IR 05000410/1992027
| ML17058B041 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 11/10/1992 |
| From: | Conte R, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17058B040 | List: |
| References | |
| RTR-NUREG-1455 50-410-92-27, NUDOCS 9211180253 | |
| Download: ML17058B041 (30) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
REPORT NO.
92-27 FACILITYDOCKET NO.
50-410 FACILITYLICENSE NO.
NPF-69 LICENSEE FACILITY Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, NY 13212 Nine Mile Point, Unit 2 EXAMINATIONDATES September 14 - 18, 1992 INSPECTORS Walter H. Baunack, Sr. Reactor Engineer William A. Maier, Operations Engineer LEAD INSPECTOR:
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. H. Williams, Sr. Operations Engineer Date WR Section, Operations Branch Division of Reactor Safety APPROVEDBY'hard J. Conte, Chief BWR Section, Operations Branch Division of Reactor Safety I/ /cl Dae, Inspection conducted from September 14 - 18, 1992 (Report No.
50-410/92-27).
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' I result of the August 13, 1991, transformer failure event, as described in NUREG-1455.
A procedures inspection and a follow-up on procedure weaknesses identified in Examination Report 50-410/92-06 was included in this inspection.
~Re uit:- The licensee has revised certain procedures that were previously identified as deficient and provided training to licensed operators on these revised procedures.
Actions have been taken by the operating organization to reduce shift coping concerns and provide more efficient use of the Shift Technical Advisor. The licensee has initiated changes in the
'yi211180253 921110 PDR ADOCK 05000410 Q
operating organization to help ensure that the Chief Shift Operator (a licensed Reactor Operator (RO)) does not direct licensed activities of other ROs.
This issue is unresolved pending completion of additional NRC staff observation.
NRC concerns over condensate booster pump injections have been adequately'addressed by the licensee.
Reactive training on Licensee Event Report lessons learned is normally conducted with generic lesson plans.
The effectiveness of this training was difficultto assess.
Several concerns over procedure adequacy was discussed and resulted in the unresolved items.
In addition, a previous unresolved item dealing with compliance with ANSVANS 3.2 - 1982 was reviewed and left ope DETAILS
.1.0 INTRODUCTIONAND SCOPE On August 13, 1991, Nine Mile Point Unit 2 experienced a'failure in the main transformer'hat resulted in simultaneous loss of five of ten uninterruptible power supplies (UPS).
Loss of these five nonsafety-related UPS caused the loss of reactor control rod position indication and a large portion of other control room instrumentation, including annunciators.
The reactor was safely taken to cold shutdown.
An Incident Investigation Team (IIT) was dispatched by the NRC to investigate th'e event.
NUREG-1455, "Transformer Failure and Common-Mode Loss of Instrument Power at Nine Mile Point Unit 2 on August 13, 1991,"
documents the IIT investigation.
Further, NRC Examination Report No. 50-410/92-06 identified weaknesses in control room command and control due to the Chief Shift Operator (CSO) directing other licensed operators.
The exam report also discussed procedure deficiencies and noted that symptoms and automatic actions are not listed in the procedures.
Also, there was no distinction between immediate and subsequent operator actions.
The procedure format deficiencies were identified as an unresolved item (URI 410/92-06-01).
This procedural concern of the NRC staff was addressed also in NUREG-1455.
This inspection follows up on several issues identified in NUREG-1455 and in a licensee letter'dated May 11, 1992, to Mr. Marvin %. Hodges (NRC) from Mr. B. Ralph Sylvia of Niagara Mohawk. It follows up also on the issues identified in the Examination Report No.
50-410/92-06 discussed above.
This inspection also examined the licensee's procedures for
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conformance to regulatory requirements and technical adequacy in accordance with the guidance in NRC Inspection Procedure 42700.
2.0 SUMMARYOF CONCLUSIONS Shift Coping - The licensee's actions on this issue were determined to be an improvement to alleviate the NRC staff's shift coping concern.
