS limits); the additional actuation setpoints -were 123.36", 123.76" and 123.79" water respectively. The technicians stated that the switches had been out of calibration on 'every performance of the PM since they were installed. The inspector questioned the adequacy of the test. The following weekend, as previously scheduled, the licensee brought in the vendor _ representative to determine the cause of the high out-of-tolerance rate. The vendor representative stated that although it is not stated in the vendor manual, the dif ferential pressure should be reset to zero each time the switch is tested. This technique is included in the new SI, and the switches have not been found out-of-tolerance since, The inspector had no further questions. b. On May 7, 1987, the-inspector observed portions of the performance of SI-689, " Auxiliary Control Air Operability Test." The test was being performed with ICF 87-548 to correct problems with the valves to be used in the test. This SI was designed to demonstrate the operability of the auxiliary control air system. The test also provides set point data for start of the auxiliary air compressors (train A and B) and closure of two normal control air isolation valves FCV-32-82 (train A) and FCV-32-85 (train B). The instruction was used to gather dew point data at various locations for information only and can also be used to perform post maintenance leak tests. The test was stopped twice for coordination problems; however, the procedure appeared to be adequate to perform the test. Personnel were following procedure. The inspector had no further questions. c. On April 30, 1987, the inspector observed portions of testing performed under WR B233555 on diesel generator (DG) 1A-A. The WR discussed work under the recommendations of the vendor representative and in accordance with the vendor manual. The vendor manual was not available at the work site; however, the vendor representative was at the work site. The vendor representative determined that the IA-A DG had a problem with the minimum / maximum voltage circuit card that had previously been identified in the 2A-A DG. This problem had caused the DG to be inoperable. The inspector questioned the continued operability of the "B" train DGs. The licensee under the guidance of the vendor representative removed these cards completely from all four DGs. The question of DG operability and utilization of the vendor manual will be followed by the inspectors as URI 327, 328/87-30-06. d. On April 23, 1987, the inspector reviewed special test instruction STI-17, "DC High Voltage Test for Selected 1E Cables in Vertical Drop Configuration." l

_--__-_______

- - _ _ l' 1 31 The objective of this test was to demonstrate, by performance of DC high voltage tests the integrity of the insulation on selected representative cables installed in conduits. The test is being performed to satisfy concerns identified by the NRC in a Technical Evaluation Report (TER) on Sequoyah nuclear plant cable pulling concerns. These concerns address the potential for cable damage due to the weight of cables being supported by 90 degree condulets on conduit tees. To demonstrate the integrity of the vertical cables, a. worst case conduit and cable installation was selected to have a dc high potential test performed on the cables in the conduit. The magnitude of the dc voltage test was in accordance with that specified for such testing in IEEE Standard 383-1974. The test program had been evaluated by TVA and had been determined to have no short or long term effects on the cables or raceways involved. TVA stated that successful completion of this test program on representative cables would demonstrate the adequacy, with respect to the issues identified above, of all Unit 2 cables . previously. installed at Sequoyah. STI-17 tested cables with 16 single conductor jackets running through the worst-case vertical drop conduit in the Unit 2 containment. During the test, 12 of the conductors clearly passed the acceptance criteria. Three conductors failed to pass by breaking down at higher voltages. The sixteenth conductor passed the acceptance criteria, but with very high leakage currents. This last cable will be referred to as " suspect." On April 24, 1987, the inspector accompanied a licensee team con- ducting a walkdown of the test boundary. The purpose of the walkdown was to determine appropriate troubleshooting activitie to determine the possible failure mode. During this walkdown it was noted that the cables under test had not been totally disconnected from the rest of the circuit. Two of the conductors that failed and the one that was suspect were still connected'to Conax brand connectors. These connectors had pigtails with only 9mm of insulation as opposed to the 45mm of insulation on the other cables under test. The licensee contacted the vendor (Conax) and determined that the connectors could not withstand the voltages used to test the conductors. TS 6.8.1 states that written procedures shall be established, implemented and maintained covering surveillance and test activities of safety related equipment. Contrary to the above, on April 22, 1987, STI-17 was performed to test certain silicone rubber insulated > conductors without requiring the technicians to disconnect the lower rated Conax connectors that were inadvertently left in the circuit. This is a violation 327,328/87-30-07. - _ - - - - _ - - .

