ML17192A598

From kanterella
Jump to navigation Jump to search
Forwards NRC Evaluation of Util Responses to IE Bulletin 79-08, Events Relevent to BWRs Identified During TMI Incident
ML17192A598
Person / Time
Site: Dresden, Quad Cities  Constellation icon.png
Issue date: 03/10/1980
From: Ippolito T
Office of Nuclear Reactor Regulation
To: Peoples D
COMMONWEALTH EDISON CO.
References
IEB-79-08, IEB-79-8, NUDOCS 8003270220
Download: ML17192A598 (42)
v • d • e


Text

Distribution*

i)locke~

ORB #3 NRR Reading Local PDR.

Docket Nos* 50-237 50-249

  • so-254 MARCH 1 0 1980

. NRC PDR DEisenhut

~~Gammi 11

.. RVolliner _

  • . *. -BGrimes*
  • and 50-26~' *

., JMi*ll er LShao

.

  • Tlppol ito * *
  • - _SNorri s

~.*.,

RB~van Mr. D. Louis P.epples

... DZiemann

  • Director_ of NucJear L. icensing *. -..._ :i.- SNowicki

.Corrmcrnw~a lt~.Edi s_on Company J'Lee

  • p. O. Box 767..

... : WKane Chicago, I.llinois: 60690 c.Thomas

Dear Mr. Peoples:

t, DRoss Atty, OELD I&E (3)

NSIC.

TERA*

HDenton-ECase DVassa 11 o

  • cHe ltemes -,:

TNovak-

. *zRosztoczy*

. OParr. *

  • JSto lz..

~

Sls rae l *

  • CDeBev.ec -
  • EJorda'n PBoehnert
  • RFrahm JGuttrilan ETb_rom..

B&O File WHodges PMatthews GMazeti s *

. PNorian NWagrier.

KM,ah'ari

SUBJECT:

NRC STAFF EVALUATION OF COf'1MONWEALT~ rn1sor~ COMPANY RESPONSES TO lE BULLETIN 79-e8 FOR.* DRESOEN STATION; UNITS 2. ANO 3 ANO

.. QUAD CITIES STATION,* UNITS. l AND 2 * :*,.

~

l

~*. -~~

~.

~. *.

' : ':I

.. ~ '

We have cor11pfoted our revici-1 *of t~*e foformation ;th;t ym(provfded in*.your

. letters dated April <<27 and.August. 3;* 1979 in response lo IE Bulletin 79-08~

_ f_or the*o.resden Station Units**z:and*3.and Quad Cities Station *uni_t_s.1 and 2 *.

~

1o f

l J..

We have ~oncluded that you have tci~en. the appropriate actions to meet: the *

  • requirement$ of e9CO *of t.he e]even action items *;dent ified *in IE BuHeti n

. 79-08~ A.COPY,9f our: evalliatfon is enclo$e.d *...

  • As _you know, NRC staff review of* th:e*Three Mile Island~ Utt1t **2 (TMI.-.2).

r~ *

~ -. accident is continuing and* other corrective actions may be required at a

  • later dat~. Specific requirements for your fad.lity that result from this review and-other TMI-2 investigqtions w'ill-b.e addressed tQ you in s~parate.correspondence. *
  • s; ncere 1.Y.
  • Th==~o, Chief '~:

. Operating Reactors Branch #3. *. rwf_ Y

_*Division of OperatinJJ ~ctors.

1:\\._~-.:_

(.)fl.RjJJ/3 ORB #2rNf\\

ORBd#Y~

JlltY/___...

~

Enciosµre:.

J~an :mjf SNowi c~f

  • \\.,DZi emann NRC Staff Evalu.atjon 3/fi'./80..

3lft/80

. 'J/80

$'OOJZ~Z..Z.0.

. cc w nclosure:

B&O

  • ,--~~*~*e*~-.aj

--~****. ___

0

_R.'._~... -'***********::.o~-~*

.. J*#~~

0 0Se~

xt*p~_g.~...... :******:.... ~-~**:***

atl ~ ~

~~

S~R:::: ~:::: :*: :*-:::::::::::.. -~((o)~:a '.::::: : : ~/!.~?~?: :*:::.::: ~([(J~?::::::::: :~~~ :(~~::: :.: : : : : : : : *::: '. :*:::::

NRC.FORM 318 (9-76) NRCM 0240

  • u.s. GOVERNMENT PRINTING OFFICE: 19;9*289*369

.. ~

"'j,*

Mr. D. Louis Peoples Commonwealth Edison Company

.cc:

Mr. o.* R. Stichrioth President Iowa-Illinois Gas and Electric Company 206 East Second Avenue Davenport, Iowa 52801

  • Mr. John W. Rowe Isham, Lincoln & Beale Counselors at Law One First National Plaza, Ghicago~ Illinois 60603 Mr. Nick Kalivianak-as Plant Superintendent 42nd Floor Quad Cities Nuclear Power Station 22710 - 206th Avenue - North Cordova, Illinoi~ 61242 Anthony Z. Reisman Natural Resources Defense Council
  • 917 15th Street, N. W.

Washington, D. C. 20005 Moline Public Library 504 - 17th Street Moline, Illinois 61265 Susan N. Sekuler Ass.istant *Attorney General Environmental Control Division

  • 188 W. Randolph Street
  • suite 2315 Chicago, Illinois 60601 Mr. N. Chrissotimos, Inspector US Nuclear Regulatory Coirrnission Box 756 Bettendorf,.Iowa 52722
  • Mr~ B. B. Stephenson Plant Superintendent

. Dresden Nuclear Power Station Rural Route #1 Morris, Illinois

  • 60450 *

- 2 March 10,1980 Jimmy L. Barker

  • U. S. Nuclear Regulatory Car:tnission P. 0. Box 706 Morris, Illinois 60450

EVALUATION OF LICENSEE'S RESPONSES TO*

IE BULLETIN 79-08 COMMONWEALTH EDISON COMPANY DRESDEN STATION, UNITS 2 AND 3 DOCKET NOS. 50-237 AND 50-249

.:..~*

Introduction.

By letter dated April 14, 1979, we transmitted Office of Inspection and Enforce-ment (IE)Bulletin 79-08 to Commonwealth Edison Company (CECo or the licens~e).

IE Bulletin 79-08 specified actions to be taken by the licensee to avoid the occurrence of an event s imi 1 ar to that which occurred at Three Mi 1 e. Is 1 and, Unit 2 (TMI-2) o~ March 28, 1979.

By lettei dated April 27, 1979, CECo pro-vided responses to Action 1tems 1 through 11 of IE Bulletin 79-08 for the Dresden Station, Units 2 and 3 (Dresden 2 and 3).

The NRC staff *review of the cECo responses 1 ed to. the issuance of requests for.*-

  • additional information regarding the CECo responses to certain.action items of lE Bulletiri.79-08.
  • These requests were c6ntained* in a letter dated July 20, 1979:

By letter dated August 3~ 19j9, CECo responded to the staff 1 s requests for additional information.

The CECci respo_nses to IE Bulletin 79-08 provided the basis for our evaluation presented below.

In.addition, the actions taken by the licensee in response to the bulletin and subsequent NRC requests were verified by onsite inspections by IE inspectors.

Evaluation-Each of the 11 action items reque~ted by IE Bull~tin 79-08 is repeated below f_ollowed by our criteria for evaluating the response, a summary of the licensee 1 s response ~nd our evaluatiori of the response.

1.
  • Review the desc~iption of ~ircumstances described in Enclosure 1 of IE Bulletin 79-05 and the preliminary chronology of the TMI-2 March 28, 1979 accident included in Enclosure 1 to IE Bull~tin 79-05A.. *
a.

