ML18054B105

Responds to NRC 891018 Ltr Re Violations Noted in Insp Rept 50-255/89-19 & Request for Addl Info.Corrective Actions: Changes to plant-specific Auxiliary Operator Task List Requested.Clarification of Stated FSAR Statement Encl

ML18054B105
Person / Time
Site:	Palisades
Issue date:	11/17/1989
From:	Berry K CONSUMERS ENERGY CO. (FORMERLY CONSUMERS POWER CO.)
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
IEIN-86-064, IEIN-86-64, NUDOCS 8911210250
Download: ML18054B105 (14)

Text

I I

• • MICHl&AN'S PRD&RESS consumers Power POWERIN&

Kenneth W Berry Director Nuclear Licensing General Offices: 1945 West Parnell Road, Jackson, Ml 49201 * (517) 788-1636 November 17, 1989 Nuclear Regulatory Commission Document Control Desk Washington, DC. 20555 DOCKET 50-255 - LICENSE DPR PALISADES PLANT -

WRIT'l'EN RESPONSE TO IR 89019 NOTICES OF VIOLATION AND REQUEST FOR ADDITIONAL INFOR¥..ATION NRC Inspection Report 50-255/89019 '(DRS) dated October 18, 1989 transmitt~d two notices of violation as a result of a special safety inspection conducted by a NRC EOP Inspection Team on July 24 through August 4,_1989 and requested

• Consumers Power Company provide a written response. Jn addition to the requested responses to the notices of violation, Consumers Power Company was requested to provide information addressing three NRC identified concerns.

This information is provided on Attachment II of this letter.

Kenneth W Berry Director, Nuclear Licensing CC Administrator, Region III, USNRC

. NRC Resident Inspector - Palisades Attachment R911210250 R91117 F~[IR 0

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0 OC1189-0222-NL04 A OV5 ENET?G'y' COMPANY

ATTACHMENT I Consumers Power Company Palisades Plant Docket 50-255 Written Responses To The Notices Of Violation Presented In IR 89019 November 17, 1989

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1 ATTACHMENT I Violation (255/89019-03)

Criterion II of Appendix B to 10CFR Part 50 requires in part that the licensee shall have a program that will ". *

• provide for indoctrination and training

• of personnel performing activities affecting quality as necessary to assure that suitable proficiency is achieved and maintained".

Contrary to the above, the licensee did not have an adequate program for

• training auxiliary operators (AOs} on the actions that they were to perform as stated in the Emergency Operating Procedures (EOP), in that none of the six AOs interviewed had been trained on, or walked through these actions. The licensee had also failed to fully implement the provisions of the existing training program which dealt with training on activities required under the EOPs.

This is a Severity Level IV violation.

Reason For Violation During the Palis.ades' -EOP upgrade, project, including the development of Administrative Procedure 4.06, "Emergency Operating Procedure Development and Implementation"-, the primary goal was to make the EOPs easily understood and useable by licensed operating personnel. As a result, an extensive training program was developed and instituted for licensed personnel. Prior to instituting the upgraded EOPs, AOs received EOP specific classroom training.

However, when training program scope was originally evaluated, the neeq for an AO on-the-job or continuing training program was not identified. A primary input to this decision was that AO .required actions during EOP performance were spe~ified within System Operating Procedures (SOPs) and that training already existed. It was not *recognized, however, that even though these tasks were specified within SOPs, they were not perfo*rmed on a frequent basis.

As noted in the Inspection Report, while AOs were able to simulate the tasks required by the EOPs, completion of the tasks were not always timely.

Consumers Power Company firmly believes that* Palisades AOs can complete the

• required tasks in the necessary time periods, however, we also believe that by enhancing our AO training program proficiency will be increased. This is evid_enced by the 1989 Operations Department goal, established in late 1988, to develop an on-the-job training (OJT) program for all AO EOP tasks. At the time of the inspection this goal had not yet been realized.