_ - _ - _ - 32 The licensee prepared ICF 87-515 to STI-17, and it was PORC approved on April 28, 1987, in order to retest the 4 conductors neted to have problems without the Conax connectors in se-ies. The test showed similar results vi conductor breakdown. The licensee performed several other tests un6er WRs starting on May 4, 1987.. With each test the conduit upstream of the 90 degree condulet and. before the vertical drop under test was disassembled. The outcome of the test ultimately showed that there was no cable damage caused by the weight of the cable at the point of support. The . breakdown was determined by the licensee to be occurring at a location other than the point of support. The- damaged cables were removed and sent to the University of Connecticut for evaluation of the failure mechanism. The mechanism identified will be addressed as a separate issue under the cable pulling test program. The licensee stated that they will replace the damaged cable and the affected Conax connectors prior to restart of Unit 2. The licensee's cable testing effort is currently under NRC evaluation for adequacy. e. On May 7,1987, the inspector observed testing performed under WP 12340. The test involved functional testing of safety injection system valves 2-FCV-63-112 and 2-FCV-63-167. Procedures were followed, the technicians appeared to be knowledgeable of their work, and the valves were tested adequately. The inspector had no further questions. f. On May 7, 1987, the inspector observed testing being performed under WR B233992. The WR stated that all meteorological monitoring instruments were giving intermittent false indication. The testing performed was non-CSSC and was not greatly involved. The technicians were following procedures and appeared to be knowledgeable about their work. The inspector had no further questions. g. On May 12, 1987, the inspector observed testing being performed under work plan 12245. The tests were to verify proper function cf the resistance temperature devices following terminal block replacement per ECN 6779. The inspector observed testing of 1-TE-68-56B and 2-TE-68-28. The acceptance criteria for the test was met and the M&TE number was recorded for future refercnce. h. On May 15, 1987, the inspector observed functional testing performed under WP 12465. This test checked the operability of the 2B-B 714 foot elevation pipe chase cooler. ECN L6835 replaced several power supply cables for ampacity concerns. The inspector questioned the test director because the testing steps of the coolers were not performed in sequence. The procedures stated that the steps of the i work plan could be performed in any order with the cognizant engineers approval. l _ _ _ _ _ _ _ _ _ _ -

- - _ - _ _ _ - _ _ - - - - - -- -_ 33 < i. On May 16, 1987, the inspector observed testing in progress under WP 12457. The test was written to verify proper operation of the refueling water purification pump. The test on the non-CSSC pump was performed utilizing new ultrasonic flow equipment. During the initial run of the test, this flov equipment gave opposite indication of that shown by downstream pressure indication. The test director cancelled the test until such time that the problem could be identified. The inspector had no further questions. j. On May 16, 1987, the inspector observed testing being performed under .WP 12193. This work plan was issued by ECN 6689 which modified the steam line power operated relief valves (PORVs). The first test (stroke time) performed on 2-PCV-1-5 was within the acceptance criteria. In the second test (controller operation) the valve opened much slower. However, this test did not have acceptance criteria, it was only performed to develop a base line on the controller. The inspector had no further questions. k. On May 18, 1987, the inspector observed portions of testing performed under WP 12456, for component cooling system (CCS) ' affle testing. o The procedure was being followed and the inspector verified portions of the valve lineups. The WP (12456) was designed to ensure that the safety-related baffle plate separating the two trains of CCS in the LCS surge tank was in place and intact. Train "B" (Unit 2) was drained to the bottom of the tank thus isolating approximately 3000 gallons of water 'on the train "A" side of the baffle plate. After draining the "B" train of CCS, the drain valve was left open to monitor for any leakage. Initially, the leakage was quite substantial. Operations personnel tightened hand operated valves in the i solation line-up, and the procedure was changed to double isolate certain lines to the tank. Following this effort the leakage was reduced to approximately 500 mi in 2 hours. The acceptance criteria for the test was no leakage. The Mechanical Testing group requested DNE to establish a less stringent acceptance c ri te ri a . The DNE engineer returned an acceptance criteria of less than 180 gallons / month leakage. This was incorporated into an instruction change form and was PORC approved. The inspector interviewed the DNE engineer on the establishment of the new acceptance criteria. The engineer stated that he knew that the leak rate was a " slow drip" and assumed that 1 liter per hour would be limiting on the leak. This calculated to be 180 gallons per month. The engineer stated that the test would be signed to verify that the baffle plate would remain intact for a 30 day period. The 180 gallons was small compared with the 3000 gallons remaining in the tank . The inspector questioned the adequacy of tne calculations. The licensee stated that the NRC had questioned the adequacy of the i ! )

