ML19260C574
| ML19260C574 | |
| Person / Time | |
|---|---|
| Site: | Humboldt Bay |
| Issue date: | 12/27/1979 |
| From: | Ippolito T Office of Nuclear Reactor Regulation |
| To: | Crane P PACIFIC GAS & ELECTRIC CO. |
| References | |
| IEB-79-08, IEB-79-8, NUDOCS 8001080032 | |
| Download: ML19260C574 (21) | |
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,0, UNITED STATES y 7, e. (, 3 i NUCLEAR REGULATORY COMMISSION s c i ej/ '
e WASHINGTON, D. C. 20555
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December 27, 1979 Docket No. 50-133 Mr. P. A. Crane Vice President and General Counsel Pacific Gas and Electric Company 77 Beale Street, 31st Floor San Francisco, California 94106'
Dear Mr. Crane:
SUBJECT:
NRC STAFF EVALUATION OF PACIFIC GAS AND ELECTRIC COMPANY RESPONSES TO IE BULLETIN 79-08 FCR HUMBOLDT BAY POWER PLANT We have completed our review of the information that you provided in your letters dated May 1 and August 6,1979 in response to IE Bulletin 79-08 for the Humboldt Bay Power Plant.
We have concluded that you have taken the appropriate actions to meet the requirements of each of the eleven action items identified in I: Bulletin 79-08. A copy of our evaluation is enclosed.
As you knew, NRC staff review of the Three Mile Island, Unit 2 (TMI-2) accident is continuing and other corrective actions may be required at a later date.
For example, the Bulletins and Orders Task Force is conduct-ing a generic review of operating boiling water reactor plants. Specific requirements for your facility that result from tnis and other TMI-2 investigations will be addressed to you in separate correspondence.
Since.
/ /
e--
q Thomas A. Ippolito, Chief Ocerating Reactors Branch #3 Divisicn of Operating Reactors Enciosure:
NRC Staff Evaluation
cc w/ enclosure:
See next page 1701 198 03
_2 8001086
/
Mr. Philip A. Crene, Jr.
Pacific Gas & Electric Company cc:
Mr. James Hanchett Public Information Officer Region V - IE U. S. Nuclear Regulatory Commission 1990 N. California Boulevard Walnut Creek, California 94596 Humboldt County Library 636 F Street Eureka, California 95501 David E. Pesonen, Esquire Garry, Dryfus, McTernan, Brotsky, Herden & Pesonen, Inc.
1256 Market Street San Francisco, California 94102 Linda J. Brown, Esquire Oonohew, Jones, Brown & Clifford 100 Van Ness Avenue,19th Floor San Francisco, California 94102 Dr. Derry Aminoto Department of Conservation Division of Mines & Geology 1416 9th Street, Roon 1341 Dacramento, California 95814
EVALUATI0ti 0F LICENSEE'S RESPONSES TO IE BULLETIN 79-C3 PACIFIC GAS AND ELECTRIC COMPANY HUMBOLOT BAY POWER PLANT, UNIT NO. 3 DOCKET NO. 50-133 1701 200
Introduction By letter dated April 14, 1979, we transmitted Office of Inspection and Enforcement (IE)Bulletin 79-08 to Pacific Gas and E.lectric Company (PG&E or the licensee).
IE Bulletin 79-08 specified actions to be taken by the licensee to avoid occurrence of an event similar to that which occurred at Three Mile Island, Unit 2 (TMI-2) on March 28, 1979.
ByietterdatedMay1, 1979, PG&E provided responses to Action Items 1 through 11 of IE Bulletin 79-08 for the Humboldt Bay Power ' Plant, Unit 3 (Humboldt Bay).
The NRC staff review of the PG&E responses led to the issuance of requests for additional information regarding the PG&E responses to certain action items of IE Bulletin 79-08.
These requests were contained in a letter dated July 20, 1979.
By letter dated August 6, 1979, PG&E responded to the staff's requests for additional information.
~
Humboldt Bay has been shutdown since July 2, 1976 under an NRC c" der for modification of license wnich requires NRC approval prior to restart.
The pacing task for resuming operation has been a geologic investigation because of seismic concerns.
Until these concerns are closer to resolution, work on other safety issues not pertinent to a shutdown reactor has been deferred.
Consistent with this, by its letter dated August 6, 1979, the licensee has committed that changes in design and operating procecures discussed in this evaluation will be ccmpleted before reactor operation resumes.
