IR 05000289/1985022

Special Safety Insp Rept 50-289/85-22 on 850916-1011. Violation Noted:Improper Storage of Scaffolding in safety- Related Area

ML20209H369
Person / Time
Site:	Three Mile Island
Issue date:	10/30/1985
From:	Conte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20209H328	List: IR 05000289/1985022 IR 05000916/2010011 ML20209H324
References
50-289-85-22, NUDOCS 8511110082
Download: ML20209H369 (44)

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o U.S. NUCLEAR REGULATORY COMMISSION I "

REGION I

Report N '50-289/85-22-Docket-N License N _DPR-50 Priority -- Category C

. Licensee .GPU Nuclear Corporation Post Office Box 480 Middletown, Pennsylvania 17057 Facility At: Three Mile Island Nuclear Station, Unit 1

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Inspection At: Middletown, Pennsylvania

' Inspection Conducted: September 16, 1985 - October 11, 1985 Inspectore: W. Baunack, Project Engineer, Region I N. Blumberg, Lead Reactor Engineer, Region I J.' Bryant, Senior _ Resident Inspector (Oconee), Region I N. Dudley, Lead Reactor Engineer (Examiner), Region ~I ,

D. Haverkamp, Technical Assistant for TMI-1 Restart, Region I

W. Johnson, Senior Resident Inspector (Arkansas) - '

Region IV M. Schaeffer,--Reactor Engineer, Region I D. Trimble, Resident Inspector (Calvert Cliffs), Region I R. Urban,-Reactor Engineer, Region I D. Vito, Senior Emergency Specialist, Region I

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P. Wen, Reactor Engineer, Region I 4 F. Young, Resident Inspector (TMI-1), Region I- i

. Approved By:

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R. Conte, TMI-1 Restart Manager N'/h/

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4 TMI-1 Restart Staff 4 Division of Reactor Projects

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la Inspection Summary:

Routine and special (NRC shift coverage) safety inspection (683 hours0.00791 days <br />0.19 hours <br />0.00113 weeks <br />2.598815e-4 months <br />) of hot shutdown activities in preparation for restart and low power operations, including operator and management performance, related preoperational and startup testing, malfunction of a reactor protection system breaker, decay heat pump operability, and the overall readiness of the facility and licensee management for restar Inspection Results:

Operators were knowledgeable of the plant design and current shift status and they were responsive to off-normal alarms and events. In general, procedures were properly implemented. There was an apparent procedure violation with respect to the proper storage of equipment in a safety-related area (paragraph 3.2.5.3). The team concept was evident with definite signs of upper management attentiveness and involvement in daily activities. The material condition of the facility has had a minimal effect on the startup test progra In general, the testing program is proceeding on schedule. Some interface problems existed between operators and test engineers as the organization came together to start working on shift and at a more intensive pace. Although some test procedure deficiencies existed, in general, these procedures were adequate to control the tests or evolutions. The licensee made extensive use of briefing sessions. Some of these briefings could have been better planned with respect to discussion of potential off-normal condition Notwithstanding the above, the test procedures were properly implemente Licensee handling.of the reactor protection system breaker malfunction was-appropriate with a technically-sound resolution proposed aad implemented. The actuation of the safety valves on the steam supply lips to the turbine-driven emergency feedwater pump was a significant finding for which the licensee provided sufficient interim corrective action until a long-term solution can-be achieved. Surveillance and maintenance data substantiate operability of the decay heat removal pumps. Licensee management sufficiently prepared the facility, operators and themselves for restar I l

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i-DETAILS

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1. Introduction and Overvie .

1.1 General At.the beginning of this inspection period on September 16, 1985, the TMI-1 Restart staff'was providing routine inspection coverage of 1 facility operations. ~ The plant was then at normal _ hot shutdown-

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conditions (reactor coolant. system'near 530F and 2155 psig) to

- maintain restart readiness'and continue operator training pending further action by the U.S. Court of Appeals for the Third Circuit in Philadelphia, Pennsylvania. On September 19,fl985,.the-Court ordered that the existing stay of the Commission's Restart Order (CLI-85-09) be lifted, effective 4:00 p.m. on September 25, 1985,~

thereby permitting restart.. Howeverr additional appeals were filed'

- with the Supreme Court of the United States, and on the afternoon of'

September 24, 1985, a Supreme Court Justice extended the stay of the Commission's Restart Order.' At 8:00 a.m. on September 24, 1985, in _

. preparation for restart, the TMI-1 Restart Staff had resumed around-cthe-clock coverage to assess restart readiness. This augmented inspection effort was maintained for 82 hours9.490741e-4 days <br />0.0228 hours <br />1.35582e-4 weeks <br />3.1201e-5 months <br />, pending furthe action by the Supreme Court, but was returned to routine inspection coverage at 6:00 p.m. on September 27, 1985, as a result of the extended sta On October 2, 1985, the Supreme Court lifted the stay of.the

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Commission's Restart Order, thereby authorizing the restart of TMI-1. By letter dated October 2, 1985, from H. R. Denton, Director, Office of. Nuclear Reactor Regulation to H. D. Hukill, Vic President and Director, TMI-1, the NRC staff authorized TMI-1 to operate,: subject .to certain conditions imposed in the restart proceeding. At 4:00 a.m. on October.3,'1985, we again resumed shift

. inspector coverage. This continuous-observation of plant activities

- was maintained by inspectors from Regions I, II:and IV for 196 hours0.00227 days <br />0.0544 hours <br />3.240741e-4 weeks <br />7.4578e-5 months <br />

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throughout the remainder of the inspection period,-which ended at 7:00 a.m. on 0ctober 11, 198 Based on the TMI-1 Restart Staff's evaluation of plant readiness'and the recommendation of the Director, TMI-1 Restart-Staff, as

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described'in a memorandum to T. E. Murley, Regional Administrator,-

Region I, dated October 3, 1985, the Regional Administrator authorized the licensee to.take the reactor critical and proceed with its approved test program up to 5% of' rated power. ~ Based on a

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'similar recommendation of the Director, TMI-1 Restart Staff,'on

' October 8. 1985, as described in a memorandum to T. E. Murley, dated-October 10, 1985, the Regional Administrator authorized the licensee to proceed with the test program up to the next hold point, which is-

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the return to power operation following a planned trip at 40% of rated powe _

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1.2 Facility Restart Operations

During the period of October 3-11, 1985, the significant THI-1 restart operational milestones included: (1) taking the reactor critical, (2) completing low power physics testing, (3) completing natural circulation testing to obtain plant thermal performance data and to provide training to reactor operators, and (4) completing initial main turbine generator testing and electric power generation up'to.15% of rated power. 'The chronological summary of plant operations during this period is listed belo Date Time Operational Highlight or Milestone 10/3/85 4:48 Control rods withdrawn in preparation for criticality 5:50 Began deboration for criticality 10:19 Region I Administrator authorized the licensee to take the reactor critical and proceed with the test program up to 5% of rated power 1:30 Reactor declared critical 10:25 Increased power to point of adding sensible heat and initiated reactor physics data collection; 3.2 E-7 amps on NI-3 and 2.5 E-7 amps on NI-4 L10/5/85 11:30 Completed zero power physics testing

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which included a successful reactor trip and restart as a part of shutdown margin calculations

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10/6/85 1:45 Increased power to 3%

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.:37 Stopped reactor coolant pumps for natural circulation testing

'2:24 Restarted reactor coolant pumps Stopped reactor coolant pumps for second

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4:45 natural circulation test 7:35 ~ Lost natural circulation flow during'a special test evolution to determine the steam generator level at which natural circulation is lost 8:37; While recovering from natural circulation, the flow transient caused the main steam safety valves on the "A" OTSG to lift at 1040 psig for less than 10 seconds

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10/8/85 11:30 Region I Administrator authorized the licensee to proceed with the test program up to the next hold point, i.e. return to power operation following a planned trip at 40% of rated power 11:45 Rolled the main turbine 10/9/85 4:01 After completing preoperational testing of the main turbine generator, connected the generator to the regional electric grid at 12% of rated power and then increased power to 15%

-10/11/85 7:00 At the end of this insrection period the reactor was at 15% of rated power, reactor coolant average temperature was 567 F and pressure was 2155 psig 1.3- Operational' Events Four events occurred during this inspection period that were considered either operationally significant or were matters of special interest to the TMI-1 Restart Staff. _These events are summarized belo Date Operational Event 9/23/85 Electrical fire occurred in one of two a-c breakers for the reactor protection system, while the plant was in hot shut-

'down 10/3/85 Unsubstantiated bomb threat received by facility via local law enforcement agency 10/3/85 One of two intermediate range channels became inoperable

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10/9/85 Steam leak identified in a 1-inch drain'

line from a main turbine control valve 1.4 Summary This inspection included an initial period of continued hot shutdown plant operation, pending sequential actions being taken by both the Third Circuit Court of Appeals and the Supreme Court, and periods of prompt but' deliberate responses to the various court actions taken-t by the licensee. The THI-1 Restart Staff remained sensitive to an adverse impact on shift supervisor safety duties due to NRC shift L _ .