_ __ k I. I l 34 l- L L baffle plate during DBVP inspections. In order to answer this question the licensee reviewed the design basis for the surge tank. The surge tank was purportedly designed to allow for NPSH of the CCS pumps. The licensee provided the inspector with calculations to show that i l NPSH can be achieved with the water level several feet below the l tank. This would remove the need for train separation in the tank. Therefore, the licensee would not be required to test the baffle plate. This item is still under review and will be tracked as URI 327,328/87-30-09. During the review of this issue with licensee engineers, it was determined that the CCS seal leakoff pumps, which return seal leakage back to the surge tank in order to facilitate CCS pump NPSH, may not be safety-related. The CCS pumps leak approximately one gallon per minute by design. This leakage is collected and pumped back to the surge tank by the seal ' leakoff pumps. Should these pumps fail ~ to perform their intended function the CCS pumps could lose NPSH within i ! a short period of time. This issue will be tracked as part of 'URI 327,328/87-30-09. 1. On May 18, 1987 the inspector observed testing being performed under SI-275.1, " Inspection of Non Class 1E Load Circuit Breakers Fed From 1E Busses - Unit 1." The testing in progress was on SQN-1-BKRB-250-NG/39, 120 VAC vital instrument board I-III, breaker -39, to the Diesel Generator Building CO2 fire protection system. The workmen appeared to be knowledgeable of the procedure. The procedure was followed step by step, and QC was involved in the reinstallation and torquing of the breakers. m. On May 20, 1987, the inspector observed testing performed under WR B 232787. The work request replaced the pump in radiation monitor 2-RM-90-14. The testing was performed in accordance with SI-206.2, " Radiation Monitoring System Sample Flow Calibrations and Functional Tests - Unit 2, 12 weeks." The procedure appeared to be well written and the technicians were following it properly. The inspector noted that the control room alarm could not be tested because 0-RA-90-12B on the common alarm had failed. The failed radiation monitor was documented on WR B230702 and the problem with the performance was written in a test deficiency. The inspector had no further questions. n. On May 21, 1987', the inspector observed portions of a motor operated valve assessment technique (MOVATS) test on 2-FCV-1-237. This test was performed under WR B211669. The valve was non-safety-related and the test wc observed for testing technique. The inspector had no further questions. o. On May 22, 1987, the inspector observed testing on SI-45.1, " Essential Raw Cooling Water Pumps." The procedure was PORC approved _ _ _ _ _ _ _ _ _ - - _ _ _ _ - _ _ _ _ _ _ _ _ _