This review should be dire~ted toward understanding:

(I) the extreme seriousness and consequences of the simultaneous blocking of both tra1ns.of a safety system at the Three Mile Island Unit 2 plant and

.other actions taken during the earl~ phases of the accident; (2) the apparent operational errors which led_ to the e~entual cor~ damage; and (3) the necessity to systematically analyze plant conditions and parameters and take appropriate corrective action:

  • b, Operational personnel should be instructed to (1) not override automatic action of engineered safety features unless continued operation of.engineered safety features will result in 'unsafe plant conditions (see Section Sa of this bulletin); and (2) not make operational decisions b~sed solely on a single plant parameter indication when one or more confirmatory indications are available.
c.

All licensed operators and plant management and supervisors with operational responsibilities shall participate in this review and such participation shall be documented in plant records.

The *licensee 1 s response was evaluated to determine that (1) the scope of review. was adequate, (2) operational personnel were properly instructed and (3) personnel particip'ation_* in the review was docu*mented *in plant records,

,.~

The ~icensee 1

s response dated April 27, 1979 states that a review of the information given in Enclosure 1 to IE Bulletins 79-05 and 79~osA was being perform~d. The review e~phasized th~.five points stressed in l.a and b of IE Bulletin 79.-08.

In accordance with Item l.c, the licensee st~ted that docu-mentati.on of this review by all licensed operators and plant management and

~u~ervisors with ope~ational responsibilities ~ould be provided and maintained on file.

The licensee 1 s supplemental respon~e dated August 3, 1979 confirmed that all acticins required by Item 1 had been completed by June 1, 1979.

We conclude that the licensee 1 s scope of review, instructions to operating personnel and documented participation satisfy the intent of IE Bulletin 79-:-08, Item 1.

2.

Review the containment isolation initiation.des~g~ and procedures, and prepare and implement all changes necessary to initiate -containment.

isolation, whether manual or automatic, of all lines whose isolation does riot* degrade needed safety.features or coo 1 ing capabi 1 i ty, upon autorriati c initiation of safety injection.

The*licensee 1 s response was. evaluated to verify that containment isolation initiation design and procedures had been reviewed to assure that (i) manual or.automatic initiation of containment isolation occurs on automatic initiation of safety injection and '(2) all_ lines (i'ncluding those designed to *~ransfer

__...,;_, radi oact i_ve gases or liquids) whose i sol at ion does not degrade cooling* capability or.needed safety features were addressed.

The licensee's response of April 27, 1979 states that a review of the existing isolation design and procedures had been performed to determine whether all systems not needed for safety injection would isolate on injection signal.

The review verified that a safety injection signal would automatically 1nitiate containment isolation, if containment isolation had not already been initiated, by closure of all valves where such closure does not degrade needed safety features or cooling capability.

In addition, applicable emergency operating procedures were reviewed to assure proper operator action.in the eve*nt of -

automatic initation of containment isolation.

In its supplement~l.response dated August 3, 1979, the licensee determined that an automatic isolation should be added to the torus-to-main condenser drain line.

By a subsequent telephone conversation, the licensee advised us that this modification has been Completed.

T~e litensee also implemented a procedure change to manually close the torus-to-main ~ondenser.drain line if isol~tion is initiated.. The licensee furthei confirmed in its August 3, 1979 letter that its review had included all lines penetrating primary containment and ~hat the review included the applicable emergency instructions and operating*

proced_ures.

other than No changes to the design or procedures were reported ~s needed the aforemention~d.

We conclude.that the licensee's review of containment isolation initiation

. design and procedures satisfies the intent of.IE Bull~tin 79-08, Item 2.

3.

Describe the actions, both automatic and manual, necessary for proper functioning of the auxil ia:ry heat removal systems (e.g., RCIC) that are

For any manual action necessary~ describe in summary form the procedure by which this.

action is takeri in a timely sense.

The licensee's response was* reviewed to assure that (1) it described the automatic and manual actions necessary for the proper functioning of the

. {

..i......

". auxiliary heat removal systems when the main feedwater system is not operable_

and (2) the procedures for any necessary manual actions were described in summary form.

The licensee's response dated April 27, 1979 states that, following a loss of feedwater, reactor scram occurs at low water level (+8 inches).

In about 34 seconds, reactor water will fall to low-low level (-59 inches) at which time high pressure coolant injection (HPCI) system operation and main steam isolation valve (MSIV) closure will be initiated. *Main steam relief valves may open shortly following MSIV closure, relieving steam to the suppression pool.

With no operator action, the HPCI system will continue adding water to the vessel until the level reaches high level (+48 inches), at which time the HPCI system turbine will automatically trip.

The HPCI syst~m turbine will auto-matically restart if the lo~ water level signal is again reached and the

  • turbine trip signal clears.

All system operat1on of HPCI is automatic.

From this point on, cooldown would continue with removal of decay heat using the isolation condenser (IC), a passive system.

Following closure of. the MSIV 1s, the IC will be initiated 15 seconds after reactor pressure rises to 1070 psig.

The IC 1 s are designed to provide core cooling in the event that the reactor is isolat~d from the main condenser by closure of the MSIV 1 s.

The IC is sized to handle all c:ore decay heat at five minutes after a scram.

This heat removal capability is verified once every five years in accordance with the Technical Specifications.

Once initiated automatically, the water inventory of the IC shell side is adequate to allow 20 minutes of operation before the water level reaches the top of the tubes without adding any makeup.

This 20 minutes is adequate to allow for manual init1ation of m~keup flow to the shell.

The shell side water inventory required to assure IC operability is defined in the Technical Specifications and the station operating procedures.

Station procedures define the proper methods of initiating makeup to the IC shell *from any one of three sources of makeup water.

The station procedures also outline the actions necessary to manually initiate the IC, including making u~ to the shell.

If the IC is unavailable, the relief v~lves would be used to control reactor depressurization.

This is performed by manually opening a relief valve from the main control rdom.

The us~ of the HPCI system for reactor makeup (either manually or by allowing automatic. initiation) would provide additional depres-surization of the reactor.

After depressurization to 350 psig, the low pressure coolant injection {LPCIJ or core spray (CS) systems could also be used for

~~

~eactor water makeup.

If both the HPCI system and the IC are unavailable, the relief valves would be used to man~ally depressurize the vessel to less than 350 psig when, in conjunc-tion with a low-low*reactor water level of -59 inches, the LPCI and CS systems would.be automatically initiated.

Once the reactor water level has been recovered and it has b~en absolutely determined that the LPCI and CS systems are no longer needed, these systems.would be manually shut down.

Although the capability of the aforementioned systems to perform as indicated is described during initial operator training and in subsequent retraining, no specific procedure existed which dealt with the loss of feed\\'1ater and possible unavailability of both the HPCI system and the It.

In its supplemental response dated August 3, 1979, the licensee stated that operating.procedures have been revised to specifically instruct.operators to manually depressuri ze the.reactor us i.ng the re 1 i ef va 1 ves, allowing the LPCI and CS systems to inject water if t~e normal feedwater and HPCI systems and the IC are unavailable.

By a subsequent telephone conversation, the licensee advised us that all licensed operators have received training in these revised procedures and ddcumentation of this training is being kept bn file.

  • * r We conclude that t.he licensee 1 s procedural summary of automatic/manual act i ans necessary for the proper functioning of auxiliary heat removal systems used when,the main feedwater system is inoperable satisfies the intent of IE B~lletin 79-08, Item 3.
4.

Describe all uses and types of vessel level indication for both automatic and manual initiation of safety systems.

Describe other redundant instru-

  • mentation which the operator might have to give the same ~nformation regarding plant status.

Insttuct operators to utilize other available information to initiate safety systems.

The licensee 1 s.response was evaluated to. determine that ( 1) a 11 uses.. and types of vessel level indication for both automat.ic and manual in.itiation of safety systems were addressed, (2) it addressed other instrumentation.available to the operator to determine changes in reactor coolant inventory and (3). operators were instructed to utilize other available.information to initiate safety systems.

The licensee 1 s respbnse of April 27, 1979 states that vessel level indication

  • for both automatic and manual initiation is achieved by diverse and redundant instrumentation.

The vessel level indication is comprised of four types of instruments.