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' inspector questioning and discussion on matters of a programmatic nature. Accordingly, the shift inspectors referred only implementa-tion matters or status questions to the shift supervisor and referred programmatic (event followup, design, or procedure adequacy problems) to resident and region-based NRC personnel. Resident and region-based personnel interfaced primarily with licensee support groups in followup to shift inspector referrals / concerns. The staff's observations and findings regarding normal shutdown plant operations, reactor-criticality and low power operation and testing, and licensee response to operational events is discussed in the report sections that follo . Shift Inspection Activities 2.1J Scope of Review and Observations on September 24-27, 1985, and again on October 3-11, 1985, the TMI-1 Restart Staff resumed its augmented shift inspection coverag The NRC shift-inspectors assessed the adequacy and effectiveness of operating personnel performance, based on the inspectors'

observations of preoperational and startup activities to determine that:

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operators are attentive and responsive to plant parameters and conditions;

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plant evolutions and testing are planned and properly authorized;

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procedures are used and followed as required by plant policy;

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equipment status changes are appropriately documented and communicated to appropriate shift personnel;

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the operating conditions of plant equipment.are effectively monitored, and appropriate corrective action is initiated when required;

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backup instrumentation, measurements, and readings are used as appropriate when normal instrumentation is found to be defective or out of tolerance;

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logkeeping is timely, accurate, and adequately reflects plant activities and status;

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operators follow good operating practices in conducting plant operations; and,

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operator actions are consistent with performance-oriented trainin Shift inspectors also assisted in the overall restart readiness

. review (described in paragraph 7) by conducting selected valve and

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breaker-lineup verifications of diesel generator systems and breaker lineup verifications of-emergency electrical system The~ shift inspectors' observations included, but_were not limited to, those shutdown facility operations, reactor plant startup and ,

testing operations, periodic' surveillance activities, and preventive l and corrective maintenance activities listed belo Shutdown Facility Operations

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routine control room activities

- once through steam generator (OTSG) steaming maneuver (level changes) using turbine bypass valves

-- control rod operation

-- annunciator alarm response

-- condenser vacuum pump startup and operation

-- reactor coolant drain tank oxygen concentration reduction and in-leakage control crew drill of loss of instrument air and cooldown from

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outside main control room

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crew drill on control room evacuation

-- reactor building ~ purging operations

-- Hurricane Gloria weather monitoring and flash flood watch anticipatory actions

-- . pre-critical checklist completion Reactor Plant Startup and Testina Operations

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routine control. room activities

-- withdrawal of control rods for restart sequence

-- deboration to criticality

-- annunicator alarm response

--- zero power physics testing (ZPPT) for cource range /

intermediate range overlap, source range high voltage cutoff, determination of sensible heat, et reactimeter operational checks for ZPPT

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shift crew drills

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' moderator temperature coefficient testing

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control rod worth testing

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shutdown margin verification

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. isothermal temperature coefficient measurements

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ejected control rod worth measurements

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manual reactor trip test

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reactor startups_per approach to criticality procedure

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hydrogen addition to turbine generator

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makeup tank boron addition

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loss of reactor coolant (natural circulation) test preparations

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reactor protection trip setpoint adjustments

-- main feedwater pump trip and emergency feedwater system initiation test

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loss of instrument air test

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installation of jumpers and resetting of low pressure trip setpoints

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restart of reactor coolant pumps following natural circulation testing

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shift from emergency feedwater to main feedwater following natural circulation testing

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removal of jumpers and resetting of reactor protection system trip setpoints.

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power level increase to 10% of rated power

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integrated control system (ICS) tuning

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periodic inspection observation tours of areas outside control room, including diesel generator rooms, emergency feedwater rooms, control building, turbine building, auxiliary building, intermediate building, electrical switchgear rooms, and outside buildings and yard areas

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turbine rolling and startup operations

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. adjustment of power range nuclear instruments to primary heat balance calculation idiscussions with shift technical advisor regarding ATOG procedures for excessive cooling and steam generator tube rupture

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routine control room operations at 15% of rated power

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caution tag posting and administrative controls'

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water addition from reclaimed water storage tank to the'B core flood tank, conducted by an auxiliary operator

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-primary auxiliary operator routine checks and log readings

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outbuildings: auxiliary operator routine checks and log readings Periodic Surveillance Activities

. September 24-27, 1985

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reactor coolant system (RCS) leakage measurements

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main' steam isolation valves quarterly valve cycling

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lhigh pressure _ injection and low pressure injection analog channels check / calibration October 3-11, 1985:

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routine shift checks

-. motor-driven emergency feedwater pump functional test

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control rod movement verification

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RCS leakage measurements

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RCS heat balance calculations Preventive and Corrective Maintenance Activities September 24-27, 1985

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reactor building ventilation stack radiation monitor (RM-A'-9) gas sampler 0-ring replacement

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reactor protection system breaker replacement

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installation of isolation transformer for reactor coolant ;

pump power monitor. input to void fraction calculation for safety parameter display system L

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turbine-driven auxiliary feedwater pump packing ring removal

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4kv bus over-voltage trip relay dead band adjustment

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main condenser exhaust radiation monitor check source-repairs

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nuclear instrumentation source range channel erratic indication troubleshooting

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October 3-11, 1985

-- nuclear instrumentation intermediate range channel power supply failure troubleshooting and repair

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group 7, rod 5, position indication faulty reed switch troubleshooting

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temporary repair of weld leak on secondary system '

steam line drain piping downstream of turbine control I valve 2.2 Assessments of Shift Inspectors

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-2. General The shift inspector assured that any potentially adverse safety concern or regulatory finding was promptly identified to both the licensee's shift supervisor and the THI-1 Restart Manager. Those items requiring additional staff review or followup are described in paragraph 3 of this report. Also, at the end of their assigned period of shift inspection activities, the inspectors provided their general assessment of facility operational readiness and operating personnel performance. These general

= assessments included, as applicable, each inspector's overall-views related to operations, technical support, maintenance, surveillance, radiological controls,

, training, emergency planning, physical security, and housekeeping / fire protection. The inspectors' assessments are presented belo . Operator Performance In general, control room operators (CR0s) were knowledge- ;

able of plant design and current status of testing and ,

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operational activities. Shift turnovers contributed to the operators' readiness to assume the shift. Shift supervision competently handled the daily problems as they arose. The operational structure effectively eliminated distracting " paperwork" for the shift supervisor. Shift staffing exceeded regulatory requirements and the shift technical composition during special evolutions or tests I

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was enhanced by the presence of additional'CR0s, shift

- foreman, and more experienced shift supervisors. This was  ;

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. reflective of management involvement in applying additional resources where neede . .

It'was noteworthy to see certain of the more experienced

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shift. supervisors.take on-training responsibilities for the operating staff. With the plant in an operating condition and during testing lulls, the shift supervisors

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and. operational. questions.. The operation's manager ^1so' '

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contributed significantly to this on-the-job training effort.

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Similarly, auxiliary operators (A0s) were knowledgeable of the plant design commensurate with their assigned duties.

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. Procedures left to A0 implementation responsibility were

. properly implemented in plant spaces based on the various

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activities witnessed by NRC shift inspectors. Although it

. , was noted that A0s had varying degrees of knowledge about the plant design; in general, they performed.in a

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competent manner to properly implement procedures and keep the control room informed on plant status. The knowledge and performance of A0s will continue to be routinely followed during shift inspector activitie As.noted above, procedures were properly. implemented.

& However, certain routine operations were implemented b .the operators who committed these actions to memory.~ -

. Examples were operation of the rod-control panel " Diamond

' Panel" and boration or deboration evolutions. -In general,

< shift supervisors explained that these.were " skills

possessed" as a part of the operators' training and reference to-the procedures was.not needed. The

> inspectors identified no cases in which operators failed to. properly follow these procedures as a result.ofL .

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performing the evolutions from memory. However, certain situations were.noted, e.g., operation of the Diamond Panel, in which operators posed operations questions among themselves and resolved-them without consulting the applicable operating procedure. The licensee's lack of

, use of procedures for routine tasks will continue to be routinely followed by the TMI-1 Restart Staf .

Overall, operators were formal and professional in their

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activities. Although some signs of inexperience showed~

through, minor errors by inexperienced operators were caught by the more' experienced operators. The TMI-l

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Restart Staff is satisfied at this time as to the I . operators' ability to safely operate TMI-1.

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'2. Training"

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-Operator req'ualification and'non-licensed operator o

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. training,rbased on shift inspectors' discussions wit operators, appears strong. ' Operators' typically are kept-very busy during training weeks and crews in training'are

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Operators were well-trained and conducted routine evolu-

'tions without reference to procedure Required plant training on natural, circulation met the-objectives and purpose. All licensed operators except.on , received the training and witnessed' plant heat removal

, using natural circulatio I 2.2.41 Technical Support Shift inspectors generally agreed:that the shift technical advisors were effectively used on shift. Some . ,

communications and-coordination problems were noted-initially-between test and operating. personnel; however, the problems appeared to be reduced as the.two groups-began to understand the.needs and limitations of each other (see paragraphs 4.3.1 and 4.3.2 for additiona details).

