ML19210D698

Responds to NRC 791030 Request for Info Re Licensee Methods & Schedules Not in Compliance w/NUREG-0578 or Clairification in HR Denton 791030 Ltr.Design Review to Satisfy Lessons Learned Requirements Should Be Completed by 800101

ML19210D698
Person / Time
Site:	Peach Bottom
Issue date:	11/21/1979
From:	Daltroff S PECO ENERGY CO., (FORMERLY PHILADELPHIA ELECTRIC
To:	Harold Denton Office of Nuclear Reactor Regulation
References
RTR-NUREG-0578, RTR-NUREG-578 NUDOCS 7911270462
Download: ML19210D698 (12)

Text

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Jg s PHILADELPHIA ELECTRIC COMPANY 2301 M ARKET STREET P.O. BOX 8699 PHILADELPHI A. PA.19101 SHIELDS L. DALTROFF stsc't c en o c ion November 21, 1979 Harold R. Denton, Director Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555

SUBJECT:

Implementation of Lessons Learned Short Term Requirements - Peach Bottom Nuclear Power Station

Reference:

Letter dated October 30, 1979, from H. R.

Denton, NRC, to All Operating Nuclear Power Plants; titled " Discussion of Lessons Learned Short Term Requirements".

Dear Mr. Denton:

The above referenced letter requests the licensee to identify their methods and schedules that are not in complete agreement with NUREG 0578 and the clarifications contained in the above referenced letter. Additionally, justification of each exception was requested. In our October 17, 1979 response to

, your September 13, 1979 letter, Philadelphia Electric. Company committed to implementing most of the NUREG 0578 requirements in accordance with the requested time s ch e du le . Several adjustments to these requirements were p rop os e d in our response where additional time was necessary t o p e rmi t effective implementation or p rocurement of the necessary hardware or alternative methods would satisfy the concerns identified in NUREG 0578.

We have reviewed the letter from Mr. Eisenhut responding to the BWR Owners' Group oositions. Subsequently, we have reassessed and where possible revised our p ositions stated in the Oct obe r 17, 1979 let'ter. These revised oositions, as well as a justification and description of the methods and schedules not in c onp le t e a3reement with NUREG 0578 and the clarification letter

, of October 30, 1979, are presented in Enclosure I.

Aow

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Page 2 P.hiladelphia Electric Company committec to completing a design review by January 1, 1980, relating t o implementation of many of the Short Tern Lessons Learned requirements as requested in y our September 13, 1979 letter. The clarifications contained in y ou r Oct ober 30, 1979 letter presented additional design criteria for implementing these requirements. Additional adjustments to the design criteria, not identified in this letter, may be necessary f ollowing f urther assessment during this design phase. These adjustments, if any, will be proposed following c o mp le t i on of the design phase.

We trust this letter is responsive t o y our requirements.

If additional clarification of our p osition is necessary, please advise us.

Very truly yours, f

t-Enclosure

ENCLOSURE I RESPONSE TO NRC, OCTOBER 30, 1979 LETTER

1. Relief and Safety Valve Testing, NUREG 0578, Section 2.1.2.

Our p osition on safety / relief valve qualification testing is revised as follows:

The Peach Bottom type safety / relief valves will be included in the scope of the prot otype qualification testing to be perf ormed under the auspices of the BWR Owners Group. We will grovide the neceosary support t h r ou gh the Owners Group to develop and complete the testing program. A description of the test program and the schedule for testing will be submitted by the BWR Owners Group in a timely manner.

2. Onsite Technical Support Center, NUREG 0578, Section 2.2.2b In response to the clarifications in y ou r Oct ober 30, 1979 letter, ou r commitments on this item is revised as follows:

The f ormer Peach Bottom Unit 1 (HTGR) control room will be adapted f or use as an interim Technical Support Center (TSC) by January 1, 1980. The f ollowing f eatures will be incorporated int o the interim center by this date.

