IR 05000155/1985022
| ML20212B715 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 08/01/1986 |
| From: | Fresco A, Holmes J, Muffett J, Thomas H, Ulie J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20212B697 | List: |
| References | |
| 50-155-85-22, NUDOCS 8608070209 | |
| Download: ML20212B715 (35) | |
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s U.S. NUCLEAR REGUL/.IORY COMMISSION c
REGION III
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Report No. 50-155/85022 Docket No. 50-155 License No. DFR-06
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Licensee:
Consumers Power Company 212 West Michigan Avenue Jackson, MI 49201 Facility Name:
Big Rock Point Nuclear Plant Inspection At:
Charlevoix, MI Inspection Conducted:
December 9-13, 1985, March 5-7, 31, May 8, and July 18, 1986 bMM~h'
s 8/t fBG Inspectors:
A. Fresco (BNL)
P Date CA d. Holmes A.-ms+ L t 9%
D&t'e
.(m H. Thomas (BNL)
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Date J.
e Date axaa Approved By:
James W. Muffett, Chief 8/l[86 Flant Systems Section Date Inspection Summary Inspection on December 9-13, 1985 March 5-7, 31, May 8, and July 18, 1986 (Report No. 50-155/85022(DRS))
Areas Inspected:
Special, announced inspection by Region III based inspectors and their consultants to determine the adequacy of the facility's post fire safe shutdown methods, and a review of the licensee's routine fire protection program.
This inspection was conducted in accordance with Inspection Procedures 30703, 37700, 37701, 41700, 42700, 64704, and 72701.
8600070209 860801 PDR ADOCK 05000155 G
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Results: Of the thirteen areas inspected, no violations or deviations were identified in ten areas; three apparent violations were identified in three areas; failure to request an exemption from the requirements of Section III.G.2 for the Screenwell and Pump House - Paragraph 3; failure to take timely corrective action concerning emergency lighting system deficiencies -
Paragraph 7; and fire protection combustible control implementing procedures were not adherid to - Paragraph 8.
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DETAILS 1.
Persons Contacted Big Rock Point R. Abel, Manager Plant Performance and Production
- R. Alexander, Technical Engineer
- R. Barnhart, Senior Quality Assurance Consultant R. Buckner, Training Administrator T. Dugan, Property Protection Operations Supervisor
- D. Hoffman, Plant Superintendent L. Monshor, Quality Assurance Superintendent R. Schroder, Engineering Supervisor
- D. Swem, Senior Engineer W. Trubilowicz, Operations Supervisor J. Warner, Property Protection Supervisor
- G. Withrow, Engineering and Maintenance Superintendent Consumers Power E. Dorbeck, Senior Engineer R. Krich, Nuclear Licensing R. Smedley, Nuclear Licensing Nuclear Regulatory Commission
- J. W. Muffett, Chief, Plant Systems Section, RIII
- S. Guthrie, Big Rock Point Senior Resident Inspector
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- Denotes those persons present at the exit interview of July 18, 1986 The inspector also contacted other licensee personnel including members of the training, engineering, and operations departments.
2.
Action on Previous Inspection Findings a.
(Closed) Unresolved Item (155/82-13-05): On August 18, 1982, the inspectors observed sphere cable penetrations between the interior
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and exterior cable penetration areas that contain cabling necessary for safe shutdown of the plant which did not have any fire resistance qualification.
The licensee was unable to provide documentation to support these sphere cable penetration configurations or show NRC acceptance of the installed design.
The licensee provided the inspectors with a copy of Consumers Power Company transmittal letter to the Nuclear Regulatory Commission (NRC), dated July 14, 1978, which indicated that all sphere cable penetration openings are to be sealed to give protection at least equivalent to that required of the barrier in which they are located as shown in the letter's attached to the
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letter. The drawings did not indicate a fire resistance requirement of the sphere cable penetrations which protect the interior and exterior cable penetration areas.
Consequently, an NRC letter to Consumers Power Company dated November 20, 1978 accepted the licensee proposals as identified in the licensee's transmittal of July 14, 1978.
Further, during the Appendix R inspection it was determined that a fire scenario postulated on either side of the cable penetration areas (interior and exterior) which assumes a loss of cabling function on
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both sides, determined that the plant still has the capability to l
still safely shutdown.
Based on the above information, this item is considered resolved.
b.
(Closed) Noncompliance (155/82-13-06A):
Firefighter protective equipment such as protective clothing and respiratory protective equipment was not being utilized in the manner prescribed by the
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fire protection implementing procedures.
Specifically, the inspec-tors observed three fire brigade members with full facial beards participating in the annual fire brigade practice session.
These persons cannot be considered qualified fire brigade members because their facial hair invalidated their qualification for. the use of respiratory protection equipment.
Also, examination of the fire brigade training and medical records revealed that one fire brigade member did not have a respiratory fit test during the year of 1981 because he was wearing a full facial beard at the time the test was given.
By licensee's internal correspondence dated July 18, 1985 from R. DeWitt, D. Hoffman, and J. Firlit regarding a change in the Big Rock Point and Palisades Nuclear Operations Department (s) Facial Hair Policy.
This correspondence indicated that Consumers Power Company Nuclear Plant employees designated as members of the fire brigade and radiation protection support personnel are required to provide immediate response to fire emergency conditions and shall remain fully qualified to respond to emergencies. According to the internal correspondence, being fully qualified includes remaining clean shaven in the area of the respirator face piece seal at all times. The correspondence further indicated that any employee who violates this rule on or after August 5,1985 will be subject to disciplinary action, up to and including discharge.
Implementation of this policy also closes Inspection Report No. 155/82-12-02.
Regarding the firefighter protective clothing concerns, refer to Paragraoh 2.f of the inspection report.
c.
(Closed) Noncompliance (155/82-13-06B):
The NRC guidance document
" Nuclear Plant Fire Protection Functional Res onsibilities, Administrative Controls and Quality Assurance,p'. Attachment No states in part, " Administrative controls should.. require an in plant review of proposed work activities to identify potential transient fire loads.