- _ _ _ _ , - ~35 on February 20, 1986, and was performed using instruction change form (ICF) 87-214 dated April 10, 1987. At the time the inspector arrived . the test engineer stated that they were almost ready to start the P-B l pump. Shortly thereafter the test was delayed for operations to run ' t an . availability checklist prior to starting the pump. The engineers stationed at the ERCW pump house called and -stated that the test gauges had been installed on the N-B pump in error. Finally, reactor operators . stated that there were outstanding' MRs on the P-B pump's fire protection system which prohibited its starting. The decision was made to test .the N-B pump because ~it was already running and the gauges were in place. The inspector questioned the test engineer about step 4.10 in the procedure which requires the performer to " maintain bearing cooling water flow between 5 gpm and 13.5 gpm." The test engineer stated that operations personnel were responsible for that portion. When questioned the licensed operator stated that there was no indication for this flow. In the past, operations had qualitatively checked this flow and not quantitatively. During this performance attempt, there was no one to check this flow at all. The test was cancelled until this issue could be resolved. TS 6.8.1 states that written procedures shall be established,_ implemented and maintained covering surveillance and test activities of safety related equipment. 51-45.1, Essential Raw Cooling Water Pumps, requires the licensee to maintain bearing cooling water flow between 5 gpm and 13.5 gpm. Contrary to the above, on December 2,1986, December 14, 1986 and May ?2, 1987, this procedure was performed without appropriate instrumentation to perform th',s step. This is a violation; and is another example of VIO 327,3'.8/87-30-01. In addition, the same ste/ remains in the new SI that has completed the SI review process and been p0RC approved. This item was reviewed by the SI review special inspection team. p. On May 23,1987, the inspector observed portions of the preparation for the performance of SI-158.1, " Containment Isolation Valve Leak Rate Test - Units 1 or 2." The observed test was a local leak rate test of 2-CV-61-692 performed per WP 12345 which replaced the valve. The inspector verified correct system line up and that testing pressure agreed with the hydrostatic pressure on the vaive name plate. The valve failed the test and a WR was written to repair the valve. The inspector had no further questions. q. On May 27, 1987, the inspector observed the performance on SI-46.3, " Component Cooling Water Pump 2A-A." Af ter' aligning the system for - J the test the inspector questioned the operator about his concern over ' reactor coolart system (RCS) temperature during the test. The operator discnted that the "A" train of RHR was in service and that - _ - _ - - - _ _ - _ _ _ _ _ _ .

- __ -__ _ __- l 36 .an increase.of cooling water to the 2A-A heat exchanger would cause a ' decrease.in.RCS temperature. The inspector pointed out step 4.3 in the procedure which states, "If Unit is o.i RHR cooling, assure heat exchanger in use for cooling is not used for pump test." The licensed operator stated that he had not been aware of the requirement. The test was subsequently stopped and the "B" train of .RHR placed in operation for the remainder of the test. TS 6.8.1 states that written procedures shall be established, implemented and maintained covering surveillance and test activities of safety related equipment. SI-46.3, " Component Cooling Water Pump 2A-A," requires that, if the unit is on RHR cooling, assure heat exchanger in use for cooling is not used for pump test. Contrary to the above, on May 27, 1987, 51-46.3, was entered and aligned using the "A" RHR heat exchanger when- the "A" train of RHR was in service for decay heat removal. This is another example of VIO 327,328/87-30-01. The inspector has expressed concern to licensee management that the operator felt uncomfortable with the test and did not stop the test. This issue will be followed by the resident inspectors for resolution. r. On May 28, 1987, the inspector observed portions of the performance of PMI 1955-082, "2B-B DG . Actuator Inspections - CSSC." The procedure appeared to be adequate and the technicians were following it. The inspector had no further questions. s. On May 28, 1987, the inspector observed testing in progress on the 2B-B Emergency Diesel Generator. Five tests were being performed during this time frame: PM 1955-082, "2B-B D/G Actuator Inspections" SI-166.36, " Diesel Starting Air Valve Test" SI-102 M/M, " Diesel Generator Monthly Mechanical Inspections" PM 1849-082, " Diesel Generator 2-GENB-082-2B-C" SI-7, " Electrical Power System, Diesel Generators" In addition the ASE representing operations was performing S01-82. 4, " Diesel Generator 28-B, - Unit 0." SI-102 requires the mechanic to " Request operations to close the isolation valves for the air start system... for performance of steps 6.2 - 6.16." This was not accomplished. The operator isolated the start system for the performance of SI-166.36. The mechanics performing SI-102 stated that they saw the AUD closing the valves and assumed that it was being done for them. While on step 6.10 requiring the mechanic to reach into the EDG machinery, the inspector noted that the start air valves were open. The inspector immediately - _ _ - _ _ _ _ _ _ - - _ _ _ - _ - _ .