This issue is closed.
(Section.3.1)
Chief Shift Operator (CSO) Authority and Duties - The licensee has taken some actions; and other actions are continuing in this area.
The item is unresolved (Section 3.2, URI 410/92-27-01).
Training on Condensate Booster Pump Injections - The licensee's actions are adequate.
(Section 3.3)
Reactive LER Training Effectiveness - The licensee has a program to train on lessons learned from operating experience.
The training was effective for the condensate booster pump injections.
Training effectiveness for other operating experiences described in LERs was difficultto assess due to lack of details in the generic lesson
plans and poor recordkeeping.,
These practices
'appeared to be compensated for by good communications by the Operations and Training Departments (Section 3.3).
Procedure revisions as a result of NUREG-'1455 - Licensee commitments were verified (Sections 3.4.2 to 3.4.6).
Procedure Adequacy - The licensee has committed to several actions associated with procedures.
Unresolved Item 92-06-01, dealing with procedure format and improving compliance with ANSI/ANS 3.2-1982, remains open (Section 3.4.1).
The use of EPIPs during the emergency of August 13, 1991, is unresolved item 410/92-27-02, (Section 3.4.8).
The compliance with the technical specification requirements of 6.8.1 is unresolved item 410/92-27-03, (Section 3.5.6).
3.0 ISSUES/FINDINGS 3.1 Shift Coping The inspectors evaluated the status and effectiveness of Niagara Mohawk's actions to enhance the operators'bility to cope with complex emergency events such as the transformer failure of August 13, 1991.
The inspection effort in this area dealt with observations of the integration of dedicated Shift Technical Advisors (STAs) into the shift crews.
Training personnel were interviewed to determine the status of including STAs in the licensed operator requalification program.
STAs began training alongside their assigned crews in March 1992 and were fully integrated into the requalification (or continuing training) program by the end of June 1992.
A memorandum from the Operations Department to the Training Department gave the initial guidance for familiarizing the control room staff with their new duties.
STAs attended the same requal training as the licensed operators on their crews.
They participated in the dynamic simulator team skills training and participated in evaluated operating tests.
Allof the qualified STAs receive'd Senior Reactor Operator (SRO) certification from the facility.
The inspectors observed dynamic simulator requalification training during the ihspection.
This observation consisted of three training scenarios that were administered to one operating crew.
Two of the three scenarios trained on symptoms that were encountered by the crew during the transformer failure event.
The STA performed an independent review of vital plant parameters and also provided some timely notifications to the Assistant Station Shift Supervisor (ASSS) of entry conditions into the Emergency Operating Procedures (EOPs).
The ASSS was devoted solely to the execution of the EOPs.
The ASSS directed the licensed
'perators and provided periodic updates to the control room team on the status of the scenario.
The Station Shift Supervisor (SSS) classified the event in accordance with'the station emergency plan and performed other duties as the Station Emergency Director.
The
SSS checked on the progress of the ASSS in the execution of the EOPs and performed a redundant marking of the procedural steps that had been executed.
This backup check of the ASSS's duties was consistent with prescribed administrative procedural guidance.
Niagara Mohawk submitted a request to NRC for a license amendment to the Technical Specifications (Tech Specs) regarding minimum shift crew composition in April 1992, prior.
to the transformer failure event.
License Amendment Number 34 was approved by NRC staff in September 1991, following the event.
This amendment provided for the inclusion of.
a dedicated STA in Table 6.2.2-1, "Minimum Shift Crew Composition," of the Tech Specs.
A footnote was added to the table (footnote g) that would allow the combining of the ASSS and STA functions ifa dedicated STA was not available.
This provision would allow the control room staff to revert to its previous staffing arrangement prior to the Tech Spec amendment.
The inspectors concluded that pr'evious staffing arrangement, when combined with the activation of the Site Emergency Plan, could cause shift coping problems as existed for the August 13, 1991, transformer failure event.