Correction Actions Taken And Results Achieved

• Since the inspection the following actions have been completed regarding AO response to tasks required* by the EOPs:

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• • 1. AO tasks required by the EOPs have been identified (37 important and infrequently performed tasks in total).

2. Based on the identified tasks, changes to the Plant specific AO task list have been requested.

3. An OJT program for AOs has been developed that encompasses the identified EOP tasks.

4 *. All AOs have completed the OJT.for 20 of the most important and infrequently performed EOP tasks identified.

5. *'All AOs have attended classroom training with licensed operators on EOP 5.0, "Steam Generator Tube Rupture".

Corrective Actions To Be Taken To Avoid Further Noncompliance In addition to completion of the remaining 17 important and infrequently performed required AO tasks identified during review of the EOPs, the following actions will be taken:

1. All AOs will attend classroom training for EOPs 1.0 through 9.0 (EOP 5.0 training already is completed). This training is intended to provide the AO with additional insight into accident mitigation efforts and to provide perspective relative to their assigned tasks.

2. Administrative Procedure 4.06 will be revtsed to formally define AO training requirements on EOPs.

3. EOP lesson plans will be revised to ensure an overview of procedural flow will be* presented and to further correlate AO tasks into accident mitigation strategies.

4. Continuing OJT requirements for AOs on EOP tasks will be developed~

5. The OJT manual for Initial AO Training will be updated to more clearly *.:*.

• specify the 37 tasks identified during that EOP review.

Date When Full Compliance Will Be Achieved The OJT on the remaining 17 tasks will be complete by March 1, .1990. The EOP classroom training for AOs will be complete by June 30, 1990. Administrative Procedure 4.06 will be revise4 by August 1, 1990. EOP lesson plan revisions, development of continuing and initial OJT training requirements will be complete by December 31, 1990 .

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3 Violation (255/89019-05)

Criterion XVIII of Appendix B to 10CFR Part 50 requires in part that ". ,

• A comprehensive system of planned and periodic audits shall be carried out to verify compliance with all aspects of the Quality Assurance Program and to determine the effectiveness of the program".

Contrary to the above, the licensee failed to perform planned and periodic audits of the Palisades EOPs from June 1986 until July 1989. This was evidenced by the fact that during this period, no Quality Assurance (QA) audits of the EOPs had been performed and the one surveillance which extended *over a two year period failed to identify ineffective training of some Operations personnel, and inadequacies with the verification and validation program.

This is a Severity Level IV violation.

Reason For Violation QA Department involvement in the EDP upgrade program began in April 1986 with the review of Administrative Procedure 4.06, "Emergency Operating Procedure Development and Implementation". Subsequent to this~ preliminary drafts to each .EDP (except EOP 3.0) were reviewed between June and October 1986 resulting in final concurrence with Rev 0 of each EOP. Since then, each revision to each EOP, including EDP 3.0, has received QA review (with the exception of a few minor technical revisions) in accordance with Plant requirements for procedure deveiopment. A QA surveillance of the EOP upgrade program was started in 1987.

This surveillance effort was intendea to evaluate the status of the program with respect to Information Notice 86-64, which identified concerns relating to licensee failure to meet NRC commitments as documented in procedures generation packages. The surveillance scope was limited to a review of the established administrative controls that addressed each element of the procedures generation packages. These controls were found as requirements in Administrative Procedure 4.06 or were verified to be implemented by reviewing various documentation. The surveillance was conducted over a period of 18 months to assure those controls remained in-place while the EOPs were being revised due to CEN-152 revisions. During the surveillance, primary emphasis was placed on assuring the EOPs conformed to the EOP writer's guidelines. The QA review of this area was a defined review in Administrative Procedure 4.06

.and was considered as part of the EOP verification process per that procedure.

Review of the last three QA Department audit reports and checklists ('87, '88 &

'89) in the area of Operations, indicated the scopes did include EOPs, The 1987 audit included interviews with several supervisors in the Operations Department, however, these interviews wer~ limited to reviewing the status of corrective actions taken to address a 1986 INFO finding on inadequate EOPs.