_ - _ _ _ _ _ - p L ! 37 1 l l requested the mechanic to stop the te'st and informed the operator of ' the error. The operator then re-closed the valves. When questioned, the operator stated that the technicians performing SI-166.36 had informed him that they were through with the start- , system setup and he had opened the valves. This could have allowed ! the EDG to start while a mechanic was reaching into the machine. TS 6.8.1 states. that written procedures shall be established, implemented and maintained covering surveillance and test activities of safety-related equipment. SI-102 M/M, " Diesel Generator Monthly Mechanical Inspections," requires that the air start system manual isolation valves be closed during the performance of steps 6.2 - 6.16 for personnel safety. Contrary to the above on May 28, 1987, the EDG starting air manual isolation valves were found open during the performance of SI-102 M/M step 6.10. SI-166'.36- states that, "No more than one manual isolation valve may be closed at any one time when installing pressure gauges." As- discussed above the AUD closed all the air start valves to the 2B-B EDG for the performance of this test. The mechanics involved later stated to the inspector that they had willingly violated the procedure because they knew that the EDG was inoperable and therefore it did not matter. TS 6.8.1 states that written procedures shall be established, implemented and maintained covering surveillance and test activities of safety-related equipment. SI-166.36, " Diesel Starting Air Valve Test," requires that the air start system manual isolation valves be closed one at a time when installing pressure gauges. Contrary to %e above, on May 28, 1987, an AUD isolated all four starting air valves to EDG 28-B utilizing the manual isolation valves for the installation of the portable pressure gauges. This is a violation and is a further example of 327,328/87-30-01. In addition, prior to starting the EDG the inspector discussed the performance of SI-166.36 with the mechanics. They stated that during this performance cycle they only performed part 4.2 and not part 4.1. Therefore, they had no concern with the air tanks only the inlet pressure during start. The inspector witnessed the EDG start and noted that the mechanics observed the inlet pressure only. SI-166.36 states that, "4.2.6 Verify tank pressure is recovering after air start test." This observation was not performed. The information was not required to be signed off in the data sheets. < This apparent noncompliance will be followed up as URI l 327,328/87-30-11. ) ) 1 L 1