The onsite staff member designated the responsibility for reviewing work activities for potential transient fire loads should specify the required additional fire protection in
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the work activity procedure. When the transient fire load causes the total fire load to exceed the capabilities of existing suppression systems and equipment additional portable suppression equipment should be brought in the area."
The licensee's transmittal of June 19, 1978, in response to NRC fire protection administrative guidelines indicates in Attachment No. 3,
"Contral of Combustibles", it is Consumers Power Company position that the first line supervisor for any specific task will make an assess-ment of the need for additional suppression equipment in any specific area based upon the transient fire loading of that area.
Further, that this assessment will be made as a portion of the applicable maintenance work order and not on a separate document.
It is felt that this adequately meets the intent of the guidelines.
Contrary to the above, no procedure for control of transient fire loading was in effect at the site.
The maintenance work orders did not include information assessing the total fire load for transient fire loads where additional suppression equipment may have been needed.
No such information was preprinted or added to complete maintenance work order form.
Section 8.0, Fire Prevention Activities of the Fire Protection Implementing Procedures for Big Rock does not address this aspect of control of combustibles, and no other evidence was available to indicate that first line supervisors were performing this task.
During the December 1985 inspection visit, the inspector was provided with Chapter 8 of the Fire Protection Implementing Procedures entitled,
" Fire Prevention Activities", which states, " Transient fire loads, such as combustible and flammable liquids or gases, wood and plastic products, or other combustible materials in areas at the plant containing safety-related systems or equipment shall be kept minimal at all times.
If the fire load is excessive and presents a possible hazard, the plant property protection supervisor or his designee shall be contacted to determine if additional fire protectioa and/or increased surveillance is needed."
In addition, the inspector was provided with Chapter 5 of the Administrative Procedures, Revision 30, dated May 10, 1985, which states, " Determine if work activity will require temporary storage of combustible or flammable materials in safety-related areas.
If this temporary storage is excessive as determined by the Maintenance Supervisor, or the Property Protection Supervisor, or his designee, additional precautions and/or surveillance should be taken." Based on the licensees actions, this item is considered closed.
d.
(Closed) Noncompliance (155/82-12-06c):
Section 2.b(3) of Attachment
No. 4 to NRC supplemental guidance document entitled, " Nuclear Plant
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Fire Protection Functional Responsibilities, Administrative Controls, i
and Quality Assurance" regarding administrative controls that should be instituted to protect safety-related equipment from fire damage as a result of work involving ignition sources such as cutting, welding, grinding, or open flame work indicates that a fire watch trained and j
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equipped to prevent and combat fires is present throughout any operation in which there is potential for fire that might damage safety-related equipment.
This paragraph references the National Fire Protection Association (NFPA) Pamphlet No. 51b.
NRC guidelines regarding cutting and welding processes are based on NFPA 51b entitled,
" Standard for Fire Prevention in Use of Cutting and Welding Processes."
Paragraph 431 of NFPA 51b requires fire watch personnel to have fire extinguishing equipment available and be trained in its use, including practice on test fires.
The licensee contends that their present ten minute slide presentation on fire protection is adequate to qualify an individual as a fire watch.
The inspectors concern relates specifically to off-site contractor personnel serving as fire watches who only receive the ten minute slide presentation with no accompanying practice on test fires.
At the exit meeting of July 18, 1986 the licensee committed to assure that contractor personnel assigned to the
" fire watch" receive adequate training.
This training will include
" hands on" practice on the use of fire extinguishers.
This commitment is sufficient to close this item.
e.
(Closed) Noncompliance (155/82-13-06d):
Fire fighting procedures at Big Rock Point do not address strategies for fighting fires in specific safety-related areas or specific areas presenting a hazard to safety-related equipment.
There are no written procedures developed for fire fighting tactics and strategies for individual safety-related areas which identify combustibles, fire extinguishants best suited for fire attack, most favorable direction of fire attack, access and egress routes involving locked doors, management of plant systems, vital heat sensitive components, radiological and toxic hazards or ventilation system operatio1.
For several areas in the plant the licensee provided the inspectors with pre-fire plans which satisfied this item's concern, however, the pre-fire plans lacked detail in describing items such as type of fire extingishant available (best suited for fire attack),
radiation hazards, type and location of vital equipment for safe shutdown located in the area.
Based on the inspector review, Open Item 82-13-06d has been closed, however, the above mentioned concerns are considered an Open Item (155/85022-01) pending licensee review of the pre-fire plans.
As guidance the NRC inspector suggested use of the NRC document entitled, " Nuclear Plant Fire Protection Functional Responsibilities, Administrative Controls and Quality Assurance."
f.
(Closed) Open Item (155/82-13-08):
During the inspection several of the licensee's administrative procedures for fire protection appeared to be vaguely or inadequately written and thus subject to common misinterpretations.
For example:
(1) Card No. 5 of Appendix A of the fire protection implementing procedures specifies emergency actions by the fire brigade leader.
Under this procedure, his immediate actions are to:
(a) Don a self contained breathing apparatus and bring the emergency caddy to the fire scene.
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__ (b) Direct the fire brigade in a proper attack of a fire and rescue operation.
(c) Maintain Communications with the control room.
(d) Request assistance of the offsite fire department whenever a fire is not extinguished immediately.
In several fire drills, including the plant annual fire drill conducted on August 27, 1981, implications of inadequacy in this procedure were exhibited.
The plant procedures for immediate actions of fire brigade leaders should more specifically address actions that will produce consistent desired results.
(2) Card No. 6 to Appendix "A" of the fire protection implementing procedures should be amended to include specific requirements for fire brigade members to respond to fire scenes with protective clothing and self contained breathing apparatus.
Procedures should be established addressing the strategy involved in attacking incipient fires, fully involved fires, fires involving radiological and toxic hazards, etc.
(3) Section 8.4.4 of the fire protection implementing procedures states in part, "A welding and cutting permit," May include more than one day but must be indicated." The loca ion, "Should be specific enough that the relieving shift supervisor can determine the area considered under the original inspection."
Work to be done, "should identify all forms of hot work covered by the permit." Special precautions," to be determined by shift supervisor.