The portion of the 1988 Operations audit which pertained to EOPs was limited to a status review of the EDP development. The 1989 audit included a status review on EOP development and training for steam generator tube rupture (EOP 5.0 and ONP 23.2); and the loss of preferred AC bus Y30 (EOP 3.0 and ONP 24.3).

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• Both of these reviews included interviews and walkthroughs with Operations personnel.

Although these QA audits and surveillances did include certain aspects pertaining to the development of EOPs, these activities did fail to identify ineffective AO training and inadequacies in the verification and validation program as presented within IR 89019. Further evaluation performed as a result of Inspection 50-255/88020 indicates that the QA verification program (audits, surveillances and activity inspections) needs to be better aligned toward ,

performance based ver-ification methodologies. -

In summary, the focus of QA Department audits and surveillances which were conducted during and after the EOP upgrade program were not directed at identifying deficiencies in the implementation of various elements of the EOP procedures generation package. QA overview during the EDP upgrade program was mainly limited to verifying that administrative _controls were in-place which addressed each element of the procedures generation package, and that the controls continued to be in effect during subsequent EDP revisions. The quality program for this effort did not adequately emphasize actual EDP validation of operator training. Further, the quality program method to periodically review.the CPC verification processes to assure appropriate focus and allocation of resources was inadequate. -

Corrective Actions Taken And Results Achieved Consumers Power Company has reviewed its QA verification program and feels that while progress has been made toward performance based inspections, continuing efforts are_ still *warranted. As a result of, and in response to Inspection 50-255/88020, a verification committee within the QA organization has been established to review and recommend improvements to the verification program.

The recent emphasis of NUREG/CR-5151 "Performance Based Inspections" by the NRC, will have a positive effect on improving the effectiveness and produc-tivity of quality verification personnel. Consumers Power Company supports this concept_ and recognizes the need to move towards a more "performance-based" verification philosophy.

In order to correct these weaknesses, the Director of QA has established a

-Verification Committee within QA to_ review and recommend improvements to the Consumers Power Verification Program. The committee is chaired by the QA Audit Supervisor and is composed of the Big Rock Point QA Superintendent; the Palisades QA Operations Supervisor and the Palisades QA Engineering Supervisor.

This committee is tasked with determining:

1; What areas/activities should be covered by the verification program.

2. What process (ie; Audit, Surveil_lance or Activity Inspection Program) should be responsible for verification. -

3. What is the appropriate frequency for verification of each area/activity. -

4. What methodology for verification sh-ould be utilized.

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5 Corrective Actions To Be Taken To .Avoid Further Noncompliance Through completion of the review described above and implementation of the Verification Committee recommendations, appropriate elements of EOP development and implementation which require QA oversight will be identified. These elements will be incorporated into and an enhancement to existing QA surveillances and audit programs.

Additionally, review of verification program scope and resource allocation will be performed at least annually.

Date When Full Compliance Will Be Achieved The Verification Committee will complete its review and provide recommendations by August 1, 1990. Due to the unknown content of the recommendations, a date for implementation cannot be provided. The identification and implementation of further assurance elements for EOP development and. implementation process.

will be completed by August 1, 1990.

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ATTACHMENT II Consumers Power Company Palisades Plant Docket 50-255 Additional Information Requested Within IR 89019 November 17, 1989 OC 1189-0222-NL04

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• • In addition to the written responses for the Notices of Violation issued within Inspection Report 50-255/89019, Consumers Power company was requested to address the following: 1) The results of the determination as to why the main feedwater automatic runback on reactor or turbine trip does not perform as designed and a 10CFR50.59 evaluation determining *whether or not this condition represents an unreviewed safety question; 2) a description of the actions. taken to provide for a comprehensive verification and validation process that would identify and correct the types of deficiencies documented in this report and;

3)