Two of the four types, the narrow and the wide range Yarway indicators, are used for the manual and/or automatic initiation of the safety systems.

(1)

The narrow range Yarway level instrumentation has a range of +60 inches to -60 inches.

Thts covers the normal operating ranges down to the lower i.nstrumeilt nozzle.

Operation of this instrumentation requires no p'ower supply, and it provides most of the trip functions associated with the water.level instrumentation.

It is referenced to 11 instrument zero, 11 is calibrated at 1000 psig reactor.pressure, and is rapid-pressure-change-compensated.

The setpoints and functions of the narrow range.Yarway include:

Setpoints

+55 inches

+30 inches

+8 inches

-59 inches.

7 -*

Functions Trips main turbine, HPCI system turbine and main feedwater pumps.

Automatic feedwater runout reset.

Inhi.bits runout flow control ~bove +30 inches.

Normal operating

. level.

Reactor scram.

Initiates Groups 2 and 3 containment isolation closure.

Initiates ECCS.

Initiates standby diesel-generators.

Trips recircul.ation pumps.

Completes *Group 1 contain:_

ment isolation.

Two narrow range Yarway level indicators are located in the main control room, and ten level indicating switch!'!s with indicators are located in the teactor building.*

(2)

The wide range Yarway level instrumentation has. a range of* 400 i nth es,..

covering the active core range and overlapping the lower portion of the narrow range Yarway.

This. provioes indication during and after a blowdown..

accident and with the recirculation pumps tripped. lt also provides.a

. Two wide-rangeYarway indicators are located in the control room.

In addition to the Yarway level instruments, there are narrow and wide*

range GE/MAC level instrum.erits which can. be used by the operator to monitor.Vessel water leVel.

(3)

The narrow range GE/MAC. level instrume.ntatibn is the most accurate level indication available to the operator.

It provides the level iriput to the feedwater level control system~ Its range of zero to 60 inthes, referenced

  • to.instrument zero, covers the normal operating range.* It is calibrated at lbOO psig and is temperature compensated.
  • The recorder alarms in the control foom at high and low water levels.

The level indications can also be displayed on the control room digital window display and recorded on the control room computer printout.

The wide range GE/MAC level instrumentation provides level indication during vessel flooding on cooldown.

Its range is 400 inches and covers the upper portion of the reactor vessel.

One wide range GE/MAC level indicator is

  • located in the main control room.

The wide range GE/MAC level indications can also be displayed on the main control room digital window display arid recorded on the control room computer printout.

In addition to the above indications available to the operator, alarms associated with the automatic action~ listed above will inform the operator of the. react6r vessel level status and require his verification that actions have. taken place at the appropriate levels.

As listed in the licensee's supplemental response dated August 3, 1979, the control room operator has numerous alternate indications that can indirectly indicate a change in reactor vessel coo.lant inventory.

Instrumentation is available in the control room to monitor:

Drywell Pressure Drywell Temperature Suppression Chamber Pressure Suppression Chamber Temperature Suppression Chamber Water Level Feedwater Flow Steam Flow Reactor Pressure Relie~ Valve Discharge Temperature Drywell.Floor and Equipment Sump Discharge Flow Reactor Building Closed Cooling Water Temperature

9 -

Any of these measured parameters could indirectly indicate a change in reactor vessel coolant. inventory.

The licensee's August 3, 1979 letter states that the operators have been instru~ted to utilize other available information as part of their training as required by Item 1 of IE Bulletin 79-08.

In addition, the use of multiple indications to identify abnormal conditions is an underlying philosophy of the licensee's abnormal and emergency procedures.

All licensed operators are trained on these procedures annually as part of their requalification training.

We cone l ude that* the l i ~ensee 1 s description of the. uses and type*$ of reactor*,.-

vessel level/inventory instrumentation and instructions to operators regarding the use of this information satisfies the intent of IE Bulletin 79-08, Item 4.

5.

Review the actiohs directed by the operating procedutes and training instructi-0ns to ensure that:

a.

Operators do riot* override automatic actions of engineered safety features, unless continued operation of engineered safety features will result in unsafe plant conditions (e.g., vessel integrity).

b.

Operators are provided additional information and instructions tb not rely upon vessel level indication alone for manual actions, but to also examine other plant parameter indications in evaluating*

plant conditions.

The licensee's response was evaluated to determine that (1) it addressed the matter of opetators improperly overriding the automatic actions of engineered.

  • safety features, (2) it addressed providing ope.rators with additional informa-tion and instructions to not rely upon vessel level indication alone f9r manual actions and (3) that the review included operating ptocedures and training instructions.

In its response dated April 27, 1979, the licensee stated that safety systems are to be operated in their normal automatic mode, ~nd that ~anual control is

  • taken only in extreme cases to prevent unsafe plant conditions, equipment damage,.or personnel injury.

The standing operating orders and administrative

procedures reflect this, and they address other requirements pertaining to instrument indications, administering ECCS, administering the standby liquid control system, operating within safety limits, and departure from approved procedures..

The licensee has advised us *that based on the reviews it performed in response to IE BLllletin 79-08, all. revisions to the standing operating orders and*

administrative procedures have been jmplemented.

In addition, the operating procedures-associated with reactor water level control and/or ECCS have been reviewed for notes concerning the overriding of engineered safety features and the proper us~ of level instrumentation for operational *decisions.

In its supplemental response dated August 3, 1979, the licensee confirmed that the review of operating procedures and training did include verification that operators are directed to use multiple symptoms in evaluating plant conditions and are not to rely solely on vessel level indication when taking manual actions during transients.

We conclude that the licensee's review of operating procedures and training instructi6ns satisfies the intent of IE Bulletin 79-08, Item 5.

6.

Review all safety-related valve positions, positioning requirements and positive controls to assure that valves remain positioned (open or closed) in a mariner to ensure the proper operation of engineered safety features.

Also review related procedures, such as those for maintenance, testing, plant and system start-up, and supervisory periodic (e.g., daily/shift checks) surveillance to ensure that such valves are returned to their correct positions following necessary manipulations and are maintained in their proper positions during all operational modes.

The licensee's response was evaluated to assure that(l) safety-related valve positioning requirements were reviewed for correctness, (2) safety-related.

valves were verified to be in the correct position and (3) positive controls were in existence to maintain proper valve position during normal operation as we 11 as.during survei 11 ance testing and maintenance.

I. The licensee's response dated April 27, 1979described the review of safety-related valve positioning requirements and described how such vaJves are verified to be in the correct positions:

. The positions of vital manual ECCS valve~ are controlled by the use ~nd documentation of lo~ks on the.handwheels.

Motor-operated valves on safety systems ar~ positioned so as to require minimal

~utomatic valve actiohs upon system initiation.

Moreover, ECCS initiation. logic is such that valves may be in off-positions, but will go to their proper positions under initiation conditions.

The only valves which.do not automatically open if closed are norma 11 y open and have key-1 ock switches in th'!;! contro*l room.

Surveillance and te*sting procedures for safety-related. equipment include step-by-step checklists to verify proper lineup of equipment following testing.

Each procedure is reviewed by station management as an additional verification

  • of proper r~turn to an op~rational state.

Additionally, when safety-related equipment is removed fr.om service for main-tenance, the equipment outage procedure requires documentation of its proper removal and return to service.

Functional tests of.the equipment are also required by this p~ocedure when the equipment is placed into operation to ensure operabi 1 i ty and proper response of the. system.

In its supple~ehtal response dated August 3, 1979, the licensee conf{rmed that -*

both station personne 1 and the.NRC Regidn I II resident inspector have verified.

the correct alignment for operation of all accessible valves in the safety systems.

Since shortly after the TMI atci~ent, the s~ction valves to the ECCS

  • pumps have been. verified open daily.

Finally, the licensee has impleme'rited a procedure to verify daily that all accessible ECCS valves in the main flow paths are in their proper positions.

We conclude that the licensee's review of safety-related valve positioning requi~ements, valve pcisitions and positive controls to maintain proper. valve positions satisfies the intent of IE Bulletin 79-08, Item 6.