The concern regarding this procedure is the fact that welding and cutting appears to be permitted for more than one day, in different areas of the plant by a single welding and cutting permit.
If a contractor has five different types of hot works to perform in five different areas of the plant within three days, only one welding permit is required.
In this case, it is not clear whether or not the supervisor reviews special precautions and assigns a fire watch after each form of hot work activity is completed, or if all forms of hot work activity to be done in all areas by a single contractor is approved at the same time the welding and cutting permit is issued.
In the latest revision of the maintenance order, the fire safeguards portion of the form was deleted.
The policy of stamping this
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portion on the form is not viewed as desirable. Therefore, it is
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suggested that the safeguard portion of the maintenance order be included in the preprinted Form No. 978 IOM / July, 81) as is suggested by the proposed revision.
On the balding and cutting permit, concerning the statement under follow up inspection, " Work area and all adjacent areas where sparks might have spread were inspected at least 30 minutes after each work period was completed
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and no fire conditions were noted." The inspector could not determine whether the fire watch returned to the areas where the work was conducted 30 minutes after the work was completed and no fire conditions were noted, or whether the fire watch was present at the scene during the work and remained there for at least 30 minutes after the operation had stopped to check for smoldering fires?
During the December 1985 inspection the inspector addressed the above concerns as listed below:
(1) The licensee provided the inspector with Card No. 5 (Revision 38, dated September 16,1985) of Appendix A of the Fire Protection Implementing Procedures which was updated to specifically address actions required of the fire brigade leader.
This portion of the item is considered closed.
(2) The concern regarding fire brigade members to respond to fire scenes with protective clothing is being renumbered as Open Item (155/85022-02). The concern related to firefighting strategies is being tracked as Open Item (155/85022-01).
(3) The licensee provided the inspector with App'endix G entitled,
" Welding and Cutting Permit for Contractors which indicates, date of work; location; work to be done; fire watch Inspection by (dates, start, finish) permit expiration, follow up insp'The ec-tions after the work is completed. The procedure states, fire watch must be present at the scene where the welding cutting, and open flame work or major grinding is in progress and must remain there for at least 30 minutes after the operation is stopped to check for smoldering fires." Based on the information provided, this item is considered closed.
g.
(Closed) Open Item (155/84-12-01):
Records of fit testing indicate that the licensee fit test Bio-Pack 60-P respirator users to a protection factor of only 500 using a high efficiency filter attached to the respirator face piece.
Apparently the licensee is unable to perform the fit test using the entire 60-P unit because introduction of the corn oil into the unit fouls the internals.
Because of this, the licensee is unable to show a protection factor of 5000 as required by 10 CFR 20, Appendix A, Note 1.
Recent guidance to Region III from the Office of Inspection and Enforcement suggests that this method of fit testing may be acceptable, and states that requiring a fit factor of 5000 in the negative pressure air purifying mode is too restrictive.
This approach to fit testing allows no credit for protection provided by the positive pressure inside the face piece generated by the device in its normal mode of operation.
Positive pressure inside the face piece can compensate for inward leakage of contaminants to some extent by ensuring air circulating through the device is leaked outward instead of leaking contaminants into the worker's breathing zone.
However, a poor fit which causes excessive outward leakage will result in rapid depletion of the small volume of oxygen carried in the device and a significant reduction in service life.
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The guidance recommended that a factor of 1000 be considered an acceptable fit when fit testing wearers of the Bio-Pak 60-P using only the face piece equipped with a high efficiency filter.
The licensee choose to eliminate the problem entirely by replacing the Bio-Pak 60-P's with open circuit self-contained breathing apparatus (SCBA) units.
The licensee's letter dated March 29, 1985, indicated that the Big Rock Point Plant was in the process of replacing the Bio-Pak SCBA with Scott Air-Paks for emergency respiratory protection.
Section 6.5.1 of the Fire Protection Implementing Procedures indicates that nine Bio-Paks are onsite for fire brigade use.
The inspector verified that nine Bio-Pak SCBA have been replaced with nine Scott Air-Paks.
The plant locations toured by the inspector having in place the SCBA included the control room (three SCBA units),
steam drum wall (one SCBA unit), fire depot No. 1 (two SCBA units),
fire depot No. 2 (two SCBA units), and access control (one SCBA unit).
These actions are acceptable to close this item.
3.
Post-Fire Safe Shutdown Capability a.
Systems Required for Safe Shutdown The inspectors examined the licensee's post-fire shutdown capability.
According to discussions with the licensee's staff and a review of documentation, the following systems are available for hot and cold shutdown including heat removal assuming a loss of off-site power:
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Reactor Protection and Trip System
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Emergency Condenser and Tube Side Outlet Valves Condensate Storage Tank and Control Rod Drive Pumps
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Demineralized Water Tank (Pump cannot be connected to EDG)
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Fire Water System
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Reactor Depressurization System (RDS)
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Core Spray Systems Post Incident Cooling System
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Reactor Cooling Water System and Heat Exchangers Shutdcwn Cooling Water System
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Service Water System
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AC Power from Emergency Diesel Generator
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DC Power from 125V Station Batteries Instrumentation for Hot and Cold Shutdown
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Of the above systems, the Reactor Depressurization, Core Spray and Post-Incident Cooling Systems are redundant to the Emergency Condenser, Condensate Storage Tank and Demineralized Water Tank for Hot Shutdown.
The Core Spray System water supply originates from the Fire System.
The Core Spray Pumps take suction only from suction strainers inside the Containment Sump, and are therefore used only during the Recirculation Mode.
The initial core spray is provided by the Fire Pumps.
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T Since under some fire scenarios the Fire Pumps may be used to provide make-up water to the Emergency Condenser shell side, the Fire Pumps play an unusually important role in achieving Hot Shutdown, particularly because they are not normally part of any reactor cooling systems at most other nuclear power plants.