• a description of planned actions for resolving.each of the specific items identified iri Appendices II (technical deficiencies) and III (human factors deficiencies) of this report including the dates by which.those actions will be completed. the following provide the requested information:

1. Main feedwater system automatic runback on reactor or turbine trip:

Inspection Report 50-255/89019 requested Consumers Power Company to address the following: The results of the determination as to why the

. main feedwater automatic runback on reactor or turbine trip does not perform as designed or if the system was modified, whether the 50.59 safety evaluation may have failed to* appropriately consider the effects of this system in the determinatio~ of whether an unreviewed safety question existed. The Inspection Report also indi.cated EOP 1.0 contained a.deviation from the guidelines of CEN-152.

The design and operation of the main feedwater regulating system remains as described in Section 7.5.1.3 of the FSAR.

Manual control of f eedwater flow may be assumed by the operator at any time. In the event of a reactor or turbine trip and if the feedwater pump turbine drivers are in the automatic control mode the feed pumps are automatically ramped down at a rate of 1.5 per cent per second to a speed corresponding to 5 per cent of full load feed-water flow which represents the flow required for decay heat removal through the turbine bypass valve."

FSAR Section. 10.3.1 states:

"Following a reactor and/or turbine tr:tp, the feedwater flow to the steam generator is ramped down to 5 per cent of full flow in the first 60 seconds. Once the system transient has terminated, the operator, while monitoring the primary coolant temperature, can restore and maintain the steam generator level."

The Inspection Report, however, states that the pumps ramp to "~ ** the flow required for decay heat", and as such we believe the Inspection Report interpretation of the FSAR statement to be in error. The FSAR statement explains how the feedwater system supplies sufficient feedwater to meet the decay beat removal requirements while not overfilling the steam generators. The FSAR statement is not intended to imply that feedwater pump rampdown wil1 exactly match .the decay heat generation rate. The following factors clarify this FSAR statement:.

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2 First,_ the nominal capacity of the turbine bypass valve is 5 per cent of full load steam flow. While it appears logical to set a final feed pump speed which can supply* up .to rated bypass valve flow,. there is in fact no direct operational correlation. Actual turbine bypass flow varies with PCS temperature and is not fixed in combination with pump speed or steam generator inventory.

Second, the FSAR des*criptions of the main feed pump. speed control and regulating valve control.designs in no way imply an automatic control feature which will match main feedwater flow to decay heat boil-off.

The equipment is clearly described as having fixed configurations (valves locked as-is, pumps at 5 per cent flow speed) post-trip.

Third, the decay heat to be removed varies with power level, power history, time after trip, and primary coqlant pump operating status.

Feedwater requirements after a trip also must replace steam released through the atmospheric dump valves (nominal capacity up to 30 per cent full power steam flow) to cool the PCS to 532°F (nominal) from the PCS average temperature program (Tave) at the pretrip power level. It must also restore the indicated steam generator level which dropped at the trip due to shrink.

• With respect to .time after trip, decay heat from an infinite power history would be equivalent to about 5 per cent power at 15 second$

after the trip. At 30 seconds, d~cay heat plus heat input from four primary coolant pumps is about 5 per cent power. At 60 seconds after trip, when the feed pump speed rampdown is complete, decay heat is equivalent to about 3.95 per cent power. It is logical that continuing to draw steam to run the main feed pumps in addition to ambient heat losses and steam flow through the turbine bypass valve may not be optimum for precise control of PCS temperatures and steam generator level.

Fourth, as described in the FSAR, the auxiliary feedwater system is the system which automatically starts and feeds steam generators. It is also the system used during very low flow conditions of startup and shutdown. Auxiliary feed controls and valves are sized to handle the low flow post-trip, shutdown and startup demands while main feedwater is not.