7.

Review your operatin~ modes and procedures for* a11 systems designed to transfer potentially radioactive gases and liquids out of the primary containment to assure that undesired pumping, venting or other release of radioactive liquids and gases will not occur inadvertently.

In particular, ensure that such an occurrence would not be caused by the resetting of engineered safety features instrumentation.

List all such systems and indicate:

a.

Whether interlocks exist to prevent transfer when high radiation indication exists.

b.

Whether such systems are isolated by the containment isolation signal.

c.

The basis on which continued operability of the above features is assured.

The licensee's response was evaluated to determine that (1).it addressed all syste~s designed to transfer potentially radioactive* gases and liquids out of primary containment, (2) inadvertent releases do not occur on resetting engineered safety features instrumentation, (3) it addressed the existence of interlocks, (4) the systems are isolated on the containment isolation signal, (5) the basis for i:ontinued operability of the features was addressed and (6) a review of the procedures.was performed.

In its April 27, 1979 res~onse, the licensee identified the following lines used to transfer potentially radioactive liquids and gases from the primary containment:

Drywell floor drain sump discharge Drywell equipment drain sump discharge D~ywell and suppression chamber ventilation Torus transfer.to the condenser hotwell Valves on all the above lines isolate the primary containment during a Group 2 isolation. *This isolation is initiated on high drywell pressure (+2 psig) or low reactor water level (+8 inches), both indicating a.possible leak to the containment.. ~A seal-in circuit is used to prevent the valves from returning to their original positions upon reset of the initiating instrumentation.

A

~anual reset_performed by the operator is needed to return to the original valve lineup.

With the isolation signal present, however, no sump discharge or torus water transfer can take place, and gas venting through two-ihch valves to the standby gas treatment system can only be done after using a key-lock bypass switch.

Procedural controls and annunciator indication govern operation of this bypass feature.

No interlocks presently exist to prevent gas or liquid transfer from the containment when a containment high radiation condition exists.

While performing the review of the above isolations, it became evident that upon manual reset of the isolation, afte~ isolation initiation conditions have cleared, open paths to the containment could exist.

This is exemplified by the drywell sump discharge line valves.

Upon isolation reset, these valves will reopen ~nd the sump pumps wi11 start on high sump level, pumping poten-tially high activity material from the containment.

The practice of leaving these valves in the closed position and only opening them during the periodic pumping down of the sumps to radwaste has been instituted along with procedural controls to close these valves and leave them closed after a Group 2 isolation.

The valves will not be opened until containment atmosphere and reactor coolant

. samples can be taken to insure that high activity materials have not been released to the containment.

The drywell and torus ventilation valves would respond in a similar manner.

If a purge of the drywell were in progress at the time a Group 2 isolation*

occurred, the valves on the vent lines would return to the open position, openihg a path out of the containment upon reset of the i~olation.

The licens.ee has instituted pra.cedural controls. which specify that the Group 2 isolati6n valves be placed in the closed position before a manual reset is attempted.

In summary, lines which transfer radioactive materials from the primary con-t~ihment ~re isolable.

These isolations do not automatically reset by the*

reset of the initiation instrumentation only, but also require a manual reset.

  • This logic provides a means of controlling releases.

The isolations.are also tested according to the Technical Specifications to assure* operability.

In its supplemental response dated August 3, 1979, the liCensee stated that the procedure changes discussed above have been initiated.

By a subsequent telephone conversation, the licensee advised ~s that these procedure changes have been completed.

We conclude that the licensee's review of systems designed to transfer radio-active gases and liquids out of primary containment to assure that undesired pumping,.venting, or ~ther release of radioactive liquid~ and gases will not occur satisfies the intent of IE Bulletin 79-08, Item 7.

8.

Review and modify as.necessary your maintenance and test procedures to ensure that they require:

a.

Verification, by test or inspection, of the operability of redundant safety-related systems prior to the removal of any safety-related system from service.

b.

Verification of the operability of safety-related systems when they are returned to service following maintenance or testing.

c.

Explicit notification of involved reactor operational personnel whenever a safety-related system is removed from and returned to se~vice.

The licensee's response was evaluated to determine that operability of redundant safety~related systems i.s verified prior to the removal of any safety-related system from service.

Where operability verification appeared only to rely on previous surveillance testing within Technical.Specification intervals, we asked that.operability be further verified by at least a visual check. of the system status to the extent practicable, prior to removing the redundant eq~ipment from service.

The response was also evaluated to assure provisions were adequate to ver:ify operability of safety-related systems when they are

  • returned to service following maintenance or testing.

We also checked to see that all involv~d reactor operational personnel iri the oncoming shift are explicitly notified during shift turnover about the status of systems removed

  • from or returned to service sinte their ~revious shift1
  • In its April 27, 1979 response, the licensee stated that existing procedures require that redundant and required backup systems are functionaily tested prior to removal of safety-related equipment from service for planned mainte-nance or testing.

This practice includes testing of each subsystem and backup system prior to removal of the equipment from service and testing thereafter in. accordance with the Technical Specifications until such equipment is returned to an operational status.

Safety-related equipment maintenance or testing procedures also require system functional tes.ts to verify operability when equipment is returned to service.

These tests verify proper operation through a 11 i sol at ion "points* required for * -*:-

its removal from service.

Surveillance procedur~s or maintenance work packages which require safet~~

related equipment outages require a shift supervisor 1 s approval prior to remo~ing equipment frbm service.

This approval is given after proper testing or verification of redundant equipment is performed.

When the equipment is returned to service, these packages or procedures again require a shift supervisor 1 s notification for review and testing prior to declaring the component operable.

In its s~pplemental response ~ated August 3, 1979, the licensee stated that an administrative procedure for Dresdeh 2 and 3 has been proposed t6 govern shift turnover practices.

The pro~edure explicitly requires the oncoming oper~~6rs to be informed of the status of equipment taken out of service or returned to servi~~. any off-normal equipment lineups, activities in pro~res; or planned, the status of caution cards and jumpers, and surveillance in progress or planned.

Following a review by.the oncoming operators of the high radiati6n

. area entry log and a teview of panel indications, the offgoing operator signs the surveillance log to indicate that he has properly turned over the shift operations.

By a subsequent telephone conversation, the licensee advised us that this procedure ~hahge has been completed..

9* We conclude th~t the licensee's review and modification of maintenance, test and administrative procedures to assure the availability of safety-related systems and operational personnel knowledge of system status satisfies the intent of IE Bulletin 79-08; Item 8.

9.

Review your prompt reporting procedures for NRC notification to assure that NRC is notified within one hour of the time the reactor is not in a*

controlled or expected condition bf operation.

Further, at that time an.

open continuous communication channel shall be.established and maintained with NRC.

The licensee's response was evaluated to determine. that (l} prompt reporting p ro~edu res required or were to be modified to require that the NRC is notified within one hour of the time the reactor is not in a controlled or expected condition of operation and (2) procedures required or were to be modified to require the establishment and maintenance of an open continuous communication channel with the NRC following such events.

~*.-

In its April 27, 1979 ~esponse, the licensee ~tated that the existing Generati~g Staiions Emergency Plan requires procedures for notificati6n of the NRC as well as other regulatory agencies in the event of an emergency situation such as descr1bed iri thi~ jtem.

In such an event, the shift engineer will immediately notify the system load dispatcher, who in turn wi 11 notify the command center director on duty, who will place an immediate call to the NRC.

In the event that the load dispatcher can~ot reach the duty command center director within five minutes, the load dispatcher will then notify the NRC~

The command center procedure requires that specific telephones be designated as open lines in which continuou~ communications.c6uld be established.

Based on the licensee'~ review of the existing Generating Stations Emergency Plan and its impl~menting procedures; the licensee believes that notification of the NRC within one hour and mainten~nce of an open line of communication are ~ssured should the tonditions specified'e~er exist.