We find this schedule acceptable.
The PG&E responses to IE Bulletin 79-08 provided the basis for our evaluation presented below.
Evaluation Each of -he 11 action ite :s recuested by IE Bulletin 79-08 is repeated below followec ey our criteria f r evaluating tne res:onse. a st.mmary of the licensee's response anc our evaluat:an of the res:cnse.
1701 201
. 1.
Review the description of circumstances described in Enclosure 1 of IE Bulletin 79-05 and the preliminary chronology of the THI-2 March 28,1979 accident included in Enclosure 1 to IE Bulletin 79-05A.
a.
This review should be directed toward understanding:
(1) the extreme seriousness and consequer.ces 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 a: parent 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 engineerec safety features will result in unsafe plant conditions (see Section 5a 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's response was evaluated to determine that (1) the scope of review was adequate, (2) cperational personnel will be properly instructed and (3) personnel participation in the review will be documented in plant records.
The licensee's response dated May 1,1979 stated that a review of the circum-stances and preliminary chronology of tne TMI-2 accicent has been conducted.
PG&E is developing and will issue a summary of this review to all licensed operators and to all supervisors with operational resoonsibilities.
The licensee is also formulating a guide to describe the general actions that are required during an emergency situation.
These actions, which have heretofore been emphasized in the training program, concern; (1) no. overriding safety system automatic actions unless continued operation of the engineered safety feature will result in unsafe plant concitions and (2) the use of all available and applicable instrumentation as tne :: asis for making cperational cecisions.
1701 202
. in addition to the above, training sessions will be conducted (with appropriate documentation in plant records) to assure that all licensed supervisors and operators are thoroughly familiar with this review and this guidance.
We conclude that the licensee's scope of review and its commitments to provide instructions to operating personnel and to document participation satisfies the intent of IE Bulletin 79-08, Item 1.
2.
Review the containment isolation initiation design and procedures, and prepare and imniement 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 injection.
The licensee's response was evaluated to verify that containment isolation initiation design and procedures had been reviewed to assure that (1) manual or automatic initiation of containment isolation occurs on automatic initiation of safety injection and (2) all lines (including those designed to t ansfer radioactive gases or liquids) whose isolation does not degrade cooling capability or needed safety features were addressed.
The licensee's May 1,1979 response stated that a review of the automatic containment isolation initiation design and procedures relating to manual and automatic containment isolation had been completed.
The only change identified involved the emergency operating procedure that describes specific actions required following a line break inside the drywell.
The change requires remote manual isolation of the closed cooling water lines to the non-safety-related dry. ell air coolers.
These are the only lines that can be manually isolated which are not already covered by the existing procedure.
All other lines penetrating the pressure suppression containment system which are not isolated in sucr. a situation involve needed safety features.
By letter cated August 5,1979, tre licensee statec tnat it had reviewed all acclicaole operating ar.: emergency ocerating procedures and confirmed that 1701 203 g
. containment isclation exists via (a) normally closed valves, (b) is automatically initiated by engineered safeguards actuation or (c) is manually initiated.
This is true for all lines except those needed for ssfety features or cooling capability and the closed cooling water lines to the drywell air coolers which were identified as requiring manual isolation.
We compared the licensee's response of August 6,1979 with the valve and piping arrangement in Figure 3-3 of the licensee's submittal of Decemoer 15, 1967 and found it to be consistent.
We conclude that the licensee's review of containment isolation initiation design and procedures satisfies the intent of IE Bulletin 79-08, Item 2.
3.
Describe the actio9s, both automatic and manual, necessary for proper functioning of the auxiliary heat removal systems (e.g., RCIC) that are used when the main feedwster 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 assure that (1) it described the automatic and manual actions necessary for the proper functioning of the auxiliary heat removal systems when the main feedwater system is not operable and (2) the procedures 'or any necessary manual actions were described in summary form.
The licensee, in its response dated May 1,1979, stated that several alternate systems, both high and low pressure, can be utilized as auxiliary heat removal systems to cool the reactor in' the event the main feedwater system is not available.
The use of each of these systems is described in detail in its emergency and normal operating procedures.
a.
Tne emergency concenser, which is initiatec automatically at 1200 psig or car ce remotely in tiated frcm tne control room is the principal syster i
usec to provice cc: ling of the reactor uncer these conditions.