Accordingly, the inspectors interviewed operations management to determine the management philosophy regarding the Tech Spec amendment and under what circumstances Nine Mile Point Unit 2 intended to utilize the provision of footnote "g" to Table 6.2.2-1.
Operations management stated that the ASSS and STA roles would be combined only ifan emergency or sudden sickness caused a loss of the dedicated STA. An additional reactor operator-licensed individual would assist in the execution of the Emergency Plan.-'perations management said that this option was the least desirable and that effort would be first expended to obtain replacement STA. This position was supported by an Operations Department Procedure that lists the combination of the ASSS and STA functions under one individual as the least desirable option to exercise and stresses that it should be minimized.
Also, the inspectors later noted that the STA position was subject to an additional footnote restriction (footnote b) to Table 6.2.2-1.
This footnote allows the shift crew composition to be one less than the required levels of the table for a period of up to two hours provided immediate action is taken to restore the composition to the minimum levels.
The inspectors discussed with Nine Mile Point 2 representatives at the exit meeting that footnote "b" was an overriding requirement to footnote g and that the provisions of footnote "g" would be valid only during the two hours that action was being taken to obtain a replacement STA-qualified individual. The Nine Mile Point 2 Project Manager from the NRC Office of Nuclear Reactor Regulation (NRR) later concurred with the position stated to Niagara Mohawk management during the exit meeting with respect to the footnote precedence noted above.
Licensee representatives acknowledged the above position.
In conclusion, the actions taken by Niagara Mohawk management to alleviate the burden on'he operating shift during times when the Emergency Plan is in effect are consistent with the stated corrective action in their response letter.
These site-specific actions, including the related Tech Spec changes, are an improvement to alleviate the NRC staff's shift coping concern.
The issue regarding shift coping, identified in NUREG-1455, is considered close.2 Chief Shift Operator Authority C
The inspectors reviewed actions taken to address NRC concerns over the role exercised by the Chief Shift Operator (CSO) in directing the actions'of licensed operators.
This concern was identified during a licensed operator replacement examination administered earlier this.'year and documented in Examination Report No. SO-410/92-06.
The inspectors interviewed Training Department personnel to determine how CSOs are trained on their duties and authorities during licensed operator training.
Training personnel stated that the philosophy exercised during training is for instructors to emphasize that CSOs are not to direct any licensed activities of the other licensed operators in the control room.
Instructors have been directed to correct, on the spot, any observed instances of improper direction by CSOs.
The inspectors interviewed Operations Department management to determine ifany actions on their part had been taken related to CSO authority.
The ASSS has been relocated to the control room.
The STA's desk lias also been moved to the same area.
Operations management believes the increased management oversight will result in licensed activities being directed by the appropriate SRO-licensed individual.
Procedural guidance supports this by requiring a licensed SRO to be physically in the control board area for all reactivity manipulations.
However, administrative procedure gives a certain amount of authority and supervising oversight to t)ie CSO.
The inspectors noted that the NRC staff would continue to monitor the activities in this area during routine inspection observations in the plant and as evidenced by operator performance in future operator licensing examinations.
The action of the CSOs in independently directing licensed activities of other licensed operators is an unresolved item (URI 92-27-01).
3.3 Condensate Booster Pump Injections and Reactive Training Effectiveness The inspectors reviewed actions taken by Niagara Mohawk, in response to concerns stated by the IITwith regard to the injection of cold water by the condensate booster pumps during the transformer failure event.
This review included:
training materials developed for providing guidance in anticipating and avoiding a reactor vessel overfill condition.
evaluating the effectiveness of the training for prevention of reactor vessel overfill.
evaluating Niagara Mohawk's actions to provide reactive training to licensed operators in response to operational events that are documented in Licensee Event Reports (LERs).
Niagara Mohawk indicated that issues of operator performance cited in NUREG-1455 have been incorporated into'licensed and nonlicensed operator training.