12. Maintenance / Material Conditions The preventive maintenance program appeared to be ver effective in minimizing equipment problem Having shift maintenance personnel who rotate'with.th operations1 shift has established good working relation-ships. Also, this seems to. reduce the typical power plant peaks of high maintenance activity:during the day shift, as'the workload is' spread over a 24-hour period. The

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f- maintenan'ce staff is capable of-quickly gearing up and

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responding to equipment problems; e.g., those associated with the auxiliary boiler, turbine steam line drain,

-generator core monitor and control room voltage mete Throughout'the period,'there were few equipment

deficiencies or operating problems and the integrate control system appeared to be.well-tuned. The diesel

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generator and intermediate and auxiliary building were-clean,~but the turbine building was generally. dirty and

' poorly. lighted. :At the close of the inspection period, the licensee needed to resolve the relief valve proble with the turbine-driven EFh pump and a steam line drain lea s 2. Surveillance Testing

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The surveillance. test program utilizes computerized scheduling and surveillance activities are effectively s

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integrated with routine plant operations. There was relatively little activity in the area of surveillance testing monitored by shift inspectors. Increased monitoring is planned for subsequent inspections during the restart test' progra . Radiological Controls Surveys appeared up-to-date and few contamination control problems were noted. Technicians were very conscientious about Form 4's and whole body count . Emergency Planning ATOG procedures appear well integrated with plant emergency procedures and emergency plan implementing procedures including criteria for declaring various emergency conditions. Also, the procedures were conveniently mounted to facilitate their us . Physical Security Auxiliary operators needed security personnel to gain access to the screen house and the rixiliary operator did not carry a key to the intermediate building. These potential access problems were being reviewed by licensee personne .3 Conclusions Operators and technicians properly implemented procedures. Although procedures for routine tasks were not referred to they were properly implemented from memory. Licensed operators, in general, demonstrated control of the facility although there were some interface problems with nuclear / test engineers in providing test direction. Minor mistakes were made but they were corrected by senior, more experienced personnel. . Substantial training experience was gained during the special evolutions performe In general, operator and technicians demonstrated detailed knowledge of the plant design and overall facility status. .0verall, personne conducted themselves in a formal and professional manne . Plant Operations 3.1 Routine Review The resident inspectors periodically inspected the facility to determine the licensee's compliance with the general operating requirements of Section 6 of the Technical Specifications (TS) in the following areas:

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review of selected plant parameters for abnormal trends;

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1 --- Lp1' ant status.from_a. maintenance / modification viewpoint

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. _ including' plant housekeeping and fire proteccion measures; a

zy . -- (control of. ongoing and special evolutions, including control

room personnel awareness of these evolutions;

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. control of documents' including log-keeping practices;

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implementation of, radiological controls; and,

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-- ' . implementation'of the. security' plan-including access control,

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boundary integrity and badging practice : - The . inspectors' focused on = the following areas:

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. control room operations during regular and backshift hours including frequent observation of activities in progress and periodic' reviews of selected sections of the shift foreman's log,and control room operator's: log and selected' sections of -

other. control room daily logs;.

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-- areas outside the control room; and,

--: selected licensee planning meeting As-a' result of-this review and shift inspector observations, the-

-inspectors reviewed specific events in more detail as noted belo .2- Findinas ,

3. General The material condition of the plant remained quite good.in that majorfsafety-related equipment was operable with i equipment-taken out of service periodically for-

-surveillance, preventive / corrective. maintenance. As '

-equipment covered by the Technical' Specifications (TS) was s removed from service, it was done so in-accordance with applicable TS action. statements and properly-recorded and highlighted in control room logs. Licensee resolutions to equipment problems were thorough and technically soun The equipment problems discussed in more detail below did a not have an adverse effect on safe plant operation nor di .they adversely affect test program progress. In summary, plant performance was relatively free of unexpected major equipment outage Housekeeping and fire protection measures remained l consistent with previous-high standards implemented during l the long shutdown. However, certain areas of-the turbine l building were not reflective of those cleanliness standards; applied to safety-related areas. The licensee was'in the process of removing temporary storage / work

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structures in the turbine building and these conditions did not adversely impact safe operations of the facilit The maintenance department's daily planning meeting was well represented by the various site and corporate-based departments involved in the operation, engineering an oversight / review areas. These meetings received an appropriate level of upper management attention. The meetings also were conducive to resolving inter-department interface problems and establishing the priority of work effort '

, ~For the special evolutions and testing thus far, licensee management has made extensive use of briefings. These briefings occurred on shift prior to the. specific test or evolution or at shift turnover just after reliefs occurred. A special briefing for the natural circulation test occurred in the plan-a-log room outside the-control room but acoustics in the room were poor. The briefing on the natural circulation test, in particular, and in

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certain other shift briefings did not give enough consideration to'what could go wrong. In general.. shift briefings adequately prepared operations and test personnel for what was to be expecte There was a definite presence and attentiveness on the

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part of licensee upper management and the various oversight groups during operation. _ Management' insisted on

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and achieved noise control in the control room although 10-20 people (including NRC representatives) were in the r -control room for special evolutions / tests. Up to 50-60 people were in the control room for the-three shift (plus licensee staff) training sessions on natural circulatio Licensee management actions'and directions to their workers could be characterized as deliberate-and cautious backed up'by strong technical capabilities on the part of certain high_ level managers._ As noted in the shift inspector activities section (paragraph 2), licensee management instilled the team concept in the assigned i

shift organization which indirectly represented at least three GPUN Vice President . Failure of Intermediate Power Range Channel On October 3, 1985, during the verification of proper overlap between the source range and intermediate range I nuclear instrumentation, one of two intermediate range i channels failed before the verification could be mad The licensee stabilized power high in the source range and worked from approximately 2:00 p.m. to 10:00 p.m. to correct the proble It was traced to a faulty pin-connector in the high voltage power supply to the instrumen ~-

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The inspector discussed the fa'ilure with'the instrument

and. controls (I&C) technicians that. performed the.

troubleshooting. The inspector. determined that the licensee's approach was performed in a safe manner. . The ,

' ' licensee's decision to stabilize _ power in the source range l

?_ was considered to be proper and prudent although Technica i Specifications only required.one intermediate' range channel to be operable during the startu n 3. Inleakane of OxyRen into Waste Gas System During this inspection period, the licensee noted an increase in the measured oxygen in the waste gas syste Licensee plant engineers reviewed the indication to; determine the source of inleakage. The licensee concluded that-the inleakage was past the newly installed vent valves (WG-V134 ar.d V135) of the reactor coolant drain tank. These two valves were added so that the control '

room operator could vent the tank remotely to containment atmosphere if needed. The original design assumed that-the pressure in the tank would'be above containment

pressure. However, on several occasions reactor building pressure was greater than tank pressure because the waste 4 gas header pressure regulator was referenced to .

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. . atmospheric pressure. The valves that were installed used L system pressure to aid in seating the valves.- The

licensee determined that this was the source of the inleakage into the waste gas system'(reverse-flow through

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a the vent valves).

Under the temporary mechanical modification system, plant f engineers installed a cap on the end of the vent pip They' designed the cap to " pop" off when the pressure in-the line exceeded 15 psig. The engineers tested the cap and demonstrated that it would pop off at less than 7 psi The' inspector reviewed the documentation _ associated _with the temporary mechanical modifications. The inspector also(discussed the design and the initial cause that required-this modification. The inspector concluded that temporary modification was performed.per applicable station procedures. From review of subsequent chemistry

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data the modification was effective in reducing inleakage into the waste gas syste '

3. Mechanical Bindina of RPS Breaker The resident. inspector, with assistance from a region based specialist, reviewed the failure of an RPS breaker on September 23, 1985. The details of that review are in

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Over-voltage Alarm en Emergency Shutdown 4KV Bus

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On several occasions thL inspector noted that the over-voltage annunciater associated with the,_4160 volt safeguardbusalarmedd,piscussionswiththelicenseeand-

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review of the actual busfvoltage noted that the voltage was not at the relay high setpoint. Operations informed the plant engineering l staff and reqngsted them to resolve-the problem. . Plant engineering reviewed and attributed

?theiproblem to an alarm reset llead band that was too

'large.s Tha voltage-value on the bus never dropped below L

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theresetloint. -As an example,.with the.IE bus at (

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approximately 4300 volts, the alarm relay is tripped at _ , .

approximately 4420 volts and.the relay resets at +

approximately'4275 volts. Therefore; the alarm comes in s and remains in. 1 Based on this data the licensee engineer s confirmed'that the' dead band for relay reset was indeed relatively large and he indicated that the relays would be

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replaced with a similar relay with a smaller-dead ban The. inspector also reviewed and' discussed ~the calibratio of the relays and found that.the relays were in calibratio The bus was maintained'at 4309 volts procedurally to ensure that the voltage would' be greater than 80% in a degraded grid. voltage situation during a design basis even Based on the above. the inspector concluded that licensee's corrective actions were appropriat . Scaffoldina Installation 3.2. Based on a review ofsthe shift foreman's log, the inspector learned that on September 28, 1985, an auxiliary operator found-tine turbine-driven emergency feedwater pump

, tripped (inoperable); and, accordingly,' the licensee-entered a Technical Specification (TS) 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement to: restore tha' pump.to an operable conditio The operators restored the pump operability by resetting the trip mechanism; and remained in compliance with'TS 3.4.1.b requirements. However, operations submitted a potentially reportable _ event form (per AP 1044); and -

operations management initiated a plant incident review:

and report documenting the circumstances of the event, underlying causes and applicable corrective action '

The' inspector reviewed, plant incident report'(PIR) N , dated September 28, 1985. The report indicated that auxiliary operftor-1 cgs for the previous shift reflected the pump not being in a tripped condition .

!

.(approximately 10:30 a'.it.:.hysthe access control computer)

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but the log reflected the pusp being found tripped on the next. shift (5:30 p.m.) aft 3r scaffolding installation (1:30 p.m. completion)'.A Based on the location of the scaffolding, the report. concluded that maintenance

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personnel inadvertently tripped the pump although this was not proven conclusively. The situation was compounded by v * the maintenance department's failure to notify the

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• operations department of the pending scaffolding erection

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t s )'( -"' in accordance with the applicable maintenance procedure (MP 1440-Y-3). Further, the operations department delayed 4 .

the post-construction inspection for approximately 5 1/2 hour b- l

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Licensee proposed corrective actions included:

-- revision of MP 1440-Y-3 to assure that the procedures and checklist require operations department signoff prior to scaffolding erection; s

-- review of the PIR by maintenance and operations department personnel; and,

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shift supervisors were to assure proper. priority is placed on timely post-construction inspections of plant scaffoldin The inspector concluded that the licensee's review reflected in the PIR provided a reasonable explanation on the circumstances and underlying causes of-the event. The inspector was satisfied with licensee proposed corrective actions. The inspector had no further comments on this even .2. During_the approach to criticality on October 3, 1985, an inspector conducted an inspection of the intermediate building and he found dismantled scaffolding laying next to the electric-driven emergency feedwater pump (EF-P2B)

along with electrical cords. The inspector expressed to licensee management that the situation was not acceptable as it contributed a trip hazard for the auxiliary operator (required by restart condition) to go tolthat area on an EFW initiation to be prepared to take manual control of

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the flow control valves as directed by the control roo The licensee representative agreed, removed the scaffolding and the electrical wire, and indicated that the equipment was in transit for removal but was laid there temporarily as a staging area to be lifted to ground level (building exit level). The inspector had no further comments in this are # 3.2. During a routine inspection of safety-related building spaces on October 5, 1985, the inspector observed scaffolding stored in the radiator room for the "A"

4 emergency diesel generator. The scaffolding was approximately 30-40 feet high, on rollers that were unlocked; and it was approximately 20 feet from the diesel generator radiator housing (a nuclear safety related

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y'

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Jo; g

-. component).~=This installation was contrary to the'

requirements of maintenance procedure 1401-18, Revision 0, t ' June 3, 1985, " Equipment Storage Inside Class 1

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"

-Buildings," Enclosure 1, Section 3. The maintenance procedure criteria assure that a safe distance.is maintained to preclude an adverse affect on safety-related ,

- equipment during a seismic even '

The inspector brought the finding to the attention-.of an operations department engineer-who then had the Lscaffolding dissantled and removed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The improper installation of the scaffolding represents an

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apparent violation of MP 1401-18, Enclosure 1, Section 3, and Technical Specification 6.8.1 (289/85-22-01).