The :n'y manual acticns rec.f e: are tncse necessary to provide makeup water Oc
- ne emergency concenser shell sacrcximately eignt hours after initiaticn.
1701 204
. b.
The reactor cleanuo system, which is normally in operation, can be utilized to provide supplementary cooling.
If the system were to be isolated by engineered safeguards actuation, it can be restored to service by manual emergency cooling actuation from the control rcom.
This requires that the control room operators (1) place the control switch in the " emergency" position (this places maximum cooling water flow on the cleanu: system and bypasses the demineralizer and regenerative heat exchangers), (2) open the cleanup isolation valves from the valve control : card and'(3) restart the cleanup pump and adjust the cleanup flow to optimum.
c.
A control rod hycraulic pump in combination witht the following system lineups can be utilized for heat removal:
(1) Steam from the reactor vessel can be routed to the main condenser via the turbine bypass valves, condensed, then returned to the reactor via tne hydraulic system pump.
Utilization of this system requires the following actions from the control room:
(a) override the isolation signal on the main steam isolation valves, if one is present, and : pen the valves and (b) cpen the bypass valves to the main condenser.
In addition, the reactor feedpumps in the reactor feedpump room aculd be manually isolated if required.
(2) Steam can be routed to the suppression chamcer via the reactor vent valves (or safety valves) and makup can be supplied by the hydraulic pumps from the condensate system.
Utilization of this system lineup would require the following actions:
(a) manual initiation of the reactor vent valves, (b) realignment Of the makeup water system from the condensate storage tank in the yard area to provide additional water to the condensate system and (c) initiation of the recirculation cooling mode for the su;:pression chamber.
This system could not be.se: for an extended period of time since the suc::ression 0 am:er will eventually be fillec.
An alternate methoc would have to :e ::rovided (sucn as core spray) once pressure was 1701 203 reduced.
d.
The core spray system can be used as an auxiliary heat removal system if reactor pressure is reduced below 150 psig.
Manual actions required to utilize this system lineup are as follows:
(1) initiate operation of the reactor vent valves, (2) initiate the core spray system, (3) change the valving lineup from tha normal closed cooling water supply to the suppression pool cooler to the screen wash pump supply in order to provide maximum cooling, e.
The shutdown system, which is the normal decay heat removal system for refueling operations, can be used for reactor cooling once reactor pressure decreases to less than 135 psig.
Utilization of this system would require that the operator (1) open the inlet and outlet motor operated isclation valves, (2) raise the reactor water level to cover the suction nozzle to this system, (3) start the pump and (4) establish closed cooling water flow to the shutdown heat exchangers.
We conclude that the licensee's procedural summary of automatic /~anual actions necessary for the proper functioning of auxiliary heat removal systems used hen the main feedwater system is inoperable satisfies the intent of IE Sulletin 79-06, Item 3.
a.
Describe all uses and types of vessel level indication for both automatic anc manual initiation of safety systems.
Describe other redundant instrumentation which the operator might have to give the same information regarding plant status.
Instruct operators to utilize other available information to initiate safety systems.
The licensee's response was evaludted to determine that (1) all uses and types of vessel level indication for both automatic and manual initiation of safety systems were acdressed, (2) it addressed other instrumentation avaiiaole to the operator to determire changes in reactor coolant inventory and (3) ocerators were instructed to utili:e other available information to initiate safety systems.
1701 206 The licensee's May 1, 1979 response stated that operators have been instructed to utilize all available sources of information in deciding to manually initiate safety systems.
By its letter dated August 6, 1979, the licensee stated that the Humboldt Bay reactor has two types of level instrumentation; one system is manufactured by Yarway and the other by Bailey.
The Yarway reactor water level instrumentation is utilized to initiate a reactor trip and reactor isolation upon a reactor low water level signal.
If reactor pressure is less than 350 psig, the reactor low water level signal also activates the core spray and low pressure core flooding systems.
With coincident signals from high drywell pressure and loss of feedwater flow, Icw reactor water level will also initiate the reactor depressurization system (vent valves).
The Bailey reactor water level instrumentation is utilized to automatically or manually control the reactor water level via feedwater regulation during power operation.
The Bailey system is not utilized for automatic actuation of the engineered safety systems.
The Yarway and Bailey level columns are attached to stilling wel's which in turn are attached to the eactar vessel.