In summary, the manual control of main feedwater is explicitly allowed as the ramp down rate is fixed and is not an automatic response to the parameters requiring control, namely primary system temperature and pressure. One fixed ramp down rate will not cover all possible operating conditions at the time of the reactor or-turbine trip. In most cases, the fixed ramp down rate does not match exactly the cooling requirements and therefore .manual control is required to prevent overc'ooling. The actual EOP 3. 0 procedural steps are as follows:

2. "If both main feed pumps are operating then stop one main feed pump".

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3. "When Tave is decreasing toward 525°F, then stop remaining main feed pump 0 .*

Main feedwater control of one pump under automatic is allowed until an over-cooling condition is approaching.

Since there was no design Ghange made to the main f eedwater control system and since operation is as described in the FSAR, a 10CFR50.59 evaluation has never been required. Additionally, none is required now since the Plant is in full compliance with its licensing bases.

Consumers Power Company also believes the Emergency procedures, as adopted, do not represent a deviation from the guidelines presented in CEN-152. The three (3) success paths requiring a steam generator feed path are all similarly represented by Success Path HR-1. Step 21 of this path .indicates "Maintain steam generator (SG) levels (or -

unisolated SG level) in the normal band using [main or auxiliary]

feedwater". HR-1 also provides supplementary information guidelines, two of which are pertinent.

1. "Do not.place system in "manual"_unless misoperation in "automatic" is apparent. Systems placed in "manual must be checked frequently to ensure proper operation."

3. "Continuously monitor RCS temperature and pressure to avoid exceeding a heat re~oval rate greater than Technical Specification

-Limitations. If the heat removal rate exceeds Technical Specification limits, there may be a potential for pressurized thermal shock (PTS) of the.reactor vessel (Reference 15.8), unless Post Accident Pressure/Temperature Limits are maintained (Figure 11-1) *II The shutdown of the main feedwater pumps does not remove them from the

• three (3) success paths for*SG feed. As shown in Resource Assessment Tree E of CEN-152, both auxiliary feedwater and main feedwater represent successful SG feed paths. If the main feedwater pumps were operable when tripped, then they should also be operable on restart.

If they were inoperable for some reason before manual tripping, then they would not be available in any case.

• As stated in the Inspection Report the manual shutdown of main feedwater is only an issue for small break LOCAs outside of containment. The only system which could be a source 'for a small break LOCA outside containment, which is operational and unisolated, is the letdown and charging (CVCS) system. The maximum pipe break size for this system represents a 0.016 square foot break. According to the small break LOCA analysis of record (CEN 114 P, Amendment 1-P) for break sizes less than 0.018 square feet feedwater needs to be restored within 60 minutes. It should be noted that either main feedwater or auxiliary feedwater can be used to maintain SG levels. For breaks greater than 0.02 square feet, the steam generators are not needed as a 0Cll89-;0222-NL04

4 heat sink.

In summary, Consumers Power Company feels the control of main feedwater as addressed by the Palisades EOPs is in accordance with the plant licensing basis as described in the FSAR and is in agreement with the overall recormnendations of the Combustion Engineering guidelines in CEN-152. To redesign the main feedwater automatic control system to exactly match primary system cooling requirements on shutdown from all possible operating conditions would add unnecessary complexity to the system and would introduce additional failure modes that would still require operator intervention. The current procedure of manually controlling mairi feedwater flow or shifting to auxiliary feedwater when necessary provides the safest operation of the~ system because it provides the most precise reliable control.*

2. EOP Verification and Validation Program:

Inspection Report 50-255/89019 identified that the EOP Verification and Validation (V&V) program was not sufficiently comprehensive and needs to be more clearly defined. This conclusion was supported by examples including the V&V effort not utilizing a multi-disciplinary team that was independent of ~he staff involved in EDP generation, failing to perform walkdowns of EDP actions *that were performed outside of the Control Room and failing to walkdown procedures attendant to the EOPs.

However, even with these weaknesses, the Inspection Report still concluded that "the results of this inspection indicated that the licensee's EOPs could be effectively carried out in the Plant and could be correctly performed by the Palisades staff". Consumers Power company concurs with this conclusion and in regard to the V&V weaknesses, acknowledges them as presented.