Training records indicated completion of NUREG-1455 training by all operators enrolled.in licensed and nonlicensed
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requalification training during March 1992.
The inspectors reviewed the content of the lesson plan used for its adequacy in covering the operation of the condensate booster pumps and the reactor vessel overfill.
The lesson plan was a generic plan dealing with Licensee Event Report (LER)/Significant Event Report (SER) Review, and its content listed only broad concepts to be reviewed with the operators.
The exact items of NUREG-1455 that were presented by the instructors were apparently at the discretion of the instructor, and no documentation of the items covered in the lecture was recorded.
Simulator scenarios to exercise the operating crews'bility to anticipate and correct potential reactor vessel.overfills by the condensate booster pumps have been developed and implemented into licensed operator requalification training.
A scenario written to train on these concepts was used for the NRC-administered requalification examination in December 1991.
The scenario bank was reviewed for scenarios that involved operations of the condensate and feed systems.
The inspectors identified nine other scenarios that included potential reactor vessel overfill events.
The inspectors observed licensed operator requalification training that was being given the week of the inspection.
Portions of three simulator lesson plans that involved potential vessel overfill 'were observed.
These were all given to the same operating crew.
Each lesson plan consisted of a period of classroom instruction that focused on a particular portion of the Emergency Operating Procedures (EOP) flowcharts.
The classroom lecture was immediately followed by a training scenario that exercised the concepts taught in the classroom.
The crews'erformance during the scenarios showed that the training has sensitized operators to the need to anticipate potential vessel overfills.
The inspectors observed one scenario that involved a failure of the feedwater master controller and the loss of both feed pumps.
The control operator responsible for level control reported that one of the level control valves (LV-10s) was failed open.
He cautioned another operator, who was relieving him at the feedwater control station, about the consequences of depressurizing below the condensate booster pump shutoff head with the valve failed open.
The ASSS asked for the status of the LV-10s as was required by the scram procedure.
Communications by the crew members regarding the evolutions in progress and the final desired plant conditions were timely and effective.
Based on these observations, the inspectors concluded that the specific LER NUREG-1455 training received for the crew observed was effective.
However, the inspectors attempted to determine how effective LER training was in response to operational events that are covered by LERs in general.
Seven LERs were chosen for review. Allof the LERs chosen dealt with either personnel performance or work practices
issues.
Four of the LERs selected were trained upon using generic lesson plans.
The lesson plans used for training on these LERs reference procedure changes that were made as a result of the events or programmatic overviews of the administrative mechanisms that were responsible for the events.
No documentation was available that described the exact content of the training, including lessons learned.
More specifically, the inspectors reviewed a draft copy of the LER that covered a reactor'cram on August 22, 1992.
The cause of the scram was improper operation of the Feedwater System.
Niagara Mohawk training personnel were interviewed regarding training planned in response to this event.
They described a training program that is being developed for licensed operators to address the identified weaknesses shown. by personnel involved with recent feedwater problems.
This training was requested by the Operations Department management, and consists of some'on-shift instruction coupled with evolutions performed on the plant simulator.
The inspectors concluded that there was a good interface and communication between the Training and Operations Departments on the specific issue.
The inspectors concluded that the actions stated in the Niagara Mohawk letter of May 11, 1992, have been completed.,The scenarios developed and trained upon have sensitized operators to the potential for reactor vessel overfill by the condensate booster pumps at reduced reactor coolant system pressure.
Sufficient evidence existed that the training on NUREG-1455 issues has also'been completed, but the inspectors were unable to determine the specific scope/details of this training.
Recordkeeping of the details of LER training was poor, but appears to be compensated by good communications between the Training and the Operations Departments..
3.4 Adequacy of Plant Specific Operating and Recovery Procedures 3 4.1 (Open) Vnresolved Iteni 410/92-06-01:
Immediate Operator Actions in Procedures Plant procedures'do not specifically identify immediate operator actions in accordance with ANSI 3.2-1982, "Administrative Controls and Quality Assurance for the Operating Phase of Nuclear Power Plants."