1. Direct communications, via dedicated p rivate telephone lines, will be made vith the Units 2 and 3 control room, the emergency control center, corp orate headequarters, the Nuclear Regulatory Commission headquarters in Bethesday, MD, and the NRC Regional Office in King of Prussia, PA.

2. Technical information in the form of plant drawings, procedures and descriptions will be f iled at the center.

3 Continuous monitoring equipment measuring both direct and airborne radiation will be p rovided. ,

A study for providing a closed circuit television link from the Unit 2 and 3 cont rol room and output f rom the plant process computer terminal to the permanent and interim TSC is in progress, and a p rogram and implementation schedule will be determined by January 1, 1980.

The role and staffing of the TSC will be incorp ora t ed into the Emergency Plan for submittal to the NRC by January 1, 1980. Implementing procedures will be developed f ollowing

- NRC approval of the Plan. The plant emergency procedures provide the guidance for p erf orming the accident assessment function from the control room. These p r o c e du res are being revised to reflect the results of the General Electric transient and accident analysis required by NUREG 0578, item 2.1 9.

Engineering s tudies are cu rr e n t ly in progress for determining

~

the location and p reliminary design for a permanent TSC.

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Page 2 Three locations, including Peach Botton Unit 1, are being studied. Design criteria for the permanent TSC shall be in accordance with the criteria established in the NRC letter of October 30, 1979 for size, habitability, instrumentation,The technical data, p ower supply , and structual integrity.

final location, conceptual plans, i mp le me nt a t i on , and deviatioas f rom y our crit eria, for the permanent Technical Support Center will be established by January 1, 1980.

3. Transient and Accident An a ly sis , NUREG 0578, Section 2.1 9 Our October 17, 1979 response proposed that the procedures and operator training be completed within three months f ollowing NRC acceptance of the General Electric Transient and Accident studies. The guidance regarding small 1.seak analysis was not received from General Electric Company until November 8, 1979 Procedures are presently being revised to reflect the new criteria. A December 31, 1979 deadline does not provide sufficient time for the procedures to be reviewed and approved, for the material to be incorp orated into the operator training program, and f or the training of all six operating shifts at Peach Bottom. Therefore, we propose that our previous response be revised as follows:

The guidance provided by the General Electric small break accident analysis to the BWR Owners Group meeting on November 8, 1979, will be incorporated into the plant procedures, and the associated operat or t raining completed by January 31, 1980. Information and guidance derived f rom the remaining General Electric transient and accident studies will be incorp ora t e d into the plant procedures, and the associated operator training completed within three months following receipt of the General Electric guidance.

4. Direct Indication of Valve Position, NUREG 0578, Section 2.1.3a In consideration of the NRC rep ly to the BWR Owners' Group p os i t i ons , our response t o section 2.1.3a is revised as follows:

A single channel system based on acoustic monitoring techniques is currently installed on all the safety / relief valves to provide p os itive, individual valve position indication in the control room by annunciating an alarm whenever any safety / relief valve is open.

Acoustic sensors have been installed on the Unit 3 code safety valves during a previous outage. Positive indication on Unit 3, with a common alarm in the control room will be operational by January 1, 1980. Positive position indication on the Unit 2 code safety valves will be installed during the Spring, 1980 refueling outage.

The design criteria as presented in several NRC documents for an upgraded p osition monitoring system appears to be 1398 194

Page 3 9

inconsistent. Dialogue between Philadelphia Electric and the NRC is in progress to clearly define the design requirements. We are presently analyzing three designs for the upgraded system. As a minimum we will provide a reliable, non safety grade qualified, single channel, direct valve 0 sition indication, powered f rom a saf eguard p ower supply , as requested in clarification item 3 on page 7 of your Oct ober 30, 1979 letter. Backup methods of determining valve position will be p rovided in accordance with the criteria to be defined after further dialogue with the NRC.

A realistic implementation schedule for an upgraded system will be determined f ollowing completion of our design review early next year. Modifications will be implemented by January 1, 1981 unless precluded by material or equipment unavailability.