The Bailey primary sensors are saturated level columns since the reference leg is maintained at saturation conditions by locating it inside the variable leg and insulating the entire column.
The Yarway level sensors are designed to operate with the reference leg subcooled since the reference leg is designed to operate at drysell ambient conditions (approximately 175 degrees Fahrenheit) plus 56 percent of the difference between the drywell ambient and reactor saturation (563 degrees Fahrenheit) temperatures.
Since the Yarway system reference leg operates below saturation, i.e., subcooled, the reactor pressure could decrease to less than 250 psig before affecting the Yarway reference leg.
The output from both the Bailey and Yarway level sensors is a differential pressure which is a direct function of the difference in height of the variable (reactor water level) and reference (constant) legs.
The 3ailey output is electronic and is converted to a pneumatic signal for use in the feedwater contrais; therefore, all of the reacouts for reactor water level (t-o incicators and one recorcer),
are decer. cent son an electrical as well as pneumatic supply.
The Yarways, which are comoletely electronic, are suoplied wita emergency pcwer for reliability and have two separate control room reactor water level reacouts.
1701 207
_ With respect to other instrumentation available to the operator, changes in reactor coolant inventory due to leaks would be detected by various autcmatically actuated signals and instrumentation.
There are only three places where primary system lines are routed; these are the reactor drywell, the refueling building and the pipe tunnel.
If a primary system leak occurred in the drywell, it would be detected by an increase in the containment (drywell) pressure and temperature.
The change in temperature would be detected by resistance temperature detectors whose readout is recorded in the control room and by thermocouples whose readout is indicated and alarmed in the control rocm.
The increase in pressure would be indicated and alarmed in the control room and would result in a reactor trip and isolation if it reached the twn psig setpoint.
A primary system leak would also be detected by an increase in the drywell sump level.
This sump is monitored by local instrumentation that is read each shift by the operator on his round.
If the level increases by 50 gallons, it initiates two independent control room level alarm annunciators and must be manually drair-d by the operator using a low level interlocked, " deadman" switch.
The frequency of sump draining is recorced and monitored by the cperators and the operating procedures require that plant management be notified (a) of any change in the rate of accumulation or (b) if the rate of accumulation exceeds 50 gallons per mon.h, i.e., one draining per month.
If primary system leakage were to occur in the refueling building or access shaf t, the steam released would be detected by one or all o' the following:
(1) one of the eight radiation monitors in the refueling building and access shaft due to the radioactivity la el increase, (2) by the moisture detector in the access shaft instrument vault and/or (3) by actuation of the refueling building high dif ferential pressure protection system which would isolate the isolation (emergency) c:ndenser and he cleanup system.
I,' :rimary system li.e :r valve leakage eere to occur in the pipe tunnel, it
.ou d :e notice: :y an increase in tre area radiation, as indicated and ala med by the pios turnel area radiation moni.or, and by an increase in :ne 1701 208 temperature as noted by the main steam line break sensors which would trip and isolate the reactor following an increase of 30 degrees acrenheit above normal ambient.
We conclude that the licensee's des:ription of the uses and types 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 actions dir"ted by the operating procedures and training instructions to ensure that:
a.
Operators do not override s
.omatic 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 actions, but to also examine other plant parameter indications in evalating plant conditions.
The licensee's response was evaluated to determine that (1) it addressed the matter of operators improperly overriding the automatic actions of engineered safety features, (2) it addressed providing operators with additional informa-tion and instructi0ns to not rely upon vessel level indication alone for manual actions anc (3) that the review included Operating procedures and training instructions.
The licensee, in its May 1, 1979 response, stated that it was formulating a guide to descrioe the general actions that are required during an emergency situation.
The licensee noted that these actions, which have heretofore been emchasized in its training program, concern (1) not overriding safety system automatic actions unless continued operation of the engineered safety feature will result in unsafe plant conditions and (2) tne use of all available and acclicable instrumentation as the basis for making c::erational decisions.
In accition to One above, training sessions ~ill be concuc.ed (witn 3::::ropriate cocumentation in plant records) to assure that all licensed
~
1701 209
__ supervisors and operators are thoroughly familiar with this review and this guidance.
The licensee also stated that operators have been instructed to utilize all available scurces of information in deciding to manually initiate safety systems.
We conclude that the licensee's review of operating procedures and training instructions satisfies the intent of IE Bulletin 79-08, Item 5.