_

The inspector' discussed the above incidents with licensee-management with respect to a-possible adverse trend with'

maintenance ' personnel working in ~ safety-related area ; Licensee ma'nagement agreed to review the matter with

= maintenance department personne .2.7 -

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~ EW Safety Valve Actuation

~

,During the midshift (11:00 p.m. - 7:00 a.m.) on October 7,

.1985, the TMI-1 Restart Staff witnessed the functional test of the two-hour backup instrument air supply for the E N system.. An inspector observed-that, upon initiation of the turbine-driven EW pump, the safety valv .

(MS-V22A/B) for the turbine steam supply line would-lift periodically until the pump accelerated to normal

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operating speed. The inspector queried licensee S representatives as to whether'or not this was an unnicessary' challenge to these valves, thereby increasing

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the1 probability of one or both valves'failing to clos e This safety concern'is.of particular significance in the event of a loss of all a-~c power.which results in the loss

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of the two electric driven _ pumps. Licensee management ,

could not'immediately state whether or not a stuck-open

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relief valve would cause'the EW pump to be inoperabl Licensee representatives acknowledged the concern, and they ag eed to conduct a design review and provide at

propers r'esolution to the problem before the startup following the 100% reactor trip'(the sixth NRC hold point). They' documented that commitment in a letter, dated Octolier 11, 1985, from H. Hukill, GPUN.to T. Murley, NRC. !The proposed resolution to preclude excessive

! challenges to the EW safety' valves is unresolved pending-completion of the licensee's action (289/85-22-02).

In the interim, licensee management agreed to issue y guidance to operators on what to do in case'one or more

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r safety valves should lift and remain open. (The y turbine-driven pump is backed up by two electric-driven pumps.) As of the end of the inspection period, that

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y guidance was not issued; and, accordingly, the licensee proposed action is unresolved pending issuance and review of the subject guidance (289/85-22-03).

3.2.8 Excessive Steam Being Discharged into the Intermediate Building While witnessing a portion of the natural circulation test procedure associated with emergency feedwater pump initiation, the inspector, along with licensee representatives, noted a main steam trap blow down line, MS-V44, blowing excessive amounts of steam. To shut the valve, a shift supervisor approached the valve away from the direction of the steam flow. Due to the volume of steam being released, the temporary Tygon tubing blew free. The inspector questioned why the valve was open and why it had been opened that fa After discussion with the secondary auxiliary operator, the shift supervisor stated the drain line is required to be cracked open. This is to ensure that no water is collecting in tnis section of steam piping which might adversely affect startup of the turbine-driven feedwater pump. The auxiliary operator stated that he must have opened the valve too muc The inspector reviewed the secondary auxiliary operator logs and walked down the area where similar traps are required to be periodically blown down. The inspector determined that even with a trap blowing down excessively that an operator would still'have access to all areas of the intermediate buildin Further, the MS-V44 trap discharge rose in excess of 20 feet to drain to the main condenser. A design change is planned to preclude improper draining or water buildu In the interim, auxiliary ~ operators drain water from this trap once a shift to assure no water is in the steam lines leading to the turbine-driven EFW pum .2.9 Apparent Bomb Threat During the midshift (11:00 p.m. to 7:00 a.m.) on October 3, 1985, the day of reactor criticality, the THI-2 Control Room received a notification from the Middletown polic The notification was that an individual called and stated that a bomb was going to go off if TMI-1 restarted. The license'e's security force was already enhanced and on alert as a result of a demonstration the previous night after the U.S. Supreme Court action to permit restar Licensee representatives documented the report and evaluated it as not a substantial threat to the facility since there was no credibility given to the caller. The threat was not made directly to the plant and no specific

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20-

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location or apparent knowledge of the plant was give Accordingly, the licensee evaluated the event as neither an explicit nor potential threat to the facility and therefore not reportable in accordance with 10 CFR 73.7 Restart occurred later that day without incident from a security viewpoin .2.10 Hurricane Preparation At 11:30 p.m. on September 26, 1985, the National Weather Service issued a flash flood watch for this area, as a consequence of Hurricane Gloria passing northward along the eastern shore of the United States. The shift inspector reviewed the applicable emergency procedure, EP 1202.32 " Flood," and emergency plan implementation procedure, EPIP 1004.22, " Tornado /High Winds," with the shift foreman and shift technical advisor. Both individuals were very knowledgeable of the procedure contents and requirements. Their actions were based on 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> predictions of river flow rates, and corresponding '

flood levels, provided by the weather service. The inspector confirmed that routine checks are done on the island dike and that two gates were available to be put in place in the event that they were neede Later, during the morning of September 27, 1985, the weather service revised their advisory to a flash flood warning, a less severe situation, in Lancaster County; the flash flood watch continued in eastern Pennsylvania. By mid-day, Hurricane Gloria was centered off the New Jersey coast and there had been a lack of significant damage in the path of the hurricane, until that time. Also, the passage of the relatively mild storm, about 1 inch of rain and winds up to 35 mph, through the Harrisburg area, as Gloria went northward, presented no actual threat to the facility. The shift inspectors determined that the operating crews had been prepared to take appropriate preventive actions, had the weather become more sever The inspectors had no further questions concerning this matte .3 Conclusion No major equipment problems existed that adversely affect safe operation of the facility. Licensee management demonstrated overall control, attentiveness, and a conservative approach to the safe operation of the facility and to the minor equipment problems which presented some obstacles to continued startup testing. Although there was an apparent violation of requirements with respect to storage of equipment in safety-rslated areas, it was promptly corrected; however, it may be indicative of a need for better control of personnel working in safety-related areas. The inadvertent actuation of the safety valves on the steam supply line to the turbine driven emergency feedwater pump was a significant

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finding and licensee interim corrective actions are needed until a long-term solution is achieve . Zero Power and Low Power Testing 4.1 Test Review Prior to Restart

.In preparation for restart and as a result of the fire in the rod control system (reviewed in NRC Inspection Report 50-289/85-21) the inspector verified the satisfactory completion of the following documents-and procedure Special test performed for job ticket CH-683, " Power up Test CRDS After Transfer Switch Fault"

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SP 1301-9.2, " Control Rod Program Special Check," test performed September 13, 1985 to September 17, 1985

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SP 1303-7.2, " Source Range Channel," test performed September 30 - October, 1, 1985

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Corrective Maintenance Procedure 1430-Y-26, " Source Range Detector Removal and Replacement," for Source Range NI-1 High Voltage and Discriminator setting determinations The inspector also independently verified NI-1 and NI-2 responses to groups 1-4 withdrawal. Records indicated that the applicable procedures were properly implemented and test data were in accordance with the test /TS acceptance criteri .2 Test Witnessing and Data Review 4. Zero Power Physics Testing

'4.2. Test Witnessing At various times during the inspection period, the inspectors witnessed all Zero Power Physics Tests (ZPPT).

The tests witnessed included:

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initial criticality;

-- reactimeter checkout;

-- all rods out boron concentration measurement;

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isothermal temperature coefficient measurement; l

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differential and integral regulating group worth measurements; l

-- differential boron worth measurement;

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shutdown margin verification; and,

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ejected rod worth measurement;

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Tests were observed for the following area Zero power physics tests were conducted in accordance with the approved test procedure, RF-1550-02, "Zero Power Physics Testing," Revision 7

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Prior to. performing each test, briefings with the test crew and operation personnel were conducted and'

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the briefing was adequate

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Test prerequisites and initial conditions were met Operator actions were correct

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-- Summary analysis was made upon completion of each tes .2. Zero Power Physics Test Results Review The ZPPT results were reviewed and. compared with Technical Specifications (TS) and with acceptance. criteria detailed in the test procedure. The details and findings of the review are described in the following.-

4.2.1.2.1. Initial Criticality Initial criticality of Cycle 5 was achieved on October 3, 1985, with reactor coolant system boron concentration of 1167 ppm and group 7 position at 66.5% withdrawal (WD).

The predicted boron concentration based.on the group 7 of 75% WD :is 1230 pp The equivalent boron concentration for group 7' change from

'66.5% WD to 75% WD is 4 ppm. - The measured deviation from prediction is therefore 1230 - (1167 + 4) = 59 ppm. This result is within the acceptance criteria of +/- 100 pp .2.1.2.2 Reactimeter Checkout The inspector independently verified that the reactimeter was adjusted with the correct -inputs of delayed neutron fraction and decay constants, and noted that the results of the " cold" calibration check were satisfactor The reactimeter was further checked using Intermediate Range NI-3 input when the reactor reached criticalit Comparisons of predicted and measured reactivities based on doubling time measurements were acceptable within the acceptance range of +/- 5%.