5. Instrumentation for Inadequate Core Cooling, NUREG 0578, Section 2.1.3b.

Our response of October 17, 1979, committed to the imp le me n t a t i on of the requirements identified in section 2.1.3b. H owe ve r , further explanation of our p rop osed time schedule is necessary. The table on pa8e 70 o. your October 30, 1979 letter permits three months for the implementation of emergency procedures and retraining related to inadequate core cooling. A January 1980 completion date is requested based on an expected completion of the analysis on Oct obe r 1980. We may be unable to meet the January 1980 deadline since the analysis by General Electric Company may not be completed in time t o permit the training of shift operating p e rs onne l. Our response of October 17, 1979, p rop os e d a period of 60 days to develop the procedures following NRC acceptance of the General Electric study, and another 60 days to c omp le t e the training of operators, for a total of 120 days. As a result of a reassessment of our p revious proposal, we p rop ose that both operating p rocedures and operat or t raining be completed within three months following receipt of the G.enera l Ele ct ric C ompany guidance. This'would accelerate implementation on a faster time schedule, and satisfies the intent of the NRC schedule.

6. System Integrity for High Radioactivity, NUREG 0578, Section 2.1.6a.

Our p osition p rop os ed in our October 17, 1979 letter is restated as follows:

System design prevents a leakage identification program that would include pressure decay type integrated leak rate tests to determine external leakage from the systems of interest.

These systems have boundaries that under normal circumstances, separate them f rom the torus compartment or the reactor vessel, and because those boundaries are not required to be leak-tight, an integrated leak test of those systems is not indicative of the leakage paths of concern.

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Page 4 Systems outside containment that would be exp ected t o cont ain h i gh ly radioactive fluida during a serious transient or accident will be identified by January 1, 1980. A routine leak inspection p rogram f or these systems will be established to identify abnormal s ou rces of leakage. The inspection will consist of an external visual inspection, or radioactive airborne area sampling, for leakage identification while the system is pressurized. Most of the systems in the program will initially be inspected quarterly. The CRD scram discharge volume will be pressurized and inspected f or leaks once p er operating cycle during the primary coolant system hydro test. The leakage identification program will include

. methods for identifying equipment to be repaired, and the frequency of inspection will be adjusted, if necessary, to adequately monitor abnormal leakage. The quarterly leakage identification p rogram will be initiated during the first quarter of 1980.

7. Plant Shielding Review, NUREG 0578, Section 2.1.6b.

Our interpretation and p rop osed actions regarding clarification item 1, page 19, of your Oct ober 30, 1979 letter is as follows:

Aggregate dose rates for various time periods after an accident are being calculated f or the control room, radiochemical and chemical laboratories, the radwaste panel, motor control centers, certain instrumentation locations, reactor coolant and containment gas sample stations, and other areas whose access has been identified as important during an accident. The aggregate dose rates will be comprised of the dose rates due to direct radiation from liquid and gas containing systems and due t o airborne radiation leaking from primary containment. These aggregate dose rates will be examined with respect to access time requirements to determine what corrective action is required t o p rovide access during accident conditions. .

Our review to be completed by January 1, 1980 will examine what corrective action, if any, is required in addressing only the dose rates from direct radiation. We will provide by January 1, 1980, r plan and schedule for addressing the aggregate dose rates.

As stated la ou r October 17, 1979 letter, the performance of vital equipment outside of primary contairment will be addressed in our response t o Bulletin 79-01 which will be submitted by January 31, 1980.

8. Post Accident Sampling, NUREG 0578, Section 2.1.8a Our Oct ober 17, 1979 response committed to a design review by January, 1, 1980 of ou r p os t accident samp ling capabilities ,

and modifications as required by January 1, 1981. In response t o the p rocedural requirements identified in yo g [3

Page 5 October 30, 1979 letter, a description of our p resent and p rop osed sampling capabilities is provided below.