1 17 -

We conclude that the licensee 1 s response satisfies the intent of IE Bulletin 79-08, Item 9.

10.

Review operating modes and procedures to deal with significant amounts of hydrogen gas that may be generated during a transient or other accident that would either remain inside the primary system or be released to the

  • containment.

The licensee 1 s response was evaluated to determine if it described th~ means or systems avai 1 able to remove hydrogen from the primary system as we 11 as the treatment and control of hydrogen in the containment.

In its response dated April 27, 1979, the licensee stated that it had reviewed the operating modes and procedures dealing with the generation of hydrogen gas either in the primary system or released to the containment during a transient.

  • The reactor head is continuously vented to the 11A 11 main steam line and, therefore, any hydrogen gas generated during a transient could be released to the contain-ment via the 11A 11 main steam line relief valve, which relieves d_irectly to the.

s~ppression pool. *In addition, the reactor head can also be vented directly to the c~ntainment by means Of two vent valves, ~hich are remotely operated from th~ main control room.

However, these valves are not normally opened without first depressurizing the system.

The hydrogen gas released to the containment is controlled by means of the containment nitrogen inerting system.

The containment atmosphere oxygen concentration can be reduced to less than five percent with nitrogen gas.

within a 24-hour p~riod, s~b~equent to plac~ng the* reactor mode switch in the 11 run 11 position following a shutdown.

The five percent oxygen concentration minimiies the possibility of hydrogen combustion following a loss-of-coolant accident.

We conclude that the licensee's response satisfiei the intent of It Bulletin

. 79-08, Item 10.

11.

Propose changes, as required, to those technical specifications which must be modified as a fesult of yoor implementing the items above.

The licensee 1 s response was evaluated to determine that a review of the Technical Specifications had been made to determine if any changes were required as a result of implementing Items 1 through 10 of IE Bulletin 79-08.

In its letter dated April 27, 1979, the licensee reported that, based on its review and investigative program performed in reiponse to Items 1 through 10 of IE Bulletin 79-08, no modification to the Technical Specifications for Dresden 2 and 3 are appropriate, so none we~e proposed..

We conclude that the licensee 1s response satisfies the intent of IE Bulletin 79~08, Item 11.

Conclusion Based on our review of the information provided by the 1 i censee to date*, we contlude that the licensee has correctly interpreted IE Bulletin 79-08.

The actions taken demonstrate the licensee 1 s understanding of the concerns arising from the.TMI-2 accident in reviewing their implementation on Dresden 2 and 3 operations, and provide added assurance for the protection of the public health and safety during the operation of Dresden Station, \\Jnits 2 and 3.

References

1.

IE Bulletin 79-05, dated April 1, 1979.

2.

IE Bulletin 79-05A, datetj April 5, 1979.

3.

IE Bulletin 79-08, dated April 14, 1979.

4~

CECo ietter, t. Reed to J. Keppler, dated April 27, 1979.

/-

~ 19 -

5.

NRC staff letter, T. Ippolito to C. Reed, dated July 20, 1979.

6.

CECo letter, C. Reed to T. Ippolito, dated August 3, 1979.

EVALUATION OF LICENSEE'S RESPONSES*

TO IE BULLETIN 79-08 COMMONWEALTH EDISON COMPANY QUAD CITIES STATION, UNITS 1 & 2 DOCKET NOS. 50-254 AND 50-265

Introduction By letter dated April 14, 1979, *we transmitted Office of Inspection and Enforce-

  • ment (IE) Bulletin 79~08 to Commonwealth Edison Company (CECo or the licensee).

IE Bulletin 79-08 specified actions to be taken by the licensee to avoid the occurrence of an event similar to that which occurred at Three Mile Island, Unit 2 (TMI~2) on March 28, 1979.

By l~tter dated April 27, 1979, CECo provid~d responses to Action Items 1 through 11 of IE Bulletin 79-08 for the Quad Cities St~tion, Units 1 and 2 (Quad Cities 1 and 2).

The NRC staff review of *the CECo responses led to the issuance of r~tjuests fbr /-

additional information *regarding the CECo responses to certain action items of IE Bulletin 79-08.

The~e requests we~e contained in a letter dated July 20, 1979.

By letter dated August 3, 1979, CECo responded to the staff's requests for additional information.

The CECo re~ponses to IE Bulletin.79-08 provided the basis for our evaluation

  • presented below.

In addition, the actions t~ken.by the licensee in response to the bulletin and s~bsequent NRC requests were verified by onsite inspections by IE inspectors.

Evaluation.*

Each of the 11 action items requested by IE Bulletin 79-08 is repeated belo~

followed by our criteria for evaluating the response, a summary of the licensee's response and ou~. evaluation of the respon~e.

1.

Review the description of circumst~nces described in Enclosure 1 of IE Bulletin 79~05 and the preliminary chronology of the TMI-2 March 28, 1979

.accident included in Enclosure 1 to IE Bulletin 79-0SA:

a.

This review should be directed toward understanding:. (1) the extreme

~eriousness and consequences of the simultaneous blocking of both trains of a safety system at the Three Mile Island Unit 2 plant and other actions taken during the early phases of the accident; (2) the apparent operational errors which led to the eventual core damage; and *(3) the necessity to systematically analyze plant conditions and parameters and take appropriate corrective action.

.. b.

Operational personnel should.be instructed to (1) not override automatic action of engineered safety features unless continued operation of engineered safety features will result in unsafe plant conditions (see Section Sa of this bulletin); and (2) not make operational decisions based solely on a single plant parameter indication when one or more confirmatory indications are available-.

c.

All licensed operators and plant management and supervisors with operational responsibilities shall participate in this review and such participation shall be documented in plant records.

The licensee 1

~ response was evaluated to determine that (1) the scope of review was adequate, (2) operational personnel were properly instructed and (3) personnel participation in the review was documented in*p1ant records:

~-

The licensee 1 s response dated April 27, 1979 states that a review of the

The. review emphasized the five points stressed in Items 1. a and b of IE Bulletin 79-08.

In* accordance with Item 1.c, the licensee stated that documentation of this review by all litensed dperators and plant management.

and supervisors with operational responsib*ilities would be provided and maintained on file.

The licensee 1 s supp)emental response dat~d August 3, 197~

confirmed that all actions required by Item 1 had be~n completed by July 25, 1979.

We conclude that the licensee 1 s scope of review, instructions to.operating personnel and documented participation satisfy the intent of IE Bulletin*..,

79-08, Item 1.

2.

Review the containment isolation initiation design and procedures, and prepare and implement all changes necessary to initiate containment isolation,.whether manual or automatic, of all lines whose isolation does not degrade needed safety features or cooling capability, upon automatic initiation of safety injectioh:

The licensee 1 s response was evaluated to verify that containment isolation ihitiation design and procedures had been reviewed to assure that (1) manual or automatic initiation of containment isdlafion 6ccurs on automatic initiation

t.

. ' of safety injection and (2) all lines (including those designed to transfer radioactive gases or liquids) whose isolation does not degrade cooling capability or needed safety features were addressed.

The licensee's response of April 27, 1979 states that a review of the existing isolation design and procedures had been performed to determine whether all systems ncit needed for safety injection would isolate on injection signal.

The review verified that a safety injection signal would automatically initiate containment isolation, if containment isolation had not already been initiated, by closure of all valves where such closure does not degrade needed safety features or cooling capability.

In addition, applicable emerge11cy operating procedures were reviewed to assure proper operator action in the event of automatic initiation of containment isolation.

In its supplemental response dated August 3, 1979, the licensee confirmed that a procedure cha~ge had b~en initiated to provide for proper operator action in the event of a reactor building closed cooling water (RBCCW) system return line break inside the drywe ll.

The licensee _further confirmed that its review included all lines penetrating primary containment and that the review included the applicable emergency instructions and operating procedures.

No changes to design or procedures were reported by the licens~e other than the procedure change for operator action. for the aforem~ntioned RBCCW system return line break inside ~he drywel 1.