This issue was identified in NRC Examination Report 50-410/92-06, as an unresolved item (URI 410/92-06-01) and also discussed in NUREG-1455.
The inspectors determined that the following actions were planned or have been taken by the licensee to resolve this issue.
The licensee plans to complete these actions by March 31, 1993.
A review of station procedure compliance with ANSI 3.2-1982 requirements willbe conducted by the Quality Assurance organizatio Gperating procedures with off normal responses will be reviewed for immediate operator actions.
These procedures willbe reformatted, ifnecessary, to include clearly-described immediate operator actions.
The licensee willrewrite the procedures for reactor scram response, loss of annunciator response, and emergency power restoration for series l,uninterruptible power supplies to provide a distinction between immediate and subsequent operator actions.
Pending completion of licensee action,. as noted above and subsequent NRC Region I review, the area remains open.
3.4.2 Revise OP-101C, "Plant. Shutdown" OP-101C, Plant Shutdown, was verified changed to clarify entry conditions from the Emergency Operating Procedures such that the procedures are complementary and not in conflict. This was an issue identified in NUREG-1455.
3.4.3 Surveillance Tests After SRVs Open During the August 13, 1991, event, operators did not recognize that two safety relief valves (SRV) had lifted until later in the event.
The Technical Specifications require a vacuum breaker test be performed within two hours following the lifting of an SRV.
Safety relief valve opening is a normal response to a turbine trip from full power.
However, the loss of instrumentation made it more difficultto determine that a turbine trip had occurred, Upon discovery that two SRVs had opened, the operators performed the required surveillance within two hours of identification.
Procedure N2-OP-101C, Plant Shutdown, was changed to alert operators of possible SRY lifting. Also, a r'equest for routine training on the procedure revision was initiated.
3.4.4 Procedure for Restoring UPS Power NUREG-1455 described a concern dealing with the lack of procedural guidance for restoration of UPS to normal.
The licensee revised OP-71, "13.8Kv/4160/600 AC Power Distribution," to include guidance on the restoration of UPS units that have tripped.
The inspectors reviewed the procedure change and the training associated with the change.
A JPM has been written and used for training to cover restoring UPS power.
Comments relating to procedure review are included in paragraph 3.5.1 of.this report.
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3.4.5 Manual Initiation of RCIC NUREG-1455 noted that RCIC was initiated manually prior to EOP entry, even though the RCIC operating procedure, OP-35, cautioned that manual initiation was to be used only when required by.EOPs.
The licensee revised OP-35, "Reactor Core Isolation Cooling," to allow
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manual initiation as directed by the SSS.
The reason for SSS approval as opposed to ASSS approval was discussed with the licensee and no reason could be identified.
The licensee indicated that the procedure willbe revised.
The inspectors noted that EOP-6, Attachment 4 provides*the only instructions for throttling RCIC injection; however, throttling of RCIC injection is performed during operations outside of the EOPs.
To provide clearer guidance for throttling RCIC, the instructions willbe added to Procedure OP-35 and deleted from EOP-6, Attachment 4.
The licensee initiated a Procedure Change Evaluation dated September 18, 1992, to correct this problem.
3.4.6 Alternate Method for Determining Control Rod Position NUREG-1455 noted that all control rod position indication was lost during the event.
The licensee developed a procedure for an alternate method of determining rod position.
The team reviewed changes to OP-96, "Reactor Manual Control. and Rod Position Indication System," to provide an alternate method for determining control rod positions.
Training on the procedure change was also reviewed.
Except for the issue discussed in section 3.5.3 dealing with operator aids, no concerns were identified in this review.
3.4.7 Records of Major Events NUREG-1455 noted that the recording of times of major events such as EOP exit and reactor shutdown was not done.
The team reviewed administrative procedures GAP-OPS-01,
"Administration of Operations," and N2-ODI-5.01, "Log Maintenance," and concluded that adequate instructions for log keeping, shift records, and shift turnover have been provided.