mw, - m- _ ' , c y '* n , , f!l " . g , 38 - ,, . at. On May" 28,1987, the inspector observed portions of the performance of SI-7,- . Electrical Power System: Diesel Generators, on the 2B-B 10/G. The U0 performing the test appeared to be knowledgeable of the m _ testing requirements. (Refer to s. above to understand other work under the : AU0's preview at the time.) The inspector had questions , , about the transfer of fuel oil and_the. pressure of the lube oil. The first question was answered adequately.' The second question was on Data Sheet 3, diesel generator running condition checklist. Item a. requires : the ' operator to check that_ the lobe oil pressure is - approximately 50 psig. The inspector noted that the pressure after 15 minutes of running was 82 psig on engine 1 and 86 psig on engine 2. The AUG stated.that the pressure is "always around 80." ' The' inspector requested that the licensee management determine if 80, psig is acceptable, and if it is to ensure that procedures are . appropriately upgraded. The resident inspectors will follow this item. 3- On May '28, 1987, the' inspector observed portions of-the performance ' u. of ' PM 1849-082, " Diesel Generator 2-GENB-082-28-2." This predictive maintenance procedure pr.imarily took die:el generator trending data following the maintenance performed. The technicians were following the. procedure and the procedure appeared to be adequate for the work involved. The inspector had no further questions, v. On May.-28, 1987, the inspector observed testing accomplished under WR B233351~ ' The PMT performed following the work was to calibrate . LT-TI-410 on the reactor and auxiliary, building floor and equipment drain sump per 51-85, " Channel . Calibration of the Containment Sump . Level and Flow Monitoring Instrumentation in the Reactor Coolant System Leakage Detection System (Refueling Outage), Unit 1." The procedure then required the technicians to check the tolerance of the redunoant channels to verify that they are within the acceptance criteria of TI-56, " Listing of TS Instruments - Units 1 and 2." The technicians were. following the procedure and the written procedure appeared to be adequate to control the testing. The inspector had no further questions. w. On May 29, 1987, the inspector observed testing performed under WP 12298 following cable reroutes in the Unit 2 west valve room. The test observed verified proper functioning of 2-FCV-1-16. The .following items were not followed appropriately: step 5. Start handcranking 2-FCV-1-16 to the open position. At approximately' 5*J valve travel from the closed position, verify the red and green lights are on. ! - - - - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - _ _ - ---

g -- - --- l9 J t , ' l'[j. ' , $W 39 ' o f _.k ' '. ' step 6,: Continue: handcranking 2-FCV-1-16 to the: open position. At' ' > t ~approximately 95*4 valve - travel from the close position, verify the following: ' Red < light'on, green light off , . Status monitor relay Al-6 is de-energized. Status monitor relay Al-5 is still energized. < Open motor: starter has dropped'out. , - At the beginning of step 5',- the operator opened the valve to full open. No indication was-made of 5*6 or 95% testing and the number of turns to.100%.was not indicated, step 9. With. the' close motor' starter still picked up, verify the following sequence of-steps for 2-FCV-1-16. a. Momentarily open the contacts on limit switch -(LS)-8 and verify the close motor starter does not drop out. . b. Momentarily open' the. torque' switch close contacts and verify the close motor starter does not drop out. c. Simultaneously open the contacts on LS-S and the torque switch close contacts and verify the close motor starter drops out. During the performance of step 9.a, the technician opened a LS and j verified by radio that the close motor starter did not drop out. In 9.b, ' h'e ' opened the torque switch close contacts and verified the close ' motor starter did not dropout. In 9.c, the two contacts discussed above were opened and the-starter again failed to drop out. A quick teview determined that the contacts opened in step 9.a were not'the LS-8 contacts required. Steps 9.a - 9.c were repeated using the correct contacts. A test deficiency was not written against this testing problem. 1

.The engineers. involved stated to the inspector that the reason that the wrong limit switch was opened was that the last valve they had tested (a few hours earlier) had required LS-15 to be opened. The operator had simply opened the one that he had earlier. The inspector stressed the fact that attention to detail in following procedures would have prevented this occurrence. Contrary to the. above, on May 29, 1987, steps 5 and 6 were performed y' with ' the valve being operated manually without indication of the approximate valve position. O Also, contrary to the above, on May 29, 1987, steps 9.a and 9.c were . performed - utilizing the wrong limit switch contacts and a test deficiency was not written. This is an example of VIO I -327,328/87-30-07. Cu_ = i= _ _ __ _ -.