Between the inspection visits performed during December 9-13, 1985, and May 5-7, 1986 the licensee prepared a document entitled, " Big Rock Point Plant Safe Shutdown Equipment - Appendix R," received during our inspection visit of March 5, 1986, which is intended to describe the safe shutdown equipment which could be rendered inoperable by a worst case fire in each area or zone and to describe other safe shutdown equipment located outside of that area or zone which could be operated to attain safe shutdown. This document was initiated during the December 9-13, 1985, inspection visit and references all of the systems identified above.
In addition, it references some systems which were not identified during the December,1985 inspection visit, such as the Standby Diesel Generator (SDG) and the " Feed and Bleed" method of achieving cold shutdown.
These systems will be discussed in more detail below.
(1) Reactivity Control Insertion of the control rods provides the required reactivity control.
This can be accomplished by depressing the scram button in the Control Room.
Loss of offsite power also causes the reactor to trip.
In the event that offsite power is not lost, the reactor can be tripped by throwing the breakers for the Control Rod Drive Pumps.
(2) Reactor Coolant Inventory Control When using the Emt gency Condenser, make-up for cooldown shrinkage and technical specification allowable leakage is provided by the Control Rod Drive Pumps which can be supplied from the Condensate Storage Tank.
The licensee has provided a calculation to'NRR to show that at a 25 F/hr cooldown rate, nine hours are available before makeup to the Reactor Coolant System is required.
In the event that the Control Rod Drive Pumps are unavailable, the plant can be cooled down within the nine hours and Shutdown Cooling System put into operation.
This would preclude the need to provide primary system pressure to allow use of low pressure make-up provided by the Fire System Pumps through the Core Spray i
valves.
The plant would remain in Hot Shutdown in this case.
When the Reactor Depressurization System is used (in the manual mode), inventory control is also provided by the Fire System Pumps through the Core Spray Valves until the Core Spray Pumps can be used in the Recirculation Mode.
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The basic methods of decay heat removal aside from the main
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condenser are the Emergency Condenser (EC) and the Reactor Depressurization System (RDS) which is coupled with the Fire
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_ ater System (FWS) and the Core Spray System (CSS).
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When using.the EC, at least one of the two tube side motor-operated isolation valves must be opened and throttled to allow and control
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flow of Reactor Coolant vapor through the EC.
The water on the shell-side of the EC is allowed to boil off and is discharged to atmosphere through a high stack.
The normal source of water is the DWS with the FWS as backup. The DWS capacity is 5,000 gallons. -The licensee could not respond with an analysis to show whether during the assumed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> that offsite power is not available that the 5,000 gallons is sufficient to provide shell side makeup to the EC to maintain Hot i
Shutdown conditions. The first approach stating that a fire truck
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would be brought onsite to fill up the DWS Tank was later retracted.
This scenario was not covered in the SER. This subject is further
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discussed-inParagraph3.b.(1).
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A second concern which arose during the procedure walkthrough is the
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amount.of time available to open the EC outlet valves after a reactor scram.
Although reactor scram.is the only operator action permitted
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form the Control Room without an exemption, as per Generic Letter 85-01, Enclosure 6, " Appendix R, Questions and Answers," Section 3.8.4
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i concerning Control Room Fire Considerations, the licensee's procedure assumes that the operator both scrams the reactor and opens the EC i
outlet valves from the Control Room.
The EC valves can also be opened 1 '
from the Alternate Shutdown Building which can be reached in about
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five minutes from the Control Room. The licensee's analysis did not consider the worst case spurious action which is actuation of one RDS
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valve.
Regardless of the spurious actuation, the analysis which was
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presented did not adequately demonstrate the time available before the.
Safety Relief Valves (SRVs) actuate assuming that the EC outlet valves remain closed.
Th-licensee's original contention was that there were three minutes available before the SRVs actuate.
Althoughinainter-nal memo, entitled, " Big Rock Point Time to SRV Analysis (Blanchard
j to Swem), dated March 7, 1986, the licensee generated a new calculation based on the information provided in the original analysis which showed that there were six to seven minutes to SRV actuation.
The time available at the time the SRVs opened to reach the RDS
actuation setpoint was stated as 1.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />, based on an internal memo of the SAI Corporation, concerning boil-off before RDS action.
This
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memo dated October 15, 1980, however, did not properly reference the
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origin of the values and whether they even applied to Big Rock Point.
While the team does not have sufficient evidence to believe that the results presented are technically incorrect, the apparent confusion i
and lack of documentation is of concern. When considering the lack of an analysis for spurious actuation of an RDS valve, the licensee has
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not adequately demonstrated the amount of time available to get to the
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Alternate Shutdown Building.
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Consequently during the NRC visit to the site on May 8, 1986 it was determined that the protection to prevent spurious actuation of the RDS valves simultaneously with fire damage to the control circuits
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for the core spray valves is considered to meet the minimum require-
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'ments of Appendix R,Section III.G.3.
However, the licensee is-
encouraged to analyze the safe shutdown methodology to ensure that, reactor vessel inventory can be maintained in.the event of a control
room fire, considering the possibility of.a stuck open relief valve
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or a spurious RDS actuation and the resulting consequences.
I A third issue concerned the possible stress corrosion attack of the EC tubes when fire water from Lake Michigan is used for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
This was identified in the NRC's Safe Shutdown Systems Report, Topic VII-3 i
under.the Systematic Evaluation Program (SEP) in May 1981.
Based on correspondence from the licensee dated March 30, 1982 and September 28, 1982, NRR appeared to have accepted the licensee's position as
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responded to the licensee by NRC letter, dated December 17, 1982 which accepted SEP Topic VII-3.
Although the NRC letter did not specifically
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mention the corrosion concerns or their satisfactory resolution, no further action is considered necessary by the inspectors.
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The inspectors noted that the May 13, 1981 SEP Report indicated that
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the shell side of the EC normally contains about 8,000 gallons of
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water which is sufficient to dissipate decay heat for four hours i
following reactor scram. An air-operated make-up valve from the DWS is automatically actuated on low level but fails closed on loss of air which is caused by loss of offsite power.
A backup flow supply is provided via a. local manu~al valve inside containment connected to the FWS.
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l The licensee has since upgraded the latter valve to a remotely operated solenoid valve which can be operated from the ASB.