6.
Review all safety-related va'1ve positions, positioning requirements and positive controls to assure that valves remain 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 reviewed for correctness, (2) safety-related valves will be verified to be in the correct position and (3) positive controls will be in existence to maintain proper valve position during normal operation as well as during surveillance testing and maintenance.
The licensee's response dated August 6, 1979 committed to a review of safety-related valve positions prior to startup.
The licensee also stated in its May 1, 1979 response that its startup, sealed valve and critical sensor checklists are designed to assure that all valves in safety-related systems are properly aligned following each major outage.
Any valves disturbed during subsequent operation would be noted en the " sealed valve check list changes" sheets.
In addition, an inoperable equipment leg is maintained for safety-related equipment.
Equipment olaced on this list must be functionally tested to demonstrate 0;erability prior to return to operational status.
These administrative c:ntrols would be applicaole whether the system was being remped from service for maintenance, testing or any other purpose.
By a te'eohone conversatica :n Septem:er 25, 1979, ne licensee ccmaitted to ccm:are all cnecklists and procecures witn : icing and instrumentation diagrams 1701 210
. to deter iine that valve position requirements are correct.
The licensee committed that this would be done before Humboldt Bay restart, and the item was reported by the licensee to have been added to the computer checklist of prestartup work.
We conclude that the licensee's review of and commitments with respect to safety-related valve positioning requirements, valve positions and positive controls to maintain pr:per valve positions satisfy the intent of IE Bulletin 79-08, Item 6.
7.
Review your operat'ng modes and procedures for all systems designed to transfer potential'y radioactive gases and liquids out of the primary containment to ass.re that undesired pumping, venting or other release of racioactive liquics and gases will not occur inadvertently.
In particular, ens.re that such an occurrence would not be caused by the resetting of enginsered safety features instrumentation.
List all such systems and indica e:
a.
Whether interlocks exist to prevent transfer when higr radiation indication exists, and b.
Whether such systems are isolated by the containment isolation signal.
c.
The basis on nich continued oparability of the above features is assured.
The licensee's response nas evaluated to determine that (1) it addressed all systems designed to tra sfer potentially radioactive gases and liquids out of primary containment, (2) inadvertent releases do not occur on resetting engineered safety featu es instrumentation, (3) it addressed the existence of interlocks, (4) the systems are isolated on the containment isolation signal, (5) tne casis for con-i ued operability of tne features was addressed and (6) a revisa of the proce:;res was perfo med.
In its u y 1, 1979 es= se, the licensee re:crted tnat operating modes and a
- Oce:_res for systems :ssi;ned : transfer potentially acicactive li uids anc gases out of tre Or' ar, containment system nac teen reviewed.
Licuic 1701 211
transfer systems (the lc*er drywell nead drain valves, the scram dump tank valves and certain su:pression chamber and core spray system piping systecs) require manual operat'or and are not normally in service during plant operation.
Operating pr0cedures are such that these system would remain isolated following an ir:ident in wrich liquids containing significant amourts of radioactivity are present in the :entainment system.
These same consideratiers apply to gaseous transfer systems with the exception of the emergency condenser vent separator, which continuously removes a small flow of steam and noncordensible gases from the emergency condenser tube bundle.
The emergenc;. c:ndelser vert separator normally discharges to the 250-foot stack.
The.er: li,e to the separator can be isolated remotely from the control room shou'd abno-mal racioactivity be detected by the stack monitoring system.
Tr.is vent systec could be a potential scurce of radio-activity if fuel fail _res were to occur.
The present operating procedures call for closure of tne tent if excessive radiation is detected in the stack.
Since closing the vent line :ould affect the long-term performar e of the emergency condenser due.o gas binding, the licensee is evaluating an alternate flow path for -he sent lire to the suppression chamber nitrogen space.
This alternate ':os Oath ac;.id be manually controlled from the control room upon isolation o' :9e n:r al veit cischarge to the stack.
If this modification proves t: :s desirable. it will be installed prior to startuo following resolution :f the geologic and seismi: issues.
In its August 6,1979 response, the licensee reported that resetting of the engineered safety featur-es instrucentation will not result in inadvertent transfer of radioacti.e ;ases and liquids outside of containment since none of the isolation or syster. talves, exce:t those listed below, change position automatically upon resening (by ei*.ner manual or autcmatic methods).