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. .2.1.2.3 All Rods Out (ARO) Critical Boron Concentration The licensee measured the ARO critical boron concentration in accordance with the procedure, 1550-02, Step. 7.3. The measured ARO critical boron concentration is 1182 pp This value differs from the predicted value of.1255 ppm by 73 ppm. The deviation is within the acceptance criteria of i 100 ppm. The lower measured value was expected since the predicted value is based on the original B&W cycle 5 fuel design report. The cycle 5 fuel has been loaded in the core since 1979. The extended shutdown caused the isotope decay and'a decrease in reactivit Recently, the licensee performed an engineering evaluation to account for the isotopic configuration changes (Memo from J. W. Folsom, TMI Fuel Projects Engineer, to J. Luoma, Manager, TMI Fuel Projects, " Expected Reactivity Changes in TMI-1 Cycle 5 Due to 6 1/2 Year Delay i Startup," dated August 29, 1985), and predicted the ARO critical boron concentration to be 1184 ppm. This study accurately predicted the critical configuratio .2.1.2.4 Isothermal Temperature Coefficient Isothermal temperature coefficients were measured in accordance with the procedure, 1550-02, steps 7.4 and The inspector noted the following results:

Predicted Value Measured Value Configuration (pcm/ F) (pcm/ F) '

All Rods Out -2.45 1 ?. 3 All Rods In -12.44 1 .96 The corresponding moderator temperature coefficients (MTC)

were determined to be as follows:

Measured Value TS Limits Configuration (pcm/ F) (pcm/ F)

All Rods Out -0.31 < All Rods In -10.97 < The inspector independently evaluated the test data and obtained the following result ITC Value (pcm/ F)

Configuration (Inspector's Calculation)

All Rods Out -2.23 All Rods In -12.55

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na

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. Test results were within acceptable criteria and the

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corresponding MTC values met the TS requirement .2.1.2.5 Control Rod Worth Measurement

.The regulating group rod worth ~ measurement was performed

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in accordance with the procedure, RF-1550-02, step The following'results were note Regulating Group Predicted Value- Measured Value-(pcm) (pcm)

Groupf7 1320 1 200 1400

. Group 6 840 i 130 863

' Group 5 1060 1 160 946 Groups 5-7 3220 1 320 3209 Test results met the acceptance criteria. The corresponding differential boron worth as derived from this test was 11.5 pcm/ ppm. This value was off the predicted.value of 10.125 pcm/ ppm +/- 10%. After

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consultation with the fuel vendor (B&W), the licensee determined that the measured value was within 15% of the calculation which was the originally-recommended-B&W acceptance criteria, (B&W Technical Document. . _

62-1003756-01, "Zero Power Physics Test, TMI-1, Cycle 5,"

dated December 20,~1978). The measured value is still:

bounded by the value (13.33 pcm/,'om) used in the FSAR

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. safety analysis (moderator dilution accident). The inspector-noted that in Cycle 4 the measured value was *

11.02 pcm/ ppm with a predicted value of 10.2.pcm/ pp Further, the safety group (groups-1 through 4) rod worth ,

as measured in the next test was not affected. Based on these facts, the inspector concurred with the licensee's-engineering _ evaluation that no safety implication is involve .2.1.2.6 Shutdown Marain Verification LThe shutdown margin was verified in accordance with the procedure step 7.6 by tripping the safety groups 1 through 4 into the reactor. The measured shutdown margin was 3.30% gK/K which met the TS 3.5.2.1 requirement of 1.0%

or/ .4'.2.1.2.7 Eiected Rod Worth Measurement The control rod N-12 was analytically determined to be the worst case ejected rod. The inspector noted the following test results:

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Predicted Value Measured Value LControl Rod' Test Conditions (% A K/K) (%AK/K)

N-12 Boron Swap 0.65.1 0.13- 0.675 N-12 Group 5 Rod Swap 0.65 1 0.13 0.707

.The measured value from the boron swap. method is within 5%

of the rod swap method. The measured ejected rod worth.is-in good agreement with the predicted value and meets the-test acceptance criteri *

'4. Low Power Natural Circulation Testing 4.2.2.~1 The low power natural circulation testing was witnessed by-the inspectors in its entirety. The main objective of

.this test was to determine the plant's ability to achieve-and maintain natural circulation cooling of the core following a plant. shutdown and loss of the reactor coolan pumps. .Because the plant had been shut down for greater

.than six years, there was no appreciable decay heat to maintain natural circulation. The reactor was maintained at 3% 11% power to simulate decay heat conditions immediately after shutdown. The test was designed to demonstrate'that:

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-- natural circulation would be achieved and maintained;-

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all emergency feedwater pumps will start and reach-full flow upon loss of both main feedwater pumps;

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steam generator water levels can be controlled manually and by the integrated control system (ICS);

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the steam drive EFW-pump provides sufficient heat removal on loss of both motor driven EFW pumps.due to loss of ac power;

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a minimum of 50 degrees F reactor coolant system subcooled margin could be maintained;

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critical air-operated valves EF-V30A/B, MS-V6, and-MS-V4A/B could be supplied'by the bottled air supply for up to two hours;-

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pressurizer heaters assigned to one emergency bus were sufficient to stabilize RCS pressure;

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the steam generator level at which natural circulation would be lost on lowering steam generator water level;

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training is accomplished for all operators on the natural circulation evolutio ,

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The inspectors: observed the test performance to verify

'that:

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' natural circulation testing was conducted in accordance with test procedure (TP) 700/2, " Low Power Natural Circulation Testing," Revision 2;

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prior to performing each major subtest, an adequate briefing was conducted for operating and test personnel;

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test prerequisites and initial conditions were met;

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applicable Technical Specifications were complied with;

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. operator actions were correct;

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test engineers were knowledgeable of their duties;

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test results were acceptabl .2.2.'2 Natural Circulation Test Results Review 4.2.2.2.1 Emergency Feedwater Test All three feedwater pumps-(one steam driven and two motor driven) started on loss of both main feedwater pumps and accelerated up to speed in less than 40 seconds'and 15 seconds respectivel .2.2.2.2 Bottled Air Supply Test Instrument air supply was cut off to the EFW discharge valves, the steam dump valves, and the EFW steam driven pump steam supply valves and backup bottled air was use Bottled air dropped'from an average of 1870 psig to an average of 1060 psig in the two-hour time limit. The minimum allowed air pressure was 250 psi .2.2.2.3 Natural Circulation Test Upon securing the RCPs for natural circulation testing, major plant parameters stabilized in approximately six-minutes. No limits specified by the procedure were exceeded. All parameters given below are average values of both loops after stabilization:

Limit Th = 578 degrees F < 590 degrees F Tc = 540 degrees F- > 525 degrees F-Pressure = 2185 psig > 1950 and < 2250 psig

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Pressure Level = 214 i > 100 and < 250 i OTSG Level = 50 % > 18 i ,

l Saturation Margin = 69 deg.F > 50 deg.F and < 100 de Other plant parameters were also within specification During.the subsequent test, all pressurizer heaters were deenergized for a period of two hours. A normal natural circulation flow was verified under this simulated loss of pressurizer heater condition. At the end of two hours of testing, the Group 8 pressurizer heaters were re-energized. Test results positively indicated that the Group 8 heater could stabilize the decrease in RCS pressure with a pressurization rate of 36 psi /hr being achieve A third portion of the test required a gradual-lowering of steam generator levels starting at 50%. The purpose of this test was to determine the effect on natural circulation flow'of lowering 0TSG 1evel. Test results indicated that at about the 35% level, the plant would lose its smooth natural circulation. Once the unstable condition was detectt;d at this level, the RCPs were restarted to establish forced circulatio .3 Additional Findings 4. Zero Power Testing

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As noted in paragraph 4.2.1, zero power physics test data vere found to be satisfactory. Test exceptions and deficiencies were reviewed by the inspectors and determined to be properly resolved. The reactor engineers were well prepared for conducting the tests. The inspector had witnessed two' data taking training sessions given by the reactor engineers durinF Previous NRC

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inspection periods. The results of . ids previous training were evident in their ability to expediently take and reduce dat It was noted, however, that they provided too much direction in the~ control of plant evolutions. In addition, it was pointed out to plant management that the operators should assure they have control of plant operations and not depend entirely on directions from the test engineer Improvement was observed after discussions with plant management. The test engineer-operator interface will continue to be routinely reviewed during future inspection Specific problems encountered by the licensee during this testing phase are discussed belo .

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4.3. Boron Overshoot On October 4, 1985,-the licensee performed paragraph'7.3,

"All Rods-Out Boron Concentration Measurement" of Test Procedure 1550-02, "Zero Power Physics Testing." During this test, boron was added to the core to position controlling group 7 rods to greater than 95% withdrawn.

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The amount of boron added (30 ppm) was based on Figure 6 of OP 1103-15B, " Integral Rod Worth." The difference in rod worth was calculated from group 7 at 69% to group at 95%.

After addition of the calculated amount of boron and withdrawal of group 7 to 95%, reactor flux continued to decrease. The licensee withdrew group 7 to 100%, but there was insufficient rod worth to stop the flux decrease and the reactor went suberitical and into the source rang In order to stop the flux decrease, water was added to the core in increments of 300, 150, 150, and 450 gallons. At approximately 5:45 a.m., neutron flux began to increase. Group 7 rods were inserted 92% and reactor power eventually stabilized. The final result was an all rods out boron concentration of 1182 ppm which was within the specification limits,- 1255 1100. (See paragraph for further discussion of test results.)