Present analy tical me thods , described in existing plant procedures, are capable with the use of temporary shielding for analyzing major gamma ra diois ot op es , chlorides, and boron on a 50 ml reactor coolant liquid sample, with dose rate equal to or less than 10 R/h r. In the event the engineering review of ou r p os t accident sampling capabilities determines the dose rate t o be in excess of 10 R/Hr. additional procedures, techniques, and system modifications, as app rop ria te, will be implemented by January 1, 1981.

Presently, capabilities f or sampling the containment atmosphere do not exist. The necessary system modifications to permit containment atmospheric sampling will be identified following completion of the design review, and modifications imp lemented by January 1, 1981.

In addition, a new gamma isotopic geometry calibration of our counting instrumentation will be performed by March 1, 1980 to permit analysis of higher levels of radioactive samples.

9 k igh Range Effluent Monitor, NUREG 0578 Section 2.1.8b We eish to add the following commitments t o those previously id_ntified in ou r Oct obe r 17, 1979 letter t o the NRC.

A high range noble gas effluent monitoring system, that satisfies the short term requirements identified in your Oct obe r 30, 1979 letter will be installed by January 1, 1980.

F o l l ow in g installation, additional time will be required to develop calibration f act ors and procedures, with an expected c omp le t i on date of April 1, 1980.

In addition, a new gamma is ot op i c geometry calibration will be perf ormed t o permit analysis of higher levels of radioactive iodine cartridges and particulate filters. T h i's imp rove me nt will increase the sample radiation level by a factor of one hundred f or which we have an a ly z in g capabilities, and will be completed, along with implementing procedures by March 1, 1980.

In the event the design review committed to in ou r Oct ober 17, 1979 letter by January 1, 1980, indicates that the radiation levels in the plant prevent sampling and analy sis with the instrumentation discussed above, additional procedures, techniques, and modifications, as appropriate, will be implemented by January 1, 1981.

10. Improved In-Plant Instrumentation. NUREG 0578,'Section 2.1.8c The NRC letter of October 30, 1979 contains a short term recommen'dation to be implemented by January 1, 1980 for a c cu ra t e ly detecting iodine levels within the plant, and a 1598 197

Page 6 specific iodine s ample r and analyze r is suggested f or consideration. A review of this matter indicates that our existing procedures utilizing portable samplers and counting room instrumentation has the capability of analyzing radioactive iodine levels higher than the measuring .

capabilities of the suggested instrumentation.

Procedures presently exists for in plant iodine analysis. In the event, the engineering study to be completed January 1, 1980, indicates radiation levels that would p revent iodine analysis using existing techniques, additional procedures, techniques, and modifications as appropriate, will be implemented by January 1, 1981.

11. Shift Technical Advisor, NUREC 0578, Section 2.2.lb.

Our p osition on this item has been reworded to clearly indicate our intention that the Shift Technical Advisor will be situated on site t o augment the operating shift, and will have no direct operating duties that mi gh t detract f rom his dedicated concern f or the safety of the plant. A rewarded response is as follows.

The long term s olution t o imp roving the accident assessment capabilities of shift personnel is the upgrading of senior licensed operat or qualifications and training. While this represents a long term objective, an interim method of providing the functions of the technical advisor as outlined in NUREG 0578, Section 2.2.1.b and discussed in Enclosure 2

" Alternative to Shift Technical Advisor" to your letter of September 13, 1979, will be necessary ove r the foreseeable future.

Effective January 1, 1980, personnel will be assigned as the Shift Technical Advisor t o augment each operating shift.

These individtnis will fulfill the accident assessment function during a plant transient. Personnel assigned t0 this position will have a bachelor's degree or equivalent in an engineering or scientific field. They will be situated on site during their scheduled shif t. ,The Shift Technical Advisor will have no duties or responsibilities for manipulation of controls or command of operations during the transient, nor will he have direct operating duties that mi gh t detract f rom his dedicated concern f or the safety of the p lant .