Scram Dump Tan < : t n 'ialve - hy reac'.or trip will close the drain i
a.
valve.
This val e :a- :: De re::e ed un'ess (1) ne rea::or trip signal resets anc (2) : e ::n ci re:. ::e at:r rancally resets One eactor safety system.
e se::rc ac ':r is :reve ted acminis.ratively unti' a 1701 212
. complete evaluation of the cause of the trip is conducted.
Once reset, the scram dump tank drains to the reactor equipment drain tank (REDT) which is located inside the refueling building (secondary containment).
Once released to tne REDT, the liquid could be automatically pumped to the radwaste facility which is outside secondary containment since the REDT pumps are aut:matically started by high REDT level.
An alternate flow path is not required because (1) manual action is required to cause the transfer and (2) if the transfer were initiated, the operator can shut down the REDT pum;s from the control room if excessive radioactivity is detected frem tie radiation monitors near the tank or located in the radwaste facility hicn indicate and alarm in the control room, b.
Suppression Pool Cooler Recirculation Valve - If operating in the recirculation mode, any automatic actuation of the core spray system would cause closure of the valve.
Manual resetting of the engineered safeguards initiation controls would cause the valve to return to the recirculation mode.
This action would only cause a recirciation of radioactive liquid fro:: the suppression chamber through the cooler and then back to the enamber so long as the core spray pumps contin..a to run.
c.
Suppression Chambe-Relief Line Isolation Valve - This valve closes wnen drywell pressure increases to two psig.
Once drywell pressure decays, the valve would re: pen.
This would not cause a transfer of radioactive gases because the vacuum relief valves would still be closed preventing a release to the refueling building.
In all cases, continued operability of the features designed to prevent inadvertent transfer of radioactive liquids or gases is assured by acministrative controls, viwal inspection during operator rounds, surveillance tests or some cce,bination of these methods.
as conclude tnat tre 'i:e sie's review of systems designed to transfer ra:io-active gases anc licuics :ut of Ori.ary containment to assure nat uncesirec pumoing, venting, or etner :alcase of radioactive licuics and gases vil not occur satisfies tne inten Of IE Eu'istin 79-03, Item 7.
1701 213 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 sa'ety-related system is removed from and returned to service.
The licensee's response was evaluated to determine that operability of redundant safety-relates systems is 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 r* moving the redundant equipment from service.
The response was also evaluated to assure provisions were adequate to verify operability of safety-related systems when tney are returned to service following maintenance or testing.
We also checked to see that all involved reactor operational personnel in the onccming shif t are explicitly nctified during shift turnover aoout the status of systems removed from or returned to service since their previous shift.
The licensee's response dated August 6,1979 stated that operability of redundant safety-relatec components or systems is presently verified by surveillance testing conducted at the time of redundant system removal.
If testing is not appropriate or is not deemed necessary, a visual inspection is conductec prior to clearance of the redundant component or system to assure c:erability of :ne reaining comocne, or system.
Tne Technical 5:ecifications and maintenance anc cerating precedures also require a ce cnstration cf acce:ts:le per'orma ce fcilcwi g any maintenance or test ng i
activity if tne func:icr Of :ne ccmcc ent cr system could have been i.pai ec. 1701 214 Procedures require that the shift reactor operational personnel not leave their posts until they rave provided the oncoming personnel with a full report on station conditions. This includes, as appropriate, (a) jobs or tests in progress, (b) bypassed cr jumpered features, (c) cleared equipment, (d) work planned for the upcoming shift and (e) any other unusual conditions.
In addition, the relieving personnel are not permitted to take over their watch until they are fully aware of plant conditions. To aid the shift foreman during watch turnover, a "shif t turnover sheet" has been provided to remind the oncoming shift forecan of the various routine review requirements.
It is also a convenient place for the offgoing shift foreman to note the status of special operations, i.e., completed, in progress or planned, which he feels are important enough to se reviewed by the next shif t foreman.
To assist the reactor operational personnel in determining the status of equipment, an inoperable equipment log and a tagging system are being used to insure that (1) the operability sta.us of all equipment and any pending action requirements are clearly understood, readily available to the shift operators and accurately transferred from shift to shif t, (2) prior to a r ange in operational condition, the required equipment is demonstrated to be operable by performing the surveillance requirements, and that once demonstrated operable, the equipment emains operable, and (3) equipment whicn becomes inoperable is properly smonstrated to be operatie after corr ^ctive actions are complete.