This is an additional control capability which was not identified in the March 8, 1983 SER.
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The RDS is the redundant means of decay heat removal when both the main and the emergency condenser are unavailable.
The RDS~ valves are.
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l set for automatic actuation when the Reactor Low Level point is reached or they can be~ manually actuated from the Control Room. There are
four valves, each of which discharges into the Reactor Enclosure.
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pressure is reduced to the point at which the FWS pumps can provide
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l water to the Core Spray ring, the Core Spray nozzle and the heat i
exchanger.
There are two FWS pumps.
One is electric but is powered
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by the Emergency Diesel Generator while the other is diesel powered.
The RDS is not the preferred method of shutdown because it discharges primary coolant to the containment atmosphere and would require extensive cleanup.
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r (4) Instrumentation Provided at the Alternate Shutdown Building The minimum required instrumentation for control and monitoring of the reactor is provided at the Alternate Shutdown Building.
(a) EC outlet valves controls, (b) Main Steam Isolation Valve (MSIV) control, (c) Fire Water Make-up to EC valve control, (d) Reactor Pressure (Steam Drum) indication (e) Drum level indication, (f) EC Water Level indication.
(S) Hot Shutdown Support Systems Based on the additional information received during the March 5-7, 1986, inspection visit to maintain hot shutdown, the following support systems are required for either method of shutdown, i.e.,
use of the EC or use of the RDS/ Core Spray Systems, except as noted:
(a) Demineralized water system including air compressor and air-operated demineralizer flow isolation valve (for EC method only).
(b). Fire water system including core spray valves ar.d flow paths (RDS method only).
(c) Control rod drive pumps and condensate storage tank.
(e) AC power from the SDG (See Section 4.2.2).
(f) DC power from 125V station batteries.
(6) Cold Shutdown Based on additional information received during the March 5-7, 1986, inspection visit, to achieve cold shutdown, the following equipment is or may be required:
(a) Shutdown cooling water pumps and flowpaths.
(b) Reactor cooling water pumps and flowpaths.
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(c) Service water pumps and flowpaths.
(d) Control rod drive (CRD) pumps if PCS makeup is required.
The March 8, 1983 SER states that in the event that the shutdown cooling water pumps or the reactor cooling water pumps are destroyed by a fire, cold shutdown capability does exist through the feed and bleed method without repair being performed; however, use of this feed and bleed method is not preferred by the licensee.
The licensee provided two separate documents to justify the acceptability of the " feed and bleed" method of shutdown.
One is a calculation undated (CPCo analysis continuation sheet calculating the flow rate required to keep the average primary system temperature at 210 F versus time after shutdown for " Feed and Bleed") intended to show that the Emergency Condenser could be used to maintain the plant at some temperature near 212 F, for example 230 F and that after a time period of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, the decay heatratewillbelowenoughsothatonly50ggmisneededto bleed water off at 210 F while injecting at 60 F.
The other is a calculation (licensee letter dated November 14, 1974, "Concerning the BRP RDS) of the flow rate capacity of any one RDS valve, which is intended to show that the capacity is sufficient for the Fire System / Core Spray Pump flow rates.
Each fire pump is capable of 1200 GPM at 115 psia.
In the first calculation, information obtained from the licensee establishes that the decay heat generation rates are based on NED0-10625, Appendix C.
The calculation does not take into account the additional short-term flow rate required to lower the PCS temperature from approximately 230 F to a steady state bleed-off temeperature of 210 F.
The PCS temperature could also be lowered by temporarily isolating the bleed-off while continuing to inject cold water from the fire pumps.
With respect to the second calculation on the capacity of one RDS valve, the licensee merely provided the calculation by the valve manufacturer showing that each valve is capable of passing 144 lbm/sec of saturated steam at 1283 psia.
However, this flow rate converted to GPM at fire system pressures of 115 psia is 1116 GPM.
This exceeds the 400 GPM rated capacity at 85 psia of the Core Spray pumps (licensee letter dated August 15, 1974, concerning BRP RDS) and closely matches the 1200 GPM capacity of one fire pump.
Therefore, considering both calculations together, the " Feed and Bleed" method is an acceptable means of achieving Cold Shutdown to avoid dependency on repairs.
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It should be noted that it may not be advisable to use the control rod drive pumps in place of the fire pumps unless the discharge pressure can be throttled because of the possibility of raising the PCS pressure to the 1300 psia range while at a temperature of 230 F.
This may be beyond the acceptable cooldown limitations.
Based on the above, operating procedures for feed and bleed, procedures should be written and implemented accordingly.
Based on the acceptability of the " Feed and Bleed" method to achieve Cold Shutdown, the licensee does not depend on any repairs to arrive at Cold Shutdown conditions except to run cables, which are stored on site, between various pumps and motor control centers.
For fires inside containment, it could not be verified whether or not any components required for " Feed and Bleed" could be affected by the fire when that method is being relied upon to achieve Cold Shutdown.
This is discussed further in the inspection report.
For fires in the Screen House and in the Emergency Diesel Generator (EDG) Room, the Standby Diesel Generator (SDG) will be used to maintain Hot Shutdown.
During the prior inspections in December 1985 and March 1986, the licensee was hesitant to take credit for the SDG, which is located outside the fenced perimeter, because the fuel supply was not designed for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of onsite storage.
During a conference call held on May 8, 1986, between some of the meeting attendees and other members of NRR, the licensee was told that it would be acceptable to take credit for delivering additional fuel from off-site sources during the postulated 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> loss of off-site power.
b.
Area Compliance with Appendix R,Section III.G.2, Where Alternate Safe Shutdown is not Required During the December 9-13, 1985, inspection visit which identified several areas wnich were mentioned by the licensee as fire areas inside containment such as the control rod drive pump room, the reactor cooling water pump room, and the shutdowr cooling system pump room.
In the Safe Shutdown Equipment document provided during the March 5-7, 1986 inspection visit, these rooms were also described as fire areas located within the containment.