The reasons for the " overshoot" of boron were discussed with licensee representatives. They noted that such overshoots are not unusual during chemical shim of rod Also, the rod worth' measurements were based on data supplied by Babcock and Wilcox (B&W) which are done by computer calculation and are part of the reactor physics book produced in 1979. Such calculations may not be completely accurate at rod worth end points and must be modified based on actual test data. The inspector independently verified this based on the actual rod worth measurement (rod worth measurement was performed following this incident) and the total amount of water diluted. The result explained that the whole evolution was caused by adding too much boron due to an overpredicted Group 7 ro worth near end points on the rod worth prediction grap The licensee handled the situation in a slow controlled manner. The overshoot of boron caused a reactivity decrease rather than increase. Adding water in small increments prevented any significant overshoot in the positive directio Although rod worths of rod grou between 69% and 95% were not as expected, the boron overshoot did not present a significant safety proble .3. Reactivity Graphs Procedure OP 1103-15B, " Estimated Critical Conditions,"

Figures 3 and 6 contain curves of integral boron and

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control rod worths respectively. These curves were based on B&W estimates. Actual. integral boron and control rod worths were accurately determined during performance of procedure 1550-02. During this. inspection period, the licensee revised Figures 3 and 6 of OP.1103-15B to reflect the actual boron and control rod worths determined by performance of procedure 1550-02. The inspec. tor verified that this revision was mad . Natural Circulation Testing As noted in paragraph 4.2.2.2, natural circulation test data were found to be within specifications. Test exceptions and deficiencies were reviewed by the inspectors and determined to be properly resolve The reactor engineers performed zero power physics tests and test engineers performed the natural circulation test and all subsequent special plant tests. In contrast to the reactor engineers, the test engineers did not appear to be as prepared for the tests. They were not as well organized and there did not appear to be a clear line of authority over data taking personnel. This may have led, in part, to the NI correction factor data collection problem discussed in paragraph 4.3.2.1 below. There appeared to be a lack of familiarity with the procedures

.to be performed both by the test engineers and plant managemen This was discussed with plant management. Considerable improvement was noted in test engineer performance 6tring subsequent plant testing. This area will be the subject of routine review during the startup test progra As evidenced by problems discussed in paragraphs 4.3.2.1, 4.3.2.2,'and 4.3.2.3 below, procedure TP 700/2 should have received a better review before issuance. Although TP 700/2 had some problems, it was technically adequate to verify the proper performance of EFW pumps and natural circulation. However, because of the problems identified in TP 700/2, the licensee is performing a further review of TP 800/8, "RCS Overcooling Test," which is the next major plant transient test to be done. This test will be performed at 40% powe The objective of this review is to eliminate the kind of procedural problems identified during the performance of TP 700/2. To date, this review has generated numerous comments to-TP 800/8'which are currently being resolved by the test engineering grou This area will continue to be routinely reviewed during the power escalation progra .

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4.3.2.1 NI Correction Factor To ensure that reactor power was maintained at 3 11%, and that the overpower trip was set at < 7% power during natural circulation, the nuclear instrumentation was calibrated using a heat balance and correction factors were established for a Tc range of 526 to 541 degrees During data reduction following performance of this test, a licensee engineer noticed that calculations were being made by using uncompensated (for temperature) rather than compensated reactor coolant system flow as required by the procedures. Test engineers had used a similar but incorrect data sheet rather than that called for by the procedure. The licensee stopped further testing until this problem could be understood cnd resolve It took appro- 'ely four hours for resolution. The licensee dets ,ed that the data sheet required by the procedure .= .a error and should have required compensated RCS flow. This had been based on a previous B&W review of the procedure which stated that calculations should be made with compensated RCS flow. An error in incorporating B&W comments caused the data sheets to be uncorrecte In addition, the inspectors noted, and the licensee concurred, that procedure and data sheets were poorly correlated and the procedure did not clearly call for what was actually intended. The licensee prepared a procedure change which corrected the above deficiencie None of the above ultimately affected the adequacy of the subsequent EFW testing and natural circulation portion of the tes .3.2.2 EFW Test Section 9.2 of the natural circulation test checks the performance of the EFW pumps. Upon tripping of the main feedwater pumps, the procedure verifies that the steam-driven EFW pump and the two motor-driven pumps start and accelerate up to speed in less than 40 and 15 seconds, respectively. At first it appeared that the measured times were in excess of specification. However, the procedure did not take into account coast down of the main feedwater pumps. EFW pumps cannot actuate until feedwater pump flow is low enough to actuate a differential pressure switch. The licensee prepared a test deficiency which accepted the times based on the differential pressure switch actuation until the EFW pumps star .3.2.3 Recovery from Natural Circulation In order to go from natural circulation to forced circulation, the procedure calls for reducing power to 0.5% and bring reactor delta "T" to 15 1 2 degrees F. As reactor power was reduced natural circulation was also

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reduced keeping the delta "T" at about 34 degrees F which-

. was unanticipated'by. testing and engineering personnel.-

..The' reactor coolant. pumps were started with this delta'

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T".

. During the portion of the test.which lowered DTSG water

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level, natural circulation was: lost in the "A" loop. The

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.RCP's wereistarted to establish forced circulation, this caused hotter-than expected water in the OTSG. Conse-quently, a main steam safety valve lifted and reseate ~

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There was no. impact on. safety and the plant responded as-designe '

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Lt 14.4 Restart' Conditions and Technical Spec'ification-Conformance

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ji Verification-

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14. Restart Conditions Verification Restart-conditions 2(a) and.2(c) stated the following:

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"(a) Prior to operation above 5% power, GPU Nuclear Corporation shall complete the Special Low Power Test'

Program in accordance with GPU Nuclear Corporation's Restart Test Specification (letter of April'5 1983

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or NRC-approved later submittal) and Item I.G.1 of

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NUREG-0694....

"(c) Prior to operation above 5% power,,GPU Nuclear  !

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. Corporation shall demonstrate that EFW system

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initiation and operation is assured independent of '

any AC source for at least two hours."

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TP 700/2,_" Low Power Natural Circulation Test',"

~ accomplished at 3% reactor' power c'onstituted the required' ,

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low-power: test program. TPl700/2 performed operation of

>the steam-driven EFW pump (EF-P-L) with the two motor "

4 - " driven pumps secured which' simulated operation of:EFW with

loss of a-c power. .In addition, TP 700/2-verified al i NUREG-0680 concern that a backup air supply independent of

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ac. power.be available to provide a two' hour supply of air

> to the steam supply pressure. regulating valve in the event of loss of normal ac-dependent air syste During performance of TP 700/2, the instrument supply was isolated and air was supplied for two hours to air-operated valves EF-30A&B, EFP discharge valves; MS-V4A&B,

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atmospheric steam dumps; and MS-V6, steam supply valve to EF-P-L using a backup supply of bottled ai The inspectors verified satisfactory performance of TP 700/2 and that the required restart conditions were me ,

The natural circulation training observations'are ,

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discussed'in paragraph 2.2.3.

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4. Technical Specification Verification

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Tehhnical Specifications 3.1.9 and 3.20.1, applicable to-low power physics and natural. circulation testing,. provide

~ exceptions to other Technical Specifications during-

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performance ~of low power' physics testing and natural circulation testin LThe inspectors verified that these specifications were met

(or not exceeded) by observation of test-performance or by review of appropriate test dat " '

- Conclusion

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Zero power and low power physics testing were= accomplished in

_s accordance with procedures, data were acceptable, and' tes _

^ . objectives were met.' Although procedural problems-were identified, they.did not affect the overall acceptability of the final dat The licensee took actions to review future tests which may caus ' unexpected plant-transients to assure that they can be properly performe ,j

There appeared to be some lack of organization among the test engineers during the start of the natural circulation tes :However, these problems appear to have been quickly correcte mLicensee management was responsive to inspector observation Problem areas were quickly corrected and actions were taken to

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preclude their recurrence. Overall licensee performance in the test area can be considered acceptable and, to date, test results are acceptabl . Reactor Protection System Breaker Malfunction 5 ~.1 Event Chronolony On. September 23, 1985,. reactor protection system (RPS) breaker CB-10-failed to close properly. The plant was in a hot shutdown condition with' reactor coolant system (RCS)-pressure at 2155 psig and RCS_ _

temperature at 533 degrees F. Control rod groups 1 through 4, which

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are normally 100% withdrawn at hot shutdown, were being manually driven into the reactor to collect data for source range detector i respons ,

, Instrument and control. maintenance personnel,were performing surveillance procedure ~(SP) 1303-4.1 that verifies RPS coincidence 1 : logic by trip testing individual RPS breakers. Technicians had just '

successfully completed testing the undervoltage trip device on RPS breaker CB-10. The technicians were-proceeding to close CB-10 in

. ' preparation for-independently test!ng the shunt. trip device. When the technician depressed the' local " closed" pushbutton, the breaker sounded as if it went closed and indicators (main annunciator window L-1-1, and two lights on the A~RPS cabinet) in the control room responded as if the breaker had closed. The local "open/ closed"

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t indicator on CB-10, however, indicated an abnormal partially-closed positio The indications of breaker position come from contact relays associated with the breaker, designated as 52a contacts. The mechanical indication is directly driven off mechanical linkage from the breaker itself. The technician recognized this abnormal breaker-indication; and, after some discussion with other test personnel, he decided to trip the breaker using the shunt trip device on the breaker since this was also the next step in the procedure. When the technician selected " Shunt Trip" on the breaker local test switch, the' breaker appeared not to open when the switch " spring returned" to-its normal position. Thinking that the breaker had failed to trip, the technicians were reviewing their observations when smoke began to come out of the CB-10 cubicle. The technician immediately depressed the local trip pushbutton but again the breaker position did not change. The shift foreman ordered that the upstream supply breaker be tripped and CB-10 racked ou Before CB-10 was completely racked out, a small, localized electrical fire occurred in the breaker cubicl The breaker was removed to the electrical shop.for inspectio Initial observation of the damaged CB-10 indicated an opening far enough to-be in the mid-open position where the main contactors were open, but not at the tripped, or trip-free position. Resistance readings indicated that the auxiliary contactors (52a's) for the damaged breaker were partially closed. A spare breaker was installed and satisfactorily tested per 1303-4.1 on September 24, 198 .2 Scope of Review The inspectors reviewed the malfunction of the reactor protection system breaker and the licensee's review of this event to determine the following item details regarding the cause of the event and event chronology