We conclude that the licensee's review of containment isol~tion initiation design and proc~dures satisfies the intent of-IE Bulletin 79-08, Item 2.

3. *. Describe the actions, both automatic and manual, necessary for proper functioning of the auxiliary heat removal systems (e.g., RCIC) that are used when the main feedwater system is not operable.

For any manual action necessary, describe in summary form the procedure by which this action is taken in a timely sense.

The licensee's response was reviewed to as~ure that (1) it described the automatic and manual actions necessary for the proper functioning of the

4 -

auxiliary heat r~moval systems when the main feedwater system is not operable and (2) the procedures for any necessary manual actions were described in summary form.

The licensee's response dated April 27, 1979 states that following a lciss of feedwater, reactor scram occurs at low water level (+8 inches).

In about 34 seconds, reactor water ievel will fall to low-low level (-59 inches), at which time high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) system operation and main steam isolation valve (MSIV) closure will be initiated.

Main steam relief valves may open shortly following MSIV closure, relieving vessel pressure tp.the suppression pool.

With no operator action, the HPCI and RCLC systems will continue adding water to the vessel until the level reaches high level (+48 inches) at which time the HPCI and RCIC system turbines will automatically trip.

The HPCI syst~m turbine will automatically restart if the low water level signal is again reached and the turbine trip signal clears.

The RCIC*system turbin~ trip must

  • be manu~lly reset.

All other HPCI and RCIC system operation is automatic.

From this point, cool down would continue with the removal of decay heat using the RCIC system in manual control.

If the RCIC system is unavall~ble, the relief valve would be used to control reactor depressurization.

This is performed by manually opening a relief valve from the main control room. *The use of the HPCI system for reactor -

makeup (either manually or by allbwing automatic initiation) would provide additional:depr~ssurization of the reactor. *After depressurization to 350 psig, the.low pressure coolant injection* (LPCI) or core spray (CS). systems could also be used for reactor water makeup.

The HPCI and RCIC systems have redundant supplies of water.

Normally they t~ke suction from the c6hdensate storage t~nk (CST).

The HPCI.system suctioh will aut6matically transfer from the CST to the suppression pool if the CST water is depleted or the suppression pool water level increases to a high level.. The RCIC system suction must be manually transferred from the CST to

_;.. the suppression pool using controls located in the main control room.

This action would need to be taken when control room alarms indicate CST low water level or suppression pool high water level.

The operator can manually initiate the HPCI and RCIC systems from the control room before automatic initiatton from low-low water level is reached.

If both the HPCI and RCIC systems are unavailable, the relief valves would be used to manually depressurize*the reactor pressure vessel to less than 350

  • psig when, in conjunction with a low-low reactor water level of -59 inches, the LPCI and.CS systems would be automatically initiated.

Once the reactor water level has been recovered and it has been absolutely determined that the*

LPCI and CS systems are no longer needed, these syste~s would be manually shut dO\\Vn.

A 1 though the capability of the aforemerit i oned systems to perform as indicated is described during' initial operator training and in subseauent retr~ininn nn specific procedure existed which dealt with the loss of feedwater and possible possible unavailability of both the HPCI' and RCIC systems.

In its supplemental resporise dated August 3, 1979, the licensee stated that operating procedures have been revised.to specifically instruct operators to manually depressurize the reactor using the relief. valves, allowing the LPCI and CS systems to. inject water if the normal feedwater, HPCI and-RCIC systems are unavailable.

All licens~d op~rators have received training in these revised procedures and ~otumentation bf this training will be kept on file.

We conclude that. the licensee's procedural summary of automatic/manual actions necessary for the proper fun ct i oni ng of auxiliary heat remova 1 systems used when th~ main feedwater system is inoperable satisfies the intent of IE Bulletin 79-08, Item 3.

4.

Describe all uses :and types of vessel leve.1 *indication for both automatic and manual initiation of safety systems.

Describe other redundant instru-mentatio~ which the operator might have to give the same informati-0n

° regarding plant status.

Instruct operators to utilize other available information to initiate safety systems.

The licensee's response was evaluated to determine that (1) all uses and types of vessel level indication for both automatic and manual initiation of safety systems wer~ addressed, (2) it addr~ssed other instrumentation available to the operator to determine changes in reactor coolant inventory and (3) operators were instructed to utilize other available information to initiate safety systems..

The licens~e's response of April 27, 1979 states that vessel level indication

~

for both automatic and manual initiation is achieved by diverse and redundant instrumentation.

The vessel level indication is comprised of four types of instruments.. Two of the four types, the narrow and wide range Yarway i ndi catOrs, are used for the manual and/or automatic initiation of the safety systems.

(1)

The *narrow range Yarway level instrumentation has a range of +60 inches _

to -60 inches.

This covers the normal operating range down to the lower instrument nozzle.

Operation of this instrumentation requires no po~er supply, and it provides most of the trip functions ~ssociated with the.

water level instrumentation.

It is referenced to uinstrument zero, 11 is calibrated at 1000 psig reactor pressure; and is rapid-pressure-change-compensated.

The setpoints and functions of the narrow range Yarway include:

Setpoints

+48 inches

+30 inches Functions Trips maih turbine, HPCI and RCIC system turbines'and main feedwater pumps.

Automatic feedwater runout reset. Inhibits runout flow control abbve +30 inches.

Normal operating' level.

+8 inches

-59 inches

  • Reactor scra*m.

Initiates Groups 2 and 3 contain-

. ment isolation and control room ventilation isolation.

Initiates ECCS.

Initiates RCIC system.

Initiates Group 1 containment isolation.

Initiates standby diesel-generators.

Trips recirtulation pumps.

Two narrow range Yarway level indicators are located in the main control room and ten level indicating switches with indicators are located in the reactor bui.lding.

(2)

The wide range Yarway level instrumentation has a range of 300 inches, covering the active core range and overlapping the lower part of the narrow range Yarway.

This provides i ndi ca ti on.during and after a bl owdown accident when the r*ecirculation pumps are tripped.

It also signals to prevent the residual heat removal (RHR) system from operating in the containment spray mode when the level is below 2/3 core height.

Two.wide range Yarway indicators are located in the control room.

In addition to the Yarway level instruments, there are narrow and wide

_range GE/MAC level instruments which can be used by the oper~tor to monitor vessel water level.

(3)

The narrow range GE/MAC level instrumentation is the most accurate level indication available to the operator.

It provides the level input to the feedwater level contra l system.

Its range. of zero to 60 inches covers th~ normal operating range.

It is calibrated at 1000 psig and is temperature co~pensated.

The recorder.alarms in the control room at high ~nd low water levels.

The level indications can also be displayed on the control room digital window display and recorded on the control room computer printout.

(4)

The wfde range GE/MAC level tnstrumentation provides level indication during vessel flooding on cooldown.

Its range is 400 inches and covers the u~per portion of the reactor vessel.

One wide range GE/MAC level indicator is located in the main control room.

The wide range GE/MAC level indications can also be displayed on the main control room digital window recorded display and on the control room computer printout.

There is also a lowe~ 400 inches vessel level GE/MAC indicator which covers levels below the range of the lower Yarway and overlaps the range of all level instrumentation except the upper wide range GE/MAC.

In addition to the above indications available to the operator; alarms associated with the Butomatic actions listed above-will inform* the operator of the reactor vessel level* status and require his verification that actions have taken place at the appropriate levels.

As listed in the licensee 1 s supplemental response dated.August 3, 1979, the control room operator has_numerous alternate indications that can indirectly indicate a change i.n reactor vessel coolant inventory.

Instrumentation is available in the control room to monitor:

Drywel l Pressure Drywell Temperature

. Suppression Chamber Pressure Suppression Chamber Temperature Suppression Chamber Water Level Feed.water Flow Steam fl ow Reactor Pressur~

Relief Valv~ Discharge Temperature Drywell Floor and Equipment Sump Discharge Flow Reactor Building Closed Cooling Water Temperature

.fl, i

9 -

Any of these measured parameters could indirectly indicate a change in reactor vessel coolant inventory.