These zones should be re-analyzed to determine if they satisfy one of the separation criteria for cables, equipment, and associated non-safety circuits of redundant trains given in Appendix R,Section III.G.2 for non-inerted containments, 1.e., separation by a horizontal distance of more than 20 feet with no intervening combustibles or fire hazards, installation of fire detectors and an automatic fire suppression system in the fire area, or separation by a noncombustible radiant energy shield.
According to
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the licensee's April 14, 1986 letter, a comprehensive fire protection summary document will be submitted to the NRC before startup from the upcoming refueling outage (startup is currently planned for December,1986).
Two other areas which were inspected for compliance with Section III.G.2 of the Appendix R included the Screen House and Emergency Diesel Generator Room.
The results are as follows:
(1) Screen House During the December 9-13, 1985 inspection visit, it was noted that this area contains both Service Water System (SWS) Pumps and also both the motor-driven and diesel-driven fire water pumps.
Since the only physical barrier evident was a radiant energy shield next to the diesel-driven fire pump to separate it from the motor-driven fire pump to satisfy Appendix A guidelines, it was assumed that no Appendix R barriers were in place to satisfy's the separation criteria.
The licensee did not dispute the team assumption that a fire in the screen house could disable both the service water pumps and the fire water pumps.
Since the service water pumps are required for cold shutdown and the fire water pumps are required for.the RDS hot shutdown method as well as one of the means to provide shell side makeup to the EC for the EC hot shutdown method, the only remaining method of hot shutdown is to provide sufficient water from the DWS to the EC shell side sufficient for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> assumed loss of offsite power.
During the March 5-7, 1986, inspection visit, the licensee took
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the approach that there was more than 20 feet of separation with I
no intervening combustibles or fire hazards between the diesel-l driven fire pump and the SWS pumps.
Under the guidelines of
Appendix A, the NRC had' granted an exemption for the use of the
radiant energy shield as an alternative to the installation of an
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automatic fire suppression system. However, no exemption had been requested under the Appendix R requirements. The lack of an exemption request is discussed in detail below.
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(a) Lack of an Exemption Request
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As discussed in NRC letter (D. Ziemann to D. Bixel) dated November 20, 1978, Item P8 of Enclosure 2 presented the NRC staff position in protecting the redundant fire pumps and service water pumps in the screenwell and pump house from a fire at the diesel driven fire pump was to either provide a sheet metal shield which extends from the floor to a few feet above the diesel pump in the area between this and other pumps, or provide sprinkler system coverage to extinguish fires in the area of the diesel driven fire pump.
This fire protection feature was required by the NRC staff to satisfy a provision of Appendix A to NRC Branch Technical Position (BTP) 9.5-1.
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In licensee letter (D. Hoffman to D. Ziemann) dated December 8, 1978, responding to the NRC staff position (P8), the licensee committed to installing a sheet metal shield.
Subsequently, the NRC SER (D. Ziemann to D. Bixel)
dated April 4, 1979 formally accepted the installation of a sheet metal shield to be installed in the Screenwell and Pump House between the redundant fire pumps.
However, according to an NRC letter (D. Eisenhut to Big Rock Point) dated November 24, 1980 sent to Big Rock Point, indicating that the provisions of Appendix R that are applicable to the fire protection features of Big Rock Point are Sections III.G, Fire Protection of Safe Shutdown Capability; III.J, Emergency Lighting; and III.0, Oil Collection System (s) for the Reactor Coolant Pump (s).
Further stating that these three Sections are required to
be backfitted in their entirety by the new rule, regardless of whether or not alternatives to the specific requirements of these Sections have been previously approved by the NRC staff.
The letter also stated that the fire protection features of Big Rock Point must satisfy the specific
requirements of Sections III.G, J, and 0 of Appendix R, unless an exemption from the Appendix R requirements is approved by the Commission.
By licensee letters (B. Johnson to D. Crutchfield) dated March 19, 1981; (G. Withrow to D. Crutchfield) dated May 19, 1981; (T. Bordine to D. Crutchfield) dated February 25, 1982; and (D. VandeWalle to D. Crutchfield) dated July 9, 1982, the licensee acknowledged receipt of NRC Generic Letter 81-12, dated February 20, 1981, which requested information pertain-ing to the proposed modifications for compliance with the Fire Protection Rule (45 FR 76602, November 19,1980).
According to Generic Letter 81-12, Paragra3h 50.48(b) of 10 CFR Part 50, which became effective on February 17, 1981, requires all nuclear plants licensed to operate prior to January 1, 1979 to meet the requirements of Sections III.G, J, and 0 of Appendix R to 10 CFR 50 regardless of any previous approvals by the NRC for alternative design features for those items.
This Generic Letter also stated that this
would require each licensee to reassess all those areas of the plant to determine whether the requirements of Section III.G.2 of Appendix R are satisfied.
The Generic Letter further stated if the III.G.2 requirement are not met, the licensee must provide alternate shutdown capability in conformance with Section III.G.3 or request an exemption ifthereissomejustifiablebasis.
The Generic Letter 81-12 and the NRC letter dated November 24, 1980, clearly informed the licensee that Section III.G of Appendix R was required to be backfitted in its entirety by
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the new rule regardless of whether or not alternatives to the specific requirements of this Section had been previously approved by the NRC staff.
However, the licensee failed to request an exemption from the requirements of III.G.2 of Appendix R after determining that the fire protection features in the Screenwell and Pump House did not meet the specific requirements of III.G.2 in that no fire suppression system was installed.
This is considered a violation (155/85022-03) of Paragraph 50.48(b)
of 10 CFR Part 50.
Until resolution of this issue is achieved, the licensee has indicated that plant operations personnel tour this area every two hours, while security personnel now tour this area every four hours.
On May 8, 1986, an inspector performed a review of licensee records verifying such tours are being conducted.
Discussions with the licensee's staff indicate that a conscious decision was made by the licensee knowing that no fire suppression system existed in the Screenwell and Pump House, not to submit, an exemption request, based on the correspondence between the licensee and the NRC, specifically NRC letters dated November 20, 1978, and April 4, 1979 (SER),
and the licensee's letter dated December 8, 1978.