_. _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ 40 x. On May 29, 1987, the inspector observed testing in progress under SI-196, " Periodic Calibration of Upper Head Injection System Instrumentation, Revision 9." The portion observed was Section VI, UHI valve stroke timing on valve 2-FCV-87-21. The test was performed and the valve was recalibrates and left within calibrated. Step 3.4 in SI-196 states that, "The automatic valve closure response time test is to be performed on only one hydraulic isolation valve at a time. The three (3) valves not under test should be closed, gagged, and the gag motors de-energized.- During the test the inspector questioned the instrument technicians on the above requirement. They stated that they were not familiar with it and that operations would know. The inspector proceeded to the control room and ascertained that the gag motor for valve 2-FCV-87- 21 was de-energizcd. However, gags for valves 2-FCV-87-22, 23 and 24 (the "three (3) valves not under test") were closed, but power was not removed. T.S. 6.8.1 states that written procedures shall be established, implemented and maintained covering surveillance and test activities of safety related equipment. SI-196, Step 3.4 states that during the performance of the stroke timing test, "The +hree (3) valves not under test should be closed, gagged, and the gag motors de-energized. Contrary to the above, during a May 27, 1987 performance of SI-196 valve- 2-FCV-87-21 was tested in Section VI of the procedure and the gag motors to 2-FCV-87-22, 23 and 24 were not de-energized. This is a violation and an example of 327,328/87-30-07. y. On June 2,1987, the inspector observed portions of the performance of SI-90.62, " Reactor Trip /ESF Instrumentation Quarterly Functional Tests (Rack 11)." This SI is the implementing document for IMI-99, "FT 7.8, Functional Test of Steam Generator Level Channel III Rack 11 L-538 L-3-97." The procedure had been through the 11censee's on going SI review program. Technicians appeared to be knowledgeable in their work, and followed the procedure. IMI-99 FT 7.8 is a " stand alone" document and does not require additional implementing procedures. The inspector had no further questions. z. On June 4,1987, the inspector observed portions of the performance of STI-61, " Flow Balance of Certain ERCW Heat Exchangers." This test was performed in order to develop excess ERCW flow data for the complete performance of SI-566, "ERCW Flow Verification Test, Units 1 and 2." l In preparation for testing the ERCW flow in the "A" CCS and AFW pumps spare cooler, the engineer found 1-FCV-67-162 was closed. The AVO, l under the direction of the SE, isolated space cooler "B" and placed space cooler "A" in service. The start sequence of the cooler caused l 1-FUV-67-162 to open. This manipulation was not specified in the - __________________--____-__ _ -

- _ _ - _ _ _ _ - - _ _ _ ! 41 procedure, nor was it prohibited. The change was made with the approval of the Shift Engineer. 16. Enforcement Conference a. Summary On June 18, 1987, an enforcement conference was neld in the Region II Office between the Office of Special Projects - NRC and Representatives of Sequoyah Nuclear Plant - TVA. The purpose of the meeting was to discuss observed inadequacies in implementation of procedures, which demonstrated a lack of control over testing evolutions and system and equipment status. Examples of such deficiencies (provided to TVA via the proposed meeting agenda of June 11, 1987) included the RCS spill events of February 1, 1987, and April 29, 1987; the May 28, 1987, performance of Diesel Generator (DG) testing per SI-102 M/M and 51-166.36; and performances of S1-45.1 (ERCW Pump Testing), SI-46.3 (CCS Pump Testing), and 51-102 E/SA (DG Testing) which occurred between May 6 - June 5, 1987. NRC opened the meeting by telling TVA that although the events identified in the proposed meeting agenda have small significance when looked at individually, as a whole they give cause for concern over TVA's control of operational activities at Sequoyah. TVA acknowledged NRC's reason for concern, stating that the overall problem could be attributed to the broad category of inattention to detail. Due to concerns of their own, TVA indicated that both PORS and NMRG reviews were initiated to look into the RCS spill events. Additionally, as a result of the recent NRC SSOMI findings in the sea of testing, a testing task force was established to look into testing related problems. The findings of. these TVA groups were presented to be: (1) operation with inadequate procedures or lack of procedures; (2) operator's non-compliance with configuration control; (3) insufficient supervisory involvement; and (4) testing programs not well defined as far as testing responsibility, awareness, and conduct. In response to these findings, TVA indicated that they took the following actions to improve performance: (1) conducted operations lessons learned meetings, emphasizing operations control and responsibility of activities, discussing each spill event, reviewing plant configuration requirements, as well as discussing prompt root cause assessment; (2) conducted procedure adherence training to over 950 people; (3) established a daily work list to ' ensure a manageable work schedule with integrated work activities; and (4) established conduct of testing guide lines which include the test director concept, use of test director logs and implementing procedures. Having seen the failure of other well intended TVA programs, NRC questioned the effectiveness of the ones described. In response, TVA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -

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l stated that program follow-up would take place through: (1) the previously planned QA restart review of operations, which includes L control of operational activities and management control; (2) the l P0RS surveillance program which is to involve observation of control- l room activities; and (3) an increase in management involvement aided by management observation training, coaching, and stressed team work. ' To ensure that NRC and TVA saw the events in the proposed meeting agenda in the same light, and to determine if TVA's intended correc- tive actions were all encompassing, each event was discussed in detail. With the exception of TVA's use of hold orders, both parties were in agreement. NRC stated that they felt the hold order pro- cedure at Sequoyah was inadequate, but would consider TVA's arguments to the contrary. The NRC has since concluded that Sequoyah failed to properly implement its clearance procedure. Additionally, the l importance of informing NRC of significant events, .such as the RCS spill of April 29, 1987, was also discussed. TVA was in agreement, and assured NRC that they would be notified of all such events in the , I future. NRC closed the conference by thanking TVA for the time and effort they put into preparing for the meeting, and told them that they would be informed at a later date of any enforcement action that may result, b. Attendees TVA: C. C. Mason, Deputy Manager, Office of Nuclear Power H. L. Abercrombie, Site Director L. M. Nobles, Plant Manager R. L. Gridley, Manager, TVA Licensing J. M. Anthony, Manager, Operations Group J. D. Patrick, Shift Engineer J. L. Hamilton, Manager, Quality Engineering and Control G. B. Kirk, Compliance Supervisor R. H. Buchholz, Sequoyah Site Representative H. H. Gammage, Plant Operations Review Staff (PORS) H. R. Rogers, Supervisor, Plant Reporting Section, PORS M. B. Whitiker, Deputy Director, Nuclear Safety and Licensing M. Cooper, Compliance, Site Licensing T. J. McGrath, Assistant Site Representative NRC: J. A. Axelrad, Deputy Director, Office of Special Projects (OSP) S. D. Richardson, Deputy Director, Division of TVA Projects (DTVA), OSP G. G. Zech, Assistant Director, Inspection Programs, DTVA, OSP K. P. Barr, Deputy Assistant Director, Inspection Programs, , DTVA, OSP ! J. N. Donahew, Branch Chief, TVA Projects Staff, DTVA, OSP _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _

_ _ _ _ _ _ _ 43 F. R. McCoy, Section Chief, Sequoyah R. E. Carroll, Project Engineer, Sequoyah i K. M. Jenison, Senior Resident Inspector, Sequoyah M. W. Branch, Restart Coordinator, Sequoyah P. E. Harmon, Resident Inspector, Sequoyah D. P. Loveless, Resident Inspector, Sequoyah S. A. Elrod, Section Chief, Watts Bar G. K. Hunegs, Project Engineer, Watts Bar G. L. Paulk, Senior Resident Inspector, Browns Ferry P. A. Taylor, Reactor Inspector, Test Programs, RII Attachment: TVA Meeting Discussion Handout

, _ _ _ _ - - - - - - _ _ _ _ . . - - - - _ - - - - . - - _ _ _ _ _ _ _ _ _ _ l ! ATTACHME_N.T_ TVA Meeting Discussion Handout - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

E C N E Y R T T I E R N F O A H L N 7 T P O 8 U R C 9 A A 1 T Y EL E N 8 L C , E L U 1 A N M V E E H C N E A E Y R U S O O J S U F E Q N N E N E S E T C R N ' . I

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