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functioning of safety systems as required by plant conditions

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consistency of licensee actions with license requirements, approved procedures, and the nature of the event

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proposed licensee actions to correct the cause of the event

.-- verification that plant and system performance were within the limits of analyses described in the Final Safety Analysis Report (FSAR)

The inspectors' review of the breaker malfunction included discussions with cognizant licensee personnel and review of the following document system drawings

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preventive maintenance procedure E36, Revision 13, August 8, 1985, "(Electrical) CRD Trip Breaker Trip"

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job tickets CB678, C5077, and CB812 and work requests 17636, 16907, and 23161

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plant incident report 1-85-11, " Failure of Control Rod Drive Breaker (Unit 10) to Close"

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machinery history entries associated with RPS breakers The inspectors independently _ reviewed the sequence of events and the history of the failed CB-10 breaker and other RPS breakers to determine if the circuit breakers underwent any abnormal event during receipt or testin The inspectcrs accompanied licensee personnel while they performed detailed inspections of the reactor trip breakers. The licensee visually examined all internal mechanical components which caused-mechanical binding on the failed breaker. Also, the inspectors independently examined the disassembled failed breake '5.3 Licensee Review / Findings 5. Breaker Maintenance / Modification History On January 16, 1985, TMI-1 RPS breakers, two se breakers (CB-10 and CB-11) and four de breakers (CB1, ., 3, and 4)

were sent to the GE Atlanta Service Division This action resulted from General Electric Company Servi:e Advice N .10, dated March 21, 1984, which suggested that users of AK-1/1A-25 breakers change the breaker bearings and latch roller assembly lubricant to Mobil-18 on all AK-2 breakers manttfactured after February 13, 198 Previously, CRG-5-56 or WD-40 was recommended; however, laboratory tests indicated that after a period of time these lubricants dried out the bearings of the latch roller assembly causing torques of greater than 10 inch-ounce After bearing refurbishment from GE Atlanta and qualification from B&W, the ac breakers were quality control receipt inspected on June 6, 1985. On June 7, 1985, the breakers underwent preventive maintenance testing in accordance with procedure E-36, " Electrical CRD Trip Breaker Check." The purpose of this preventive maintenance is to check the breaker for proper operation and adjustment; specifically, this preventive maintenance checks the breaker for:

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undervoltage device over travel;

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stationary contact spring pressure;

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torque on trip shift required to trip breaker;

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response time testing; and,

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undervoltage device armature clearanc Breaker CB-10 failed to close on July 19, 1985, after being tripped and removed from its cubicle. The-breaker was removed so a fan motor in No. 10 trip switch gear cubicle could be worked on. Corrective maintenance Job Ticket CH-358 was generated at that time to troubleshoct, repair, and test breaker CB-10 to determine why it did not close' properly after being racked into its cubicl The breaker was inspected and operated manually to determine if the closing problem could be determine Preventive maintenance procedure E-36 was performed and no problems were identified. All "as-found" data were within specification. Discussions with the licensee indicated that when the breaker was racked back into the cubicle, minor misalignment kept the breaker from closing; i.e.,

the breaker kept tripping free, a problem not germane to the failure that occurred on September 23, 198 On September 15, 1985, CB-10 was installed in the CB-11 position because of a loose screw problem that developed on one of the manual pushbuttons on CB-11. Surveillance Procedure 1303-4.1, " Reactor Protection System," was performed and satisfactory results were obtained until the event of September 23, 1985. This RPS test procedure is performed weekly on all six (6) CRD system AK-2 breakers to assure proper operation, including manually tripping of the breakers in the undervoltage and shunt trip mode .3.2 Breaker Failure Analysis The failed breaker was examined by the licensee on September.24 and 25 to determine the failure mod Vendor representatives participated in this proces The failure was tentatively diagnosed by the licensee as mechanical binding within the breaker closure assembl As a result, the breaker would not fully open or close from the failed mid position.. The GE representa-tive was not aware of any prior failures of this type on their breakers.'

Measurements and inspections were made on the failed breaker to gather a data base from which the inspection could be conducted on the other breakers. These criteria included:

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looseness of the shoulder pin ycke assembly shaft;

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measurement of the distance between the inside of the yoke at main contact shaft;

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inspection of the shoulder pin yoke assembly shaft interior fork for binding;

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measurement of the inside distance between pointed yokes with calibers;

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manually pushing on breaker closing solenoid armature and examination for signs of wear or rub marks below the square holes on both sides of the spring carrier; and,

-- measurement of the inside distance below the square holes between the spring carrier side Corrective maintenance job ticket CH 798, dated September 25, 1985, initiated a maintenance procedure to perform inspection and take measurements on all GE type AK-2 circuit breakers used in the CRDs (ac and de breakers and spares) and the main exciter field breake In-process QC insp-action was a mandatory hold point prior to beginnin From this special inspection of all RPS breakers, the licensee found one additional breaker, CB-11, to have wear-marks on similar internal components; however, the wear marks appeared to be on different surfaces of the components in question. Other tolerances appeared to be

'within the same range as that of the other breaker The licensee concluded that all four de breakers installed were acceptable. The ac breaker (CB-11) with wear marks would require additional inspection by G Breakers CB-10A and CB-11A (TMI-2 breakers) were installed in place of the two TMI-l breaker Because breaker CB-10A had not been modified by GE for the above-noted roller bar torque problem, the licensee measured the torque required to trip CB-10A and found it to be acceptabl In addition, the licensee reviewed the events associated with the damaged shunt relay and shunt coil test relay (" designated 27 relay") and determined that these failures were a direct result of the mechanical binding of the breaker. The licensee determined that with the breaker in the mid positio. , contacts used for control and indication of breaker position could be closed. Because of the allowable variance in the tolerance, these contacts (52a contacts) would open or close' depending on the specific dimensions at different mid positions of the breake In the case of breaker CB-10, these contacts appeared to remain closed in the position that the breaker faile One pair of 52a contacts is normally used to de-energize the shunt coil when the breaker is open. In addition, the licensee had modified the breaker so that the shunt trip could be tested independent of the undervoltage coil tri A new relay and 27a contacts were installed to aid in performing this function. The 27a contacts are in' series

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i with the shunt trip coil and a pair of 52a contact Normally the 27a contacts are opened and closed to energize the shunt coi When testing the shunt trip only, the test circuit closes contacts (on 27a energizing) to energize the shunt trip coil. When the shunt trip test switch is released, the 27a contacts will return to their normally open_ positio These contacts are not designed to interrupt power to the shunt trip coil; this is the function of the 52a contac However, with breaker CB-10 in the mid-position (52a contacts remained closed), contact 27a attempted to interrupt power to the shunt trip coil and fused themselves together. The shunt trip coil which is designed for intermittent energization remained energized continuously and overheate . Licensee Additional Actions

' As part of the licensee's followup action, a review was performed on the adequacy of existing maintenance'and operating procedures. The licensee determined their surveillance procedure needed precautionary notes to ensure that if a breaker did not close fully, the operator would take appropriate actions. The electrical indication of the breaker position is from a pair of 52a contacts which supply the only indication in the control roo When the breaker is in the mid position, the control room indicators would appear closed. The licensee is procedurally requiring that local mechanical and control room indications be checked when cycling RPS trip

" breakers. To ensure that knowledge of this event was shared with the rest of the industry, the licensee also made a " Notepad" notification (see paragraph 5.4).

Further, the licensee shipped the failed breaker (designated CB-10) and the breaker that indicated some wear (designated CB-11) to General Electric for further evaluation. These two breakers were replaced by TMI-2 breakers (CB-10A and CB-11A). Of the six installed breakers, five breakers (four de breakers and CB-10A) have been modified by G The CB-11A breaker will be replaced shortly with a modified breaker (see paragraph 5.4).

5. Licensee Conclusion On September 30, 1985, the licensee concluded that the six RPS trip breakers installed were considered to be operable based on the above review. Further evaluation of breakers CB-10 and CB-11 will be performed; however, the licensee does not expect these results to change its conclusions as

' to the adequacy of the presently installed breaker . _ - . __ _ _ .

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g Also, the licensee concluded that the design of the breaker test relays was still acceptable; however, precautionary notes should be added to their procedures to

. assure the shunt' trip is not used in the event.of mechanical binding during closing of a breaker. The

.previously noted modifications involved replacement of several bearings with new bearings and the replacement of the trip bar roller assembly. The licensee concluded that the parts involved with the mechanical binding or the evidence of wear were not involved in the modificatio The modification was performed due to the lubricant in these bearings becoming hard and causing additional torque required to be developed to trip the breake .4 NRC Findings Operator action in response to the event was timely and correct in isolating all power sources to the breaker. Shortly after the event, licensee management took the initiative to provide an information report to'the NRC's resident offic The licensee review of the event was thorough and technicallt soun The licensee used the technical resources not only from the2r engineering staff but also from the vendors (B&W and GE) who were involved with the refurbishment of the breake .

The licensee's special inspection was properly implemented and provided sufficient information as to the probable cause of the even Licensee quality control inspectors monitored licensee activities during the implementation of the procedure that was also periodically witnessed by various levels of management in the operations and maintenance departmen There was ample evidence of QC receipt inspection on the return of the refurbished breaker to the site. There was sufficient documented evidence to develop a chronology of the breaker modification / maintenance history and the event sequenc The inspectors independently confirmed the licensee's findings noted above. Also, the inspectors agreed with the' licensee's conclusion of September 30, 1985, that the installed RPS breakers, including the one unrefurbished breaker (CB-10A), were operable even though the exact nature of the mechanical binding in the latching mechanism (main spring assembly) was not determined as of that dat Additional information may be revealed as a result of the vendor research on the breakers that were shipped to GE (paragraph 5.3.3).