Consumers Power Company's review of NUREG-1358, "Lessons Learned From The Special Inspection Program For Emergency Operating Procedures, March-October 1988" received just prior to the inspection will significantly enhance deficiency resolution and will incorporate appropriate information into actions taken to resolve identified deficiencies.

The following actions have already been taken in resolving the V&V program weaknesses presented:

1. Recent minor revisions to EOPs (to resolve some of the NRC EOP Audit comments) have been technically reviewed by Engineering and Reactor Engineering. Departments (ie, multi-discipline reviews).

2. Validation of the minor revision to EDP 1.0 was conducted at the Palisades simulator as well as walked through in the Palisades Control Room.

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3. During the walkthrough, validation of EOP 1.0 in Item 2 above, the Project Engineer associated with the detailed Control Room Design Review Program at Palisades was present to evaluate human factor related concerns.

4. Administrative Procedure 4.06 has been updated to remove reference to the EOP Technical Notebook.

In addition to actions completed, the following actions will take place:

a. V&V will be performed on all EOP support procedures. This effort will be completed in conjunction with an ongoing procedure improvement program, which is presently scheduled to be completed in the second quarter of 1991.

b. Multi-disciplinary reviews will be performed on the EOPs in the future. System Engineering, Reactor Engineering, Accident &

Transient Engineering and Safety Engineering expertise will be included depending on the change proposed.

c. Actions directed by the EOPs outside of the Control Room will be verified and validated as p.art of the EOP revision and/or biennial review process.

d. Waiver*criteria for V&V requirements will be defined.

Administrative Procedure 4.06 will be formally revised to address a through d above by August 1990.

3. Actions for resolution of Inspection Report 50-255/89019 Appendix II (technical) and Appendix III (human factor) deficiencies.

Appendix-tr technical deficiencies were noted in the following categories:

a. Referral to other procedures not adequate

b. Special requirements to perform a step not being specified (ie, valve keys etc)

c. Failure to have prefabricated piping/cables/procedures for identified EOP tasks (primarily maintenance issues)

d. Preferred instrumentation for p*arameter monitoring not specified e~ Degraded containment effects on instrumentation not considered Our rev:iew of the Appendix III issu.es noted the following causes :for human factor deficiencies:

a *. Lack of specific guidance provided within Administrative Procedure 4.06

b. Failure to strictly comply with Administrative Procedure 4.06 OC1189-0222-NL04

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c. Failure to wholly utilize a multi-disciplinary team for the V&V program.

During the inspection, Consumers Power Company provided initial responses to the inspectors for many of the issues noted in Appendices II and III and as such, are evaluating and implementing those initial responses. Where an NRC suggested resolution is not adopted, justification will be documented and maintained in an onsite response document. The Inspection Report, received by Consumers Power Company on October 23, 1989, requested a description of our planned action for each of the specific items noted in Appendices II and III.

Due to the number of specific items listed and small response time, a detailed action is not provided herein for each specific item. However, as indicated above, an onsite response document is being developed to incorporate line-by-line, our response to each individual inspection comments. This information will be made readily available to the NRC Resident Inspectors, one of whom was a member of the inspection team. To date, approximately 40 percent of the comments noted in Appendices II and III have been incorporated by.

revision into the EOPs. The remainder of the items will be dispositioned and as appropriate, included by revision into the EOPs by August 1, 1990.

Disposition will be based on:

a. Evaluation of proper procedure referencing

b. Evaluation of special step requirements

c. Evaluation of p~estaging equipment/procedures

d. Evaluation of preferred instrumentation for parameter monitoring

e. Evaluation of degraded containment conditions on instrumentation.

EOP basis documents will be updated by December 31, 1990. Appropriate training will be developed and implemented regarding EOP changes by December 31, !'990 in conjunction with the actions specified in our response to violation 50-255/89019-03.

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