Th~ licensee 1 s August 3, 1979 letter states that the operators have been instructed to utilize other available information as part of their training as required by Item 1 of IE Bulletin 79-08.

In addition, the use of

  • multiple indications to identify abnormal conditions is an underlying philosophy of the licensee 1s ~bnormal and emergency procedures. *All licensed operators are trained on these procedures annually as part of their requalification training.

We conclude that the licensee 1s description of the uses and types of reactor

  • "'.essel level/inventory instrumentation and instructions*to operators regarding the use of this information satisfies the intent of IE Bulletin 79-08, Item 4.
5.

Re~iew the actions directed by the operat1ng procedures and training instructions to ensure that:

a.

Operators do not override automatic actions of engineered safety features, unless continued operation of engineered safety features will result in unsafe plant conditions (e.g., vessel integrity).

b.

Operators are provided additional information and instructions to not rely upon vessel level indication alone for manual attions, but to also examine other plant parameter indications in evaluating plant.conditions.

The licensee 1 s response was evaluat~d to determine that (1) it addressed the matter of operators improperly overriding the automatic actions of engineered safety f~atures, (2) it addressed providing operators with additional informa-tion and instructions to n~t rely upon vessel level indication alone for manual actions and (3) that the review.included ope~ating procedures and training instructions.

In its *response dated April 27, 1979, the. licensee stated that safety systems are to be operaied in their normal autbmatic mode, and that manual control ii taken only in extreme cases to prevent unsafe plant conditions, equipment

t

- 10.-

damage, or personnel injury.

The standing operating orders and administrative..

procedures reflect this, and they address other requirements pertaining to instrument indications, administering ECCS,

~dministerin~ the standby liquid control system, operating within safety limits, and departure from approved

. procedures.

The licensee has advised us that based on the reviews it performed in response to IE ~ulletin 79-08, all revisions to the standing operating orders and administrative procedures have been implemented.

Iri addition, the operating procedures associated with reactor water level control and/or ECCS have been reviewed for notes concerning the overriding of engineered *safety features.and the proper use of level instrumentation for operational decisions.

In its supplemental response dated August 3, 1979, the licensee confirmed that the review of operating procedures and training included verification that ope~ators are di~ected to use ~ultiple indicatibns in evaluating plant

  • conditions and are ndt to rely solely on vessel level indication when taking manual acti-0ns during transi~nts.
  • W~ conclude that t~e licensee's review of operating procedures and trainihg instructions satisfies the intent of IE Bulletin 79-08, Item 5.
6.

Review all safety-related valve positions, positioning requirements and positive cont~6ls to as~ure that valves remafn positioned (open or closed) in a manner to ensure the proper operation of engineered safety features.

Also review related procedures, such as those for*maintenance, testing, plant and system start-up, and supervisory periodic (e.g., daily/shift checks) surveillance to ensure that such valves are returned to their correct positions following necessary manipulations and are maintained in their proper positions during all operational modes.

The licensee's response was evaluated to assure that (1) safety-related valve positioning requirements were feviewed for correctness, (2) safety-related valves wete verified to be in the correct position and (3) positive controls were in existence to maintain proper valve position durirtg nor~al operation as well as during surveillance testing and maintenance.

/-,,,..

  • The 1icensee 1 s response dated. Apri 1 27, 1979.described the review of safety-re lated valve positioning requirements and described how safety-related valves are verified to be in the corr~ct positions.

The positions of vital manual ECCS valves are controlled by the use and docu-mentation of locks on the handwheels., Motor-operated valves on safety systems

  • are positioned so as to require minimal automatic valve actions upon system initiation.

Moreover, ECCS initiation logic is such that valves may be in off-positions, but will go to their proper positions under in*itiation conditions.

The only valves which do not automatically open if closed are normally open and have key~lock switches in the control room.

Surveillance and testing procedures for safety-related equipment include step-by-step checklists to verify proper lineup of equipment following testing, Each procedure is reviewed by station management as an additional verification of proper return to an operational state.

Additio~ally, when safety-related equipment is removed from service for maintenance, the equipment outage procedure requires documentation of its proper removal and return to service.

Functional tests of th~ equipment are also required by this procedure when the equipment is placed into operation to ensure* operabi 1 i ty and proper response of the system.,

In its supplemental response dated Augu~t 3, 1979, the licensee confirmed.

that both station personriel-and the NRC Region III resident inspector have verified the correct alignment for operation of all accessible valves in the safety systems.

Since shortly after the TM! accident, the suction valves to the ECCS pumpsha.ve been verified open daily.

By a subsequent telephone conversation, the licensee advised us that it has implemented a procedure to verify daily that all accessible ECCS valves in the main flow paths are in their proper po~itions.

We conclude that th~ licensee 1s review of safety-related valve positioning requirements, valve posit{ons and positive controls to maintain proper valve positions satisfies the intent of IE Bulletin 79-08, Item 6.

"' ' 7.

Review your operattng modes and procedures for all systems designed to transfer potentially radioactive gases and. 1 iquids out of the primary containment to assure that undesired pumping, venting or othe~ release of radioactive liquids and gases will not occur inadvertently.

In particular, ensure that such an occurrence would not be caused by the resetting of engineered safety features instrumentation.

List all such systems and *indicate:

a.

Whether interlocks exist to p~event transfer when high radiation indication.exists.

b.

Whether ~uch systems are isolated by the containment isolation signal.

c.

The.basis on which continued operability of the above features is assured.

The licensee's response was evaluated to dete~mine that (1) it addressed all systems designed to transfer potentially radioactive gases and liquids out of primary containment, (2) inadvertent releases do riot occur on resetting engineered safety features instrumentation, (3) it addressed the existence of interlo~ks, (4) the systems are isolated on the containment isolati6n signal, (5) the basis for continued operability of the features was addressed and (6) a review of the procedures was performed.

In its April 27, 1979 response, the licensee identified th~ following lines used to transfer potentially radioactive liquids and gases from the containment:

Orywell floor drain sump discharge Orywell equipment drain sump discharge Orywe 11 and suppression chamber ventilation Torus tran~fer to condenser hotwell or ~adwaste Valves on all the above lines isolate the primary containment during a Group 2 isolation.

This isolation is initiated on high drywell pressure (+2 psig) or low reactor water level (+8 inches), both indicating a possible leak to the containment~ A seal~in circuit is used to prevent the valves from returning t6 their original positi6hs upon reset of the initiating instrumentation.

A

!/*;

... manual reset performed by the operator is needed to retu~n to the original valve lineup.

With the isolation signal present, however, no sump discharge or torus water transfer can take place, and gas venting through twd-inch valves to the standby gas treatment system can only_b~ done after using a key-lock bypass switch.

Procedural controls and annunciator indication govern operation of this bypass feature.

No interlocks presently exist to prevent gas or liquid transfer from the containment when a containment high radiation condition exists.

While performing the review of the above isolations, it became evident that upon manual reset of the isolati6n, after* isolation initiation conditions have-_

cleared, open paths to the containment could exist, This is exemplified by

~he drywell sump discharge line valves.

Upon isolation reset, these valves will reopen and the sump pumps will start on high sump level, pumping poten-

- tially high activity material from the containment.

At the present time, these valves are maintained in the closed position and opene~ only during the periodic pumping down of the sumps to rad_waste.,This prac_tice wi.ll be continued, along wit~ procedural controls to close these valves and leave them clcised after a Group 2 isolation.

They will not be opened until containment atmosphere and reactor coolant samples can be taken to insure that high activity materials have not been released_ to the contain~ent.

-The drywell and torus ventilation valves would respond in a similar manner.

If a purge of the drywell were in progress at the time a Group 2 isolation occurred, the valves on the ve~t lines would r~turn to the open position,

  • opening a path out of the coMtainment upon reset of the isolation.

The licensee has instituted procedural controls which specjfy that the Group 2 isolation valves be placed in the closed po~ition before a manual res~t i~

attempted.