The inspectors noted that the Emergency Plan implementing procedures also provide instruction to a number of key personnel for logging important information during an emergency.
The licensee described plans to emphasize the importance of recordkeeping during training.
These actions are adequate to resolve this issue.
3.4.8 Use of Procedures During Emergencies The inspectors reviewed use of recovery procedures during the event, as noted in NUREG-1455.
The IIT concluded that lack of certain procedural steps unnecessarily challenged the operators.
The inspectors noted the following guidance and requirements for this area.
NRC guidance in Part 9900 of the NRC Inspection Manual recognizes that in emergency situations, when time for proper safety response does not permit changing a deficient procedure, then deviation from the procedure in the interest of plant safety is considered appropriate.
This expectation is based on the requirements and guidance concerning use of procedures for all activities affecting quality.
Additionally, requirements are given in 10 CFR 50.54(x) which states that a licensee may depart from a license condition or technical specification in an emergency when the action is immediately needed to protect the public health and safety, and
no action within the'license conditions or technical specifications that can provide adequate or equivalent protection is immediately apparent.
Further, 10 CFR 50.54(y) requires approval of a licensed senior operator prior to taking the action permitted by paragraph 50.54(x).
The licensee's Emergency Plan and implementing procedures required by 10 CFR 50.47 provide detailed requirements for individuals involved with specific emergency response functions. "
Technical Specifications section 6.8(f) states that written procedures shall be established, implemented, and maintained covering Emergency Plan implementation.
The licensee indicated that recovery actions of the damage control teams were directed by the Emergency Director.
The five nonsafety-related UPS that were lost were restored within about one-half hour after the main generator tripped (5:48 a.m.).
After the Technical Support Center (TSC) was activated, the Emergency Director concluded that maintaining the UPS loads on the maintenance supply was not acceptable with the Site Area Emergency still in effect and the loads still vulnerable to power loss.
Therefore, he directed the damage control team to restore the five nonsafety-related UPS to normal operation.
The UPS system engineer assisted the damage control team in this operation.
UPS IC and ID were returned to
normal power at 9:50 a.m.
UPS IG was placed on normal power at 10:20 a.m.
Attempts to return UPS IA and IB to normal power were unsuccessful
~ The primary loads on each of the 5 UPS units is given in the following table.
MAJOR UPS LOADS'A
]D Plant Computer 3-D Monicore Components RPIS RSCS RWM Rad Waste SPDS SRM Recorder Annunciators RSCS Lights Lights FWCS Page Page GETARS Stack Gas Telephone Ann unciators SRM Recorder Rad Monitors.
RHR Monitors The NRC staff in the regional response center were concerned that the UPS transfers were not being procedurally controlled and could result in additional damage or create an unexpected event.
As a result of these concerns, an NRC resident inspector discussed the transfer operations with the systems engineer and observed damage control team operations.
'10 UPS were in operation; 5 lost power during the event (1A, 1B, 1C, 1D, and 1G); 2 safety-related and 3 commercial grade UPS operated through the even Based upon the discussion with the systems engineer and observing the transfer of 1G, the resident inspector concluded that the licensee had considerable expertise operating the unit.
However, he noted that the evolutions were directed by the system engineer without the use of procedures.
P Between 7:40'a.m. and 8:07 a.m., the TSC, EOF, and OSC were activated.
This allowed additional resources to be available to handle the emergency in a carefully planned out manner in accordance with established emergency procedures.
The actions of the maintenance coordinator, OSC coordinator, and Damage Control team coordinator, with
'respect to returning the UPS power to normal was not determined during this inspection.
These individuals had specific roles and responsibilities, including technical and administrative direction to the damage control team, during the emergency.
Emergency Plari Implementating Procedure S-EPP-22 provides guidance for the conduct of damage control team activities during an emergency.