During a transient, the Shift Technical Advisor will, observe control room ins t ru me n t a t i on and ECCS operation and availability to determine that the transient is proceeding as predicted. He will advise Shift Supervision of significant adverse conditions. After a stable condition has been achieved, he will aid shift pers onnel in analysis of the transient to determine cause and Technical Specification implications. At the request of Shift Supervision, the Shift Technical Advisor may als o aid in reporting plant conditions 1398 198

Page 7 to Plant Management and serve as '.inson with technical support personnel.

The individual's filling this position will receive special training in nuclear physics, chemistry, reactor thermodynamics, fluid mechanics, heatThis transfer, electrical training is being circuitry and reactor control theory.

provided by the Nuclear Steam Action hasSupply been System initiatedvendor (General t o accomplish Electric Company). 1980. Completion some of this training p rior t o January 1, of this training for all individuals assigned1,t o1981 this position will be completed prior to January The operating experience assetsment function described in Enclosure 2 to your letter of .iep t e mb e r 13, 1979, will be provided by the Shift Technical Advisors and supplemented by individuals p ossessing bachelor 's degrees or equivalent in engineering or scientific fields from the Engineering and Research Department and Electric Production Department.

These indivf ?aals would typically reprasent Mechanical and Engineering, Electrical Engieering, Quality Assurance, Licensing fields. Reports on these assessments will be provided to the Superintendent - GenerationThis Division / Nuclear review process will and to the Station Superintendent.

be initiated January 1, 1980.

The above method represents our interim method of meeting the 2.2.1.b. Following requirements of NUREG 0578, Section implementation, other methods may be identified Significantwhich enhance changes to the program or are equally effective.discussed with the the program described above will be resident inspect or p rior t o implementation. Any -

changes made Industry Topical will meet the criteria outlined at the NRC Meeting in Bethesda on Oct ober 12, 1979

12. Shift and Relief Turnover Procedures. NUREG 0578, Section 2.2.lc.

• We p r op os e that the requirements stated in this section be imp lemented except for the request to establish separate checklists or logs for use by the offgoing and ongoing auxiliary operators and maintenance technicians.

A variety of shift turnover checklists or logs, situated in v a r i ou s locations of the plant and under the control of many groups would further hinder the transfer of vital inf ormation to the operating shift pers onnel with primary r esp ons ibi li ty f or plant operations. A limited number of checklists or logs, centralized in the control room, and under the supervision of control room pers onnel is essential to

• effective transfer of inf ormation.

Maintenance and testing of equipment vital to safe operation of the plant is perf ormed with the knowledge and approval The of the ap p rop riat e licensed control room operator.

checklists, status boards, or logs will be utilized to 1398 199

Page 8 identify any equipment under maintenance or test that by themselves could degrade a system critical to the prevention and mitigation of operational transients and accidents, or initiate an operational transient. Some of this inf ormation

- will be supplied t o the control room operators and supervisors, as appropriate, by the auxiliary operators and technicians f or ent ry int o the checklists and logs. Shift personnel meetings under the direction of shift supervision are normally held shortly after shift turnover. The auxiliary operator's participation in these meetings includes review of the checklists and logs. These methods are considered more effective in the transfer of vital information durin8 shift turnover than the use of separate logs by the auxiliary operatora and technicians.

13. Containment Isolation, NUREC 0578, Section 2.1.4 In response to the clarifications in y our Oct ober 30, 1979 letter, our commitments on this items is revised as follows:

We are conducting a review comparing the design of the Peach Bottom containment isolation provisions to the criteria stated in NUREG 0578, Section 2.1.4. Many of the design features are generic t o BWR facilities. Questions which arise regarding these generic features will be reviewed by General Elect ric Company under the direction of the BWR Owners Group. Our current assessment of the degree of compliance expected on January 1, 1980 and ou r justification f or the p rop osed delays is provided below:

Diversity of Isolatien Signals All containment isolation valves currently provided with automatic closure logic receive diverse, safety-grade isolation signals in accordance with SRP 6.2.4. with the following exceptions: ,

a) Reactor Water Cleanup suction and return line isolation valves (MO 15,18 ,6 8 ) are cu r ren t ly provided with the following signals to initiate valve closure:

RWCU High Flow (300 %)

Reactor Low Water Level (0")

RWCU Non-Regenerative Heat Exchanger High Temperature (200 F)

Standby Liquid Control System Operation The latter two are process signals rather than containment isolation signals.

b) The HPCI and RCIC steam exhaust line drain isolation valves (AO-4240,4241,4247,4248) are p r e s en t ly closed upon trip of their respective turbines. This trip is a process signal rather than a containment isolation signal.