One additional concern regarding the adequacy of other fire protection / safe shutdown systems in the Screen House.
The acceptability of the fire protection measures in the Screen House are currently under review by NRR, i.e., the i
radiant energy shield between the diesel and electric fire
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pumps as an alternative to a fixed suppression system.
On May 8, 1986, the inspectors again inspected the Screen House accompanied by NRR representatives.
NRR personnel raised a concern over the effectiveness of the smoke detectors in this area.
i Another issue such as the effect of a fire on the craveling screens and the Screen Wash Pump was resolved by having licensee personnel physically demonstrate that a traveling screen can be rotated manually.
Without the Screen Wash Pump, cleaning of the screens could be accomplished by hosing.
The licensee also attempted to show that plugging had only occurred twice during the life of the plant and was only partial (licensee internal letter dated March 21 1986, BRP traveling screens).
Therefore, this issue and the issue of the Demineralized Water Pump located in the Screen House, which is actually a transfer pump which would not be required for any of the
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shutdown scenarios, were resolved.
However, the overall issue of the acceptability of the fire protection measures
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within the Screen House remains open.
According to the May 8, 1986 meeting, this issue will be pursued by NRR and
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the licensee.
(2) Emergency Diesel Generator Room During the December, 1985-inspection, the licensee intentionally did not identify the Standby Diesel Generator (SDG) as part of the equipment required for safe shutdown in the event of a fire in the EDG room.
Instead, to achieve hot shutdown, the diesel-driven fire pump was proposed to be used to provide makeup to the EC shell. side and also to the PCS by means of the DC powered core spray valves in conjunction with the DC powered RDS.
However, cold shutdown cannot be achieved within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> unless
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the shutdown cooling water pumps receive power either from the j
SDG, offsite power sources, or the EDG which would have been i
repaired within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
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Based on the May 8, 1986 telephone conference call with NRR and I
attendees at the meeting, NRR presonnel stated that the licensee can take credit for use of the Standby Diesel Generator if additional fuel can be delivered from off-site sources within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
The licensee confirmed having such available resources.
Therefore, this issue is resolved.
All of the above can be powered by the Emergency Diesel Generator and a 125V DC battery source.
However, one pump in both the Shutdown and Reactor Cooling Water Systems requires the connection of a temporary cable between the pump motor and newly installed power feeders inside the containment.
Connection of the Service Water pump requires a temporary cable between the Emergency Diesel Generator Room and the adjoining Screen House.
These
" temporary" cables are installed with disconnect switches, and their operation is addressed in appropriate procedures.
4.
Procedures / Alternative Shutdown Building Facilities a.
Areas Where Alternative Safe Shutdown-is Required in Accordance with Appendix R,Section III.G.3 A fire in the following areas requires the use of the Alternative Shutdown Building facilities:
Control Room
Exterior Cable Penetration Area
Containment Interior Electrical Penetration Area Condensate Pump Room
Electrical Equipment Room
Turbine Generator Room
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The licensee has obtained certain exemptions from the requirements for-
' fixed fire detection and suppression of Appendix R,Section III.G.3 for
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the Turbine Generator and Condensate Pump Rooms.
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There are three procedures which are utilized to achieve safe shutdown
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- from the Alternative Shutdown Building (ASB).
Emergency Operating
Procedure EMP 3.10 is the primary procedure which references portions of System Operating Procedure 50P 5 for the Reactor Shutdown System and 50P 28 for Station Power.
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The scope of.the review was to ascertain that the shutdown could be
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- attained in a safe and orderly manner, to determine the level of difficulty involved in operating equipment, and to verify that~there
'was no dependence on repairs to-achieve Hot Shutdown.
A repair
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. includes installing electrical or pneumatic jumpers, wires or fuses to perform an action required for Hot Shutdown.
The licensee had requested and received an exemption request to
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provide a jumper cable to operate the Control Rod Drive Pump No. 1.
within nine hours of reactor trip during the Hot Shutdown period.
During the inspection, the license demonstrated that a permanent underground cable has been installed between the EDG Building and a power distribution box at the Equipment Lock to the Containment Building, and that a transfer switch to isolate the pump from the
Control Room has been installed in the ASB to allow operation of the pump from the Equipment Lock.
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No problems were noted concerning S0P 5 and 50P 28.
However, a
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deficiency was identified in EMP 3.10 concerning the immediate operator actions when Control Room evacuation is required due to a fire.
The procedure indicates two immediate operator actions to be
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(1) Scram the-reactor, (2) Crack open the EC outlet valves.
i The ASB is within approximately a two minute walking distance from i
the Control Room.
Although the EC outlet valves can be opened from
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the ASB, the procedure'did not identify this action to be performed
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L immediately upon assuming control at the ASB.
Revision 132 of
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EMP 3.10, dated December 16, 1985 clarified-that the operator should
j immediately transfer control of the valves to the ASB and verify that
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the EC is in service, thereby, satisfying the inspector's concern.
i Directly concerning this issue is that Generic Letter 86-10, Control
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Room fire considerations indicating that the only manual action usually credited in the Control Room is the reactor trip and that any additional Control Room actions deemed necessary would have to be justified under the exemption process.
The licensee was requested
i to determine how much time is available before the RDS valves or Steam Drum safety valves begin to open, and what is the effect on safe il i
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. shutdown capability.
The licensee provided a new calculation in the form of an internal memorandum dated March 17, 1986 (licensee internal memo dated March 17, 1986, BRP Appendix R Audit Analyses) which is intended to show:
(1) the time required for heatup from normal operating pressure (1250 psia) to the relief valve setpoint (1550 psia) and (2) the time required to boil off the water above the top of active fuel.
This calculation could not be reviewed at the plant site due to time constraints.
It should be noted that the licensee's assumptions are conservative at the outset, except as noted:
(1) Loss of offsite power occurs at time zero.
(2) Reactor trip is assumed at time zero (non-conservative).
(3) Reactor power before trip is 240 MWt, the maximum allowable.
(4) Main steam isolation valve closes at time zero.
(5) Emergency condenser is not operable.