  • In summary, isolations of lines which transfer radioactive materials from the primary con~ainment do exist.

These isolations do not automatically reset by the reset of the initiation instrumentation only, but a:lso require a manual

.. reset.

This logic provides a means of controlling releases.

The isolations are also tested according to the Technical Specifications to assure operability.

In its supplemental. response dated August 3, 1979, the licensee stated that the procedure changes discussed above have been initiated.

By a subsequent telephone conversation, the licensee advised us that these procedure changes have been completed.

We conclude that the lice~see's review of systems designed to transfer radio~

active gases and liquids out of primary containment to a~sure that undesired pumping, venting, or -0ther release of radioactive liquids and gases will not.

-0ccur, satisfies the intent of IE Bulletin 79-08, Item 7.

8.

Review and. modify as necessary your maintenance and test procedures to ensure that they require:

a.

Verification, by test or inspection, of the operability of redundant safety-related systems prior to the removal of any safety-related system from service.

b.

Verification of the operability of safety-related systems when they are returned to servic~ following maintenance or testing.

c.

Explicit notification of involved reactor operational pe~sonnel whenever a safety-related system is removed from and returned to service.

The lii:ensee's response was evaluated to determine that operability of redundant safety-refated systems is verified prior to the removal of any safety-related system from service.

Where operability verification appeared only to rely on previous surveillance te~ting within Technical Specification intervals, we asked that operability be further verified by _at least a visual check of the system status to t~e extent practicable, prior"to r~movi~g the redundant

  • equipment from service.

The response wa~ al~o evaluated to assure ihat provi-sions were adequate to verify operability of safety-related systems when they are ~eturned to service following maintenance or testing.

We al~o checked to s~e that al' involved reactor operational personnel in the onco~ing shift are

- 15 *-

explicitly notified during shift turnover about the status of systems removed from or returned to service since their previous shift.

In its April 27, 1979 response, the licensee stated that existing procedures require that redundant and required backup systems are functionally tested prior to removal of safety-related equipment from service for planned mainte-nanc~ or testing.

This pfactice includes testing of each subsystem and backup system prior to removal.of the equipment from service and testing thereafter in accordance with the Technical Specifications until such equipment is returned to an operati-0nal status.

Safety-related equipment maintenance or testing procedures also require system functional tests to verify operability when equipment" is returned to service.*

These tests verify proper operation* through all isolation* points required for its removal from service.

Surveillance procedures or maintenance work packages which require safety-related equipment outag~s require a shift supervisor 1 s approval prior to removing equipment from service.

This approval is given after proper testing or verif~cation of redundant equipment is performed.

When the'equip~ent is returned to service, these packages or procedures again require a shift supervisor 1 s notification for review and testing prior to declaring the component operable.

In its supplemental response dated August 3, 1979, the licensee stated that

  • .Procedure QAP 300-4, 11Shift Change for Nuclear Station Operators, 11 describes those actions to be taken upon shift turnover.

Included. in these actions is the review of the shift log by the jncoming operator for equipment tak~n out of service.

Othe~ actions are verbally transferred at shift change, such as sp~cial conditio~s. current operational status, and useful information fo~

future shifts.

The incoming operator, by this procedure, is required to check control room panels for proper syste~ lin~ups.

We ~onclude that the licens~e's review and modification of maintenance, test and administrative procedures to assure the availability of safety-related systems and operational personnel knowledge of system status satisfies the intent of IE Bulletin 79-08, Item 8.

9.

Review your prompt reporting procedures for NRC notification to assure that NRC is notified within one hour of the time the reactor is not in a controlled or expected condition of operation.

Further, at that time an open continuous communication channel shall be established and maintained with NRC.

The licensee's response was evaluated to determine that (1) prompt reporting procedures required or were to be modified to require that the NRC is notified within one hour of the time the reactor is not in a controlled or expected condition of operation and (2) procedures required or were to be modified to require the establishment. and maintenance of an open continuou~ communication channel with the NRC following such events.

In its April 27, 1979 response, the licensee stated that the existing Generating

  • Stations Emergency Plan requires procedures for notification of the NRC as well as.other regulatory agencies in the event of an emergency situation such as described in this item;~ In s~ch an event, the shift engineer will immediately notify the system load dispatcher, who in turn will notify the command center director on duty, who wili place an immediate call to *the NRC.

In the event that the load dispatcher cannot reach the duty command center director within five minutes, the load dispatcher will then notify the NRC.

The command cente~ procedure require~ that specific telephones be designated as open lines in which tontinuous communication~ ~ould be ~st~blished.

Based 6n the licensee's review of the existing Generating Stations Emergency Plan an*d its implementing procedures, the licensee believes that not.ification

~f ihe NRC within one hour and maintenance of an open line of communication

  • are assured should the conditions specified ever exist.

We conclude that the licensee 1 s response satisfies the intent of IE Sulletin 79-08, Item 9.

10.

Review operating modes and procedures to deal with significant amounts of hydrogen gas that may be generated during a transient -0r other accident

  • that would either remain inside the primary system or be released to the containment.

The licensee 1 s response was evaluated to det~rmine if it described the means or systems available to remove hydrogen from the primary system as well as the treatment and control of hydrogen in the containment.

In its response dated April 27, 1~79, the licensee stated that it ha~ reviewed the operating mode~ and procedures dealing with the generation of hydrogen gas either in the primary system or released to the containment during a transient.

The reactor head is continuously vented to the 11 A 11 main steam line and, therefore, any hydrogen gas generated during a transient could be released to the contain-ment via.the 11 A 11 main steam line relief valve, which relieves directly to the suppression pool.

In addition, the reactor head can also be vented directly to the containment by ~eans of two vent valves, which are remotely operated.

from. the main control room.

However, these valves are not normally opened

~ithout first dep~essurizing the system.

The hydrogen gas released to the containment is controlled by means of the containment nitrogen inerting sy~tem.

The containment atmosphere oxygen concentration can b~ r~duced to less than five percent with nitrogen gas within a 24..,hour period, subsequent to placing the reactor mode switch in.

the 11 run 11

. position fol lowing a shutdown.. The five percent oxygen concentra-tion minimi.zes the possibility of hydrogen combustion following a loss-of-coolant accident.

We conclude that the licensee 1 s response satisfies the intent of IE Bulletin

  • 79-08, Item 10.

. 11.

Propose changes, as required, to those technical specifications which must be modified as a result of your implementing the items above.

The licensee's response was evaluated to.determine that a review of the Technical Specifications had been made to determine if any changes were required as a result of implementing Items 1 through 10 of IE Bulletin 79-08.

In its letter dated April 27, 1979, the licensee reported that, ba~ed 6n its review and investigative program performed in response to Items 1 through 10 of IE Bull~tin 79-08, no modifications to the Technical Specifications for

. Quad Cities 1 and 2 are appropriate, so none were proposed.

We conclude that the licensee's response satisfies the intent of IE Bulletin 79-08, Item 11.

Conclusion Based on our review of the information provided by t~e licensee to datei we conclude that the licensee has ~orrectly interpreted IE Bulletin 79-08.

The actions taken demonstrate the licensee's understanding of the concerns adsing from the TMI-2 accident in reviewing their implementation on Quad Cities 1 and 2 operations, and provide added assurance for the protection of the public health and safety during the operation of Quad Cities Station, Units 1 and 2.

References*

1.

IE-Bulletin 79-05, dated April 1, 1979.

2.

IE Bulletin 79-05AJ dated April 5, 1979.

3.

.IE Bulletin 79-08, dated April 14, 1979;

4.

CECo letter, C~ Re~d to J. Keppler, dated April 27, 1979.

.;;. l.i;** "-"'

l~ -~

  • 5~

NRC_staff letter, T. Ippolito to C. Reed, dated July 20, 1979.

6.

CECo letter, C. Reed to T. Ippolito, d~ted August 3, 1979.

Retrieved from "https://kanterella.com/w/index.php?title=ML17192A598&oldid=5130951"