Until the completion of that research effort and replacement of the unrefurbished breaker , this area is unresolved pending completion of licensee's review of the vendor's related report and subsequent NRC Region I review (289/85-22-05).

The licensee was to make a number of procedural revisions (paragraph 5.3.3). One was to assure that when a breaking open/close problem is identified in accordance with SP 1303-4.1, the local operation

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I switch will be used to open the breaker. Further, the licensee was considering a review of their startup/ operating procedures to assure a positive local check of ac and de breaker closure since the control room indication, depending on breaker intermediate position, could be deceiving. The licensee review of related procedural changes is unresolved pending completion of licensee action and subsequent NRC Region I' review (289/85-22-04).

5.5 Conclusion Operator response to the event was appropriate to the circumstance The inspectors tentatively concluded that the failed breaker was unique and attributed to an isolated failure. Additional review of vendor research efforts will be needed to determine if there are generic implications. Procedural changes will be needed to preclude use of the shunt trip coil to open a jammed RPS breaker locally and to assure positive closure of the RPS breaker on reactor startu The installed breakers were operable for restar . Decay Heat Pump Operability Review The inspector assessed the operability of the decay heat pumps,

. based on a review of licensee maintenance (preventive and-corrective) and surveillance activities to verify that:

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procedures required by Technical Specifications (TS) 4.2.2 and 4.5.2.2.b are being properly implemented;

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applicable procedures have the proper format and technical content in accordance with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWP and applicable sections of ANSI N18.7-1976;

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surveillances and preventive maintenance (PM) were conducted at the-proper frequency; and,

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machinery history records and related surveillance and preventive maintenance records were retrievabl In addition to discussions with cognizant licensee personnel (main-tenance, operation, and engineering), the inspector reviewed selected portions of the following licensee documents and records:

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Surveillance Procedure (SP) 1300-3B A/B, " Decay Heat Removal Pump Functional Test and Valve Operability Test," Revision 21, dated 8/5/85, including data obtained 3/26/85, 6/21/85, and 9/20/85;

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SP 1303-11.54, " Low Pressure Injection," Revision 4, dated 11/20/84, including data obtained on 4/8/85;

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PM Procedure M-138, "011 Sampling Procedure," Revision 2, dated 3/14/85;

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PM Procedure-1410-P-3, " Lube Oil Change," Revision 6, dated

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PM Procedure M-130, "High Speed Flexible Couplings (Gear Tooth-Type)," Revision 2, dated 6/3/85, including data obtained from 8/28/84 and 11/30/84;

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PM Procedure E-2, " Dielectric Check of Insulation, Motors and Cables," Revision 3, dated 5/25/83, including data obtained from 9/14/84 and 10/27/84;

--- PM Procedure E-1, " Vibration Analysis for Rotating Equipment',"

Revision 4, dated 7/4/81, including data obtained during 1984 through 1985;

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selected job tickets from machinery history files, numbers C1689, C1702, CA577, C2805, CC279, CB356, CA440, C8515 and C3529; and,

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Worthington Pump International Technical Manual 2148-E3F,

" Centrifugal Pumps Types NM, NMT, and NND."

6.2 Findings The inspector determined that surveillance and preventive maintenance activities were current and being conducted at the proper frequency, were in accordance with TS, and records were retrievable. SP 1300-3B A/B was found to meet all applicable requirements of Subsection IWP,Section XI of the ASME Cod However, upon review of surveillance data from SP 1300-3B A/B taken on March 26, 1985, the inspector noted a discrepancy. Several instruments used to measure surveillance data had full-scale ranges greater than three times the' reference value. This is not in agreement with IWP-4120, " Range." However, by the time the next surveillance was conducted on June 21, 1985, a procedure change was made to correct this deficiency. The inspector had no further question Preventive maintenance procedures appropriately reflected vendor recommendations to change lubricating fluids at six-month interval SP.1300-3B A/B also reflected vendor recommendations for periodi-cally measuring bearing temperatures, and inlet and outlet pump discharge pressure Machinery history provided a useful summary of work activities on-the decay heat pumps. Referenced job ticket records were retriev-able using the licensee's microfiche and microfilm systems. When major corrective maintenance was performed under various job tickets, adequate post-maintenance testing and various independent

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verifications were specified and performed.

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6.3 Conclusions The inspector concluded that the licensee's records were well kept and that these records reflected applicable procedures that were being properly implemented. In place surveillance and preventive maintenance procedures and post-maintenance testing should provide adequate reliability such that the decay heat pumps will be operable when called upo . Restart Readiness During the inspection, the resident inspectors assisted by region-based inspectors continued their review of equipment operability (started in NRC Inspection No. 50-289/85-12) in selected areas to assess the readiness of the plant for startup. The selected areas inspected included safety-related building spaces; outstanding licensee identified items in the surveillance, maintenance and modification areas; outstanding NRC inspection findings; and selected valve lineups. The objective was to identify equipment operability problems that could adversely affect safe operation of the facilit The results of this review are documented belo .1 Safety-Related Building Spaces Periodically, the inspector reviewed safety-related building spaces to identify ~any loose equipment, scaffolding, or other problems such as fire hazards / housekeeping that could adversely affect the operability of safety-related equipment in adjacent area Shortly before the pending restart of September 25, 1985, selected areas of the following safety-related buildings were inspected:

reactor building; auxiliary building; fuel handling building; intermediate building; diesel generator building; and control buildin In general, equipment storage was satisfactory and in accordance with the licensee's administrative procedure However, during the-reactor building inspection, a core flood tank level indicator had an active leak with substantial boron encrustation. The licensee was responsive and corrected this ite .2 Outstanding Licensee Identified Items The inspector reviewed selected portions of the licensee's applicable corrective action tracking systems to determine if any adverse condition for safety-related equipment operability existe The inspector's review included tracking systems for open mainte-nance job tickets, open exceptions and deficiencies (E&Ds)

associated with Technical Specification surveillances, and open plant modification incomplete work list item The inspector reviewed the open job tickets and discussed all work that had been classified as priority one, two and three. Of the

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priority two and three work, the inspector determined that the work required by these jobs would not have an adverse affect on plant safety if not completed prior to returning the plant to operatio The inspector reviewed all E&Ds noted by the licensee for all current surveillances. From this sampling the inspector determined that the licensee was properly conducting required surveillances and none of the noted deficiencies or exceptions would adversely affec plant safet The incomplete work items list (IWL) was reviewed. The inspector discussed the IWL with licensee representatives. The licensee adequately resolved or addressed each item on the IWL to ensure that no adverse condition would exist due to an item remaining ope The inspector found no conditions that would adversely affect plant safety in these areas or inconsistencies with regulatory require-ment .3 Outstandina Inspection Findings The inspector reviewed the Region I file of outstanding inspection findings to identify any equipment operability problems that would adversely affect safe operation of the facility. No such conditions were identifie .4 Valve Lineup Verifications As part of the validation of the THI-1 readiness for restart and subsequent safe operation at power, the NRC TMI-l Restart Staff independently verified the position of safety-related valves. The inspectors, with the aid of auxiliary operators, verified the position of valves listed in the following operating procedures:

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Operating Procedure (OP) 1104-4, " Decay Heat Removal System;"

-- OP 1104-5, " Reactor Building Spray;"

-- OP 1105-2, " Reactor Protection System;"

-- OP 1105-3, " Safeguards Actuation System;"

- -- OP 1105-6, "Non-Nuclear Instrumentation;"

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OP 1107-2, " Emergency Electrical;" and,

-- OP 1107-3, " Diesel Generator."

No conditions were identified that would adversely affect safe operation of the facility.

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f8 J s 7.5 Restart Condition Verification On October 2, 1985, when the Office of Nuclear Reactor Regulation issued the TMI-1 restart conditions, the inspector verified that there were no substantial changes to these conditions that were verified during NRC Inspection 50-289/85-19. In the applicable inspection report, the restart conditions were labelled " proposed license conditions 2.C.9, 2.C.10, 2.C.11, 2.C.12, and 2.C.13." How-ever, the. letter designations (2.C.9, 2.C.10, 2.C.11, 2.C.12, and 2.C.13) are now replaced by the numerical listing (1, 2, 3, 4, and 5 respectively) as shown on the attachment of the NRR letter of October 2, 1985. Future NRC staff references to applicable conditions will be according to the latter numerical listin .6 Conclusion Since no items were identified above that would impact the safe restart of the facility, the TMI-1 Restart Staff recommended to Region I management on October 3, 1985, that the licensee be released from the first FRC hold point, reactor criticality. At 10:19 a.m. on October 3, 1985, the Ragion I Administrator release the licensee from that hold poin . Exit Interview The inspectors discussed the inspection scope and findings with licensee management at the exit interview conducted on October 11, 1985. The following personnel attended the final exit meeting:

H. Shipman, Operations Engineer, TMI-1 S. Otto, Licensing Engineer, Technical Functions R. Tools, Operations and Maintenance Director, TMI-1 J. Colitz, Plant Engineering Director, TMI-1 H. Hukill, Vice President and Director, THI-1 D. Shovlin, Maintenance Manager C. Hartman, Plant Engineering Manager M. Nelson, Review Program Supervisor W. Stanley, Operator Training Manager (Acting)

R. Neidig, Communications As discussed at the meeting, the inspection results are summarized in the cover page of the inspection report. Licensee representatives indicated that none of the subjects discussed contained proprietary informatio Unresolved items are matters about which information is required in order to ascertain whether they are acceptable items, violations or deviation Unresolved item (s) discussed during the exit meeting are documented in paragraphs 3.2.7 and ,

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