S-EPP-22 indicates that damage control teams should be briefed on procedural adherence and should review procedures written for the task, if applicable.
It also suggests strongly that an emergency procedure should have been written, reviewed, and approved for the transfer operation.
Based upon this information, the inspector could not conclude that all applicable procedures were followed.
Licensee representatives agreed to review this matter.
This issue is
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unresolved pending completion of licensee action and further NRC staff review (URI 410/92-27-02).
3.5 Review of Licensee Procedures As a result of the procedure concerns discussed in NUREG-1455 and the NRC Examination Report No. 50-410/92-06, the inspectors reviewed procedure compliance with administrative requirements and technical adequacy.
Procedures OP-71, OP-74A, OP-96, and OP-35 were reviewed.
A walkdown of selected procedures was also conducted.
The licensee's procedure upgrade program was examined.
Observations by the inspectors associated with each procedure are listed below.
3.5.1 OP-71, "13Kv/4160/600V A.C. Power Distribution" Breakers were identified by panel location as opposed to exact nomenclature found on plant equipment tags.
The licensee's procedure writers manual requires breakers be identified by equipment tag information.
The table in Step 33.5 had an incorrectly numbered breaker.
The technical adequacy of Step 33.5 was questioned by the inspectors.
'tep 24.0-i identified a supply breaker as CB-1, but plant prints and equipment tag nomenclature do not identify the breaker as CB-Step 33.3 refers to Attachment 1, which should be Attachment 2.
3.5.2 OP-74A, "Emergency D.C. Distribution" This was an upgraded procedure.
Breakers were identified by panel location as opposed to exact nomenclature found on plant equipment tags.
The licensee's procedure writers manual requires breakers be identified by equipment tag information.
Steps 2.1.4 and 2.1.5 do not identify which breaker feeds Division I or Division II battery chargers.
3.5.3 OP-96, "Reactor Manual Control and Rod Position Indication System" Step 8.1 identifies RPIS power switch C12A-Sl.
This switch, which is in a cabinet in the control room, is marked with a magic marker.
This is an example of poor control over operator aids.
3.5.4 OP-35, "Reactor Core Isolation Cooling" The procedure did not include RCIC throttled operation.
3.5.5 Procedure Upgrade Program In response to concerns raised in the examination report about procedures, the licensee stated that their ongoing procedure upgrade program would address these issues.
The inspectors noted that the procedure upgrade program was initiated in 1989, and would make human factors improvements and incorporate outstanding procedure changes.
Procedures to be upgraded include operations, surveillance, preventive maintenance, and administrative procedures.
Apparently, this program did not receive a high priority until September 1992.
Prior to September 1992, the project consisted of a coordinator and two or three individuals.
The project now consists of a coordinator and twelve individuals.
The licensee indicated that about 180 upgraded procedures have been issued.
The goal is to have 396 procedures issued by January 1993.
3.5.6 Procedure Concerns As a result of the review discussed in sections 3.5.1 to 3.5.5, the inspectors expressed concern over the number of problems identified in review of a small sample of procedures.
There appears to be a need for increased attention to preparation and maintenance of
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procedures.
This area is an unresolved item URI 410/92-27-03, pending further licensee action and NRC staff review of the licensee's procedure upgrade results.
4.0 EXITMEETING An exit meeting was conducted on, September 18, 1992.
The team's findings were discussed at this meeting except for the issue of using EPIPs during the emergency.
This issue had not been identified at the time of the exit.
Attendees at the exit meeting are listed in Attachment 1.
Attachment:
List of Attendees
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ATTACHMENT1 LIST OF ATTENDEES NRC Exit Meeting, September 18, 1992
~Mi M
k W. D. Baker J. T. Coney A. F. Zallnick
,J. B. Helker R. J. Crandall J. G. Poindexter D. W. White R. K. Slade T. Mattessech A. DeGracia J. G. Reid N clear Re ulat r ommi.ion W. L. Schmidt R. J. Conte J. H. Williams W. A. Maier