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Page 9 The above designs appear t o be generic and will be reviewed and resolved accordingly. Modifications, if necessary, will be made during the first scheduled outages of each unit subsequent to January 1, 1980.

Classification of Systems All lines penetrating p rimary containment have been reviewed and classified as essential or non-essential. The results of this review will be reported to the NRC by January 1, 1980.

Isolation of Non Essential Lines All non-essential lines are presently provided with automatic isolation valves which are closed either by containment isolation signals or reverse flow (i . e . check valves, excess flow check valves) with the f ollowing exceptions :

a) LPCI and Core Spray test valves (AO-10-163A,B and A0 15A, B) are not provided with automatic isolation.

These 1" valves are located in parallel with the check valves which p rovide inboard isolation in the LPCI and Core Spray injection lines. These normally-closed, fail-closed valves are op erated only to equalize pressures t o permi t stroking of the check valves. These valves are opened by a push bottom which utilizes a momentary contact to open the valve f or testing. We do not feel that it is necessary to p rovide is ola ti on signals to these valves.

b) The ILRT connections and Service Air supply lines are provided with dual locked-closed, manual globe valves for is ola t i on . These lines are not used during unit operation. We do not feel that it is necessary to provide isolation signals to these valves. This is in accordance with 10 CFR 50, Appendix A, GDC 56.

c) The isolation valves on the Reactor Building Cooling Water (MO-2373,2374) and Drywell Chilled Water Systems (MO-2200A,B and 2201A, B) do not receive automatic isolation signals. It is our p osition that these valves should not be automatically isolated since their continued use will tend,to mitigate the consequences of an accident. ,

d) The Radioactive Gas Sample line is ola t i on valves (SV-4966 A-D) are nos profvided with automatic isolation signals. These valves are normally closed but may be opened by the operat or f or p os t -a c c i de n t gas analysis.

Modifications will be made t o p rovide diverse automatic isolation during the first scheduled outages of each unit subsequent to the availability of equipment.

e) The TIP drive line isolation valvts are not provided directly with automatic isolation signals. The TIPS are automatically withdrawn on Reactor Low Water Level (0")

on High D ryve ll Pressure (2 psig). Each drive line is 1398 201

Page 10 provided with ball and shest valves for isolation. The ball valves are automatically opened and closed on the TIP position. The f unction of the shear valve is to provide isolation in the event that a ball valve fails to close or a drive cable fails to retract. It The shear valve is operated from the control room. is our position that these isolation f eatures are adequate for their intended service.

Items a, c, and e, are generic and will be reviewed and resolved as such in a timely manner.

Reset of Isolation Signals We have completed a design review of the control systems for all automatic isolation valves to assure that resetting their isolation logic will not result in automatic r e op enin g .

Modifications to many of the isolation valves will be necessary. Plans are being made t o imp lement these modifications to the isolation valveand logic during the first the Spring, 1980 scheduled outage in 1980 on Unit 3, refueling outage on Unit 2. In the interim, procedural controls exist and have been re-emphasized to require that each individual cont rol switch be placed in the closed position f ollowing a containment isolation so as to preclude the inadvertant reopening of any isolation valve when its isolation is reset.

14. Containment Water Level Monitoring, Enclosure 3 (September 13, 1979 letter)

Our Oct ober 17, 19 79 resp onse p rop osed that the lower end of the range of the instrumentation used to monitor containment water level be one f oot above the bottom of the suppression pool instead of at the bottom of the suppression pool. This was p rop osed t o make use of existing piping and will provide the operator with the inf oymation required f or diagnosis, and a c t i on .

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