We conclude that the licensee's review and modification of maintenance, test and administrative procedures to assure the availability of safety-related systems and operational cersonnel knowledge of system status satisfies the intent of IE Bulletin 79-08, Item 8.
9.
Review your promet reporting procedures for NRC notification to assure that NRC is notified witnir one hour of :ne time tne reactor is not in a controlled or excectec c:ncition of coerati:n.
Further, at that time an open continuous : r::unication 9annel snall be establishec and maintained witn NRC.
1701 215 The licensee's response was evaluated to determine thet (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 continuous communication channel with the NRC following such events.
The licensee, in its May 1, 1579 response, reported that it reviewed the reporting procedures for NRC notification and will issue a supplement to the existing procedure which incorporates the one hcur notification and open centinuous communication channel recommendations of the bulletin.
By its letter dated August 6,1979, the licensee stated that the supplement to the existing reporting procedures for NRC notification will be revised prior to returning to pcwer operation.
The supplement will state that NRC notification is required within one nour of the time the reactor is not in a controlled or expected condition of operation.
We conclude that the licensee's response satisfies the intent of IE Bulletin 79-08, Item 9.
10.
Review operating m0 des and procedures to deal with significant amounts of hydrogen gas that ay :e generated during a transient or other accident that would either re ain inside the primary system or be released to the containment.
The licensee's response was evaluated to determine if it described the means or systems available to remcve hydrogen from the primary system as well as the treatment and control of nycrogen in the containment.
By a telephone conversa.icn on November 9, 1979, the licensee Confirmed that it reviewed its operating medes and procedures tnat address controlling significant amounts of nycr gen.
~ ne licensee state:: 19a
- u-ing ncrmal cperaticr, tne reactor p essure vessel come is fillec witn s.ea.
-ica ficws to the tur ine.
During reactor 1701.216
. isolation, the dome is autocatically vented through the safety valves to the suppression pool.
In addition, the reactor vessel head has a vent line with valves remotely operated fr m the control room.
In its response of April 14, 1979, the licensee stated that existing procedures and operating modes do not explicitly address the concern of significant amounts of hydregen gas that may be generated during a transient or other accident.
However, the containment system is designed for the partial pressure of hydrogen resulting frcm a significantly greater metal water reaction than is required by Appendix X of 10 CFR Part 50.
Both the drywell and suppression cha-ber are inerted with nitrogen so that the oxygen content is maintained at less than five percent.
This condition is verified during the containment purging operation just prior to returning the unit to servico and then is maintained by adding nitrogen to make up for any leakige 1 tus, thus further recucing the oxygen content.
Following the production of significant noncondensibles in the containment system, venting could be accomplished by remote actuation of valves which permit flow frr the containment to the gas treatment system.
We conclude that the licensee's response satisfies the intent of IE Bulletin 75-:3, Item 10.
11.
Propose cnanges, as recuired, to those technical specifications whicn 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 *o determine if any changes were reovired as a result of i plementing Items 1 though 10 of IE Bulletin 79-08.
Tne licensee reported ir its letter datec May 1,1979 that its review has sr -n that no changes to tne Technical Specifications are recuired.
e : rcluce that tne li:e see's res:ense satisfies tne intent of IE Bulle in 79-0S, Item 11.
1701 217
. Conclusion Based on our review of the information provided by the licensee to date, we conclude that the licensee has correctly interpreted IE Bulletin 79-08.
The actions taken and commitments made demonstrate the licensee's understanding of the concerns arising from the TMI-2 accident in reviewing their implementation on Humboldt Bay operations, and will provide added assurance for the protection of the public health and safety during the operation of Humboldt Bay.
Referencaj 1.
IE Bulietin 79-05, dated April 1, 1979.
2.
IE Bulletin 79-05A, dated April 5, 1979.
3.
IE Bulletin 79-08, dated April 14, 1979.
4.
PG&E letter, P. Crane to R. Engelkin, dated May 1, 1979.
5.
NRC staff letter, T. Ippolito to P. Crane, dated July 20, 1979.
6.
PG&E letter, P. Crane to T. Ippolito, dated August 6, 1979.
7.
PG&E letter, R. Peterson to Director, Division of Reactor Licensing, December 15, 1967.
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