The licensee's results indicate that for Item 1, there are six (6)
minutes available before reaching the safety valve setpoint and that for Item 2, in 1.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> the water above the top of active fuel will boil off.
Under the assumption that the Primary Coolant System volumes given the licensee's Appendix R Audit Analyses memo are correct and that lifting of a safety relief valve is acceptable, there appears to be no problem for the licensee to reach the Alternative Shutdown Building to open the Emergency Cdndenser outlet valves to place the EC in operation given that a Control Room fire has prevented opening of the outlet valves.
In addition, during telephone conversations with the licensee, which took place on December 19 and 23, 1985, the inspectors expressed concern with regard to the availability of direct readings of reactor level at all times during the alternative safe shutdown process There is recognition in EMP 3.10, Step 3.10.5.3(f), that level indica-tion in the steam drum may not always exist but no method was provided by which the operator could ascertain reactor level at that time.
The
licensee has incorporated an addition step into Procedure 3.10, thereby, resolving the inspectors' concern.
c.
Remote Shutdown Capability As stated in Paragraph 4.b, the licensee has available an Alternative Shutdown Building (ASB) from which the minimum required safe shutdown components can be controlled.
The following safe shutdown components
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are controlled from the ASB.
Emergency Condenser Outlet Valve, M07053,
Emergency Condenser Outlet Valve, M07063,
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J Main Steam Isolation Valve, M07050,
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Emergency Condenser Makeup Valve, SV4947 from the Fire Water System.
The control circuits for these components are effectively isolated i
from the Control Room.
It should be noted, as previously discussed
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in Paragraph 3.a.(3) that the Fire Water Makeup Valve SV4947 is an
upgrade which was not discussed in the March 8, 1983 SER.
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The Station Emergency Diesel Generator (DG11) will be used for the
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Alternative Safe Shutdown System onsite power source.
A Transfer L
Switch (TS-1401) was installed in the Emergency Diesel Generator (DG11) room to effect the transfer of emergency diesel generator
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power from the normal Class IE buses to the Alternative Safe
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i Shutdown System.
480V AC Emergency Power is transmitted through a Disconnect Switch (DISC.1441) to a Power Disti bution Box (TB 334)
and then to another transfer switch (TRS-1442) for Control Rod Drive
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Pump No. 2, both of which are located just outside the Equipment
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Lock, i
The 125V DC power that is needed for the the operation of the
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Emergency Condenser Outlet, Main Steam Isolation and Emergency j
Condenser Makeup Valves, the instrumentation and indicating lights-i is obtained from a 60 cell Station Battery located in the ASB.
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The licensee was asked to provide the sizing calculations and test results for this station battery.
A check of the load profile, j
battery sizing calculations, and battery performance test data indicated that adequate battery capacity exists to support operation
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of the DC equipment for the required duration following a postulated i
fire concurrent with a loss of offsite power.
The test was conducted for eight hours to simulate the actual loading I
conditions as per the IEEE-1978 requirements although it is capable of
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72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> operation as required by Appendix R.
The test was also conducted to justify the basis for the September 30, 1985 submittal to the NRC of the licensee's draft technical specifications which add the
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i Alternate Shutdown Battery to the Emergency Power Sources.
The draft
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technical specifications have not yet been formally reviewed by hRR.
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The cabling for the entire system is routed in conduits which are run L
separately from the normal Class IE circuits and do not pass through
any common fire areas.
The instrumentation is independent of the Control Room, Cable Spreading Room, Electrical Room, Exterior Cable
l Penetration Area and Turbine Generator Building.
The 125V DC Control Power for the Emergency Diesel Generator (DG 11) is supplied through
j a circuit breaker which is considered to be an isolation device.
j The capability to monitor the following parameters has been provided
in the ASB.
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Steam Drum Level, LI-3188.
Steam Drum Pressure, PI-188.
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Indicating lights are used to monitor the Emergency Condenser Level and the Fire Water Makeup to the Emergency Condenser.
5.
Protection for Associated Circuits Three issues concerning various associated circuits were identified.
These are the common bus concern, spurious signal concern and the common enclosure concern.
Each of these are addressed as follows:
Common Bus Concern Spurious Signal Concern
Common Enclosure Concern a. ' Common Bus The common bus associated circuit concern is found in circuits, either safety related or nonsafety-related, where there is a common power source with shutdown equipment and the power source is not electrically protected from the circuit of concern.
In order to audit for this concern at Big Rock Point I, a sample selection of circuits was checked.
The following are examples of the components that are fed or controlled by circuits that were reviewed during the inspection.
Main Alternate Shutdown Fused Disconnect Switch DISC-1441,
480V AC Distribution Panel Main Disconnect Switch - DISC-1442,2,
Fuse - LPS-RK70 CRD No. 1 Pump,
125V DC Battery Fused Disconnect Switch DISC-1612,
125V DC Circuit Breaker.
72-2011 72-2012 72-2013 72-2014 All of the above devices are part of the Alternative Safe Shutdown Electric Distribution System and were found to have satisfactory coordination.
The coordination for the Class IE 480 volt 3 phase buses was reviewed and it was determined that the circuit breakers which were installed in the Motor Control Centers 1A, 2A, and 2B were older vintage 480 volt molded case breakers which are very difficult to coordinate.
As a result of the review it was determined that a fire which damaged the Alternative Safe Shutdown System Cables could cause short circuits to the cables which service the Control Rod Drive Pump No. 1 and subse-quently open the Emergency Diesel Generator Feeder Breaker JL400.
Control Rod Drive Pump No. 2 would be available after Bus 1A is stripped, Feeder Breaker JL400 is reclosed, and the Breaker JT300 is closed to energize Bus 2A.
Bus 2A, is independent of the cable routing for the Alternative Safe Shutdown System.
This resolution is satisfactory since one redundant train will be available during the fire to provide makeup to the reactor vessel.
All new circuits are checked for proper coordination since this is now possible with the present state of the art 480V molded case circuit breakers.
A third of the relay settings are checked annually in accordance with data which is provided by the Consumer's Power Electrical Group.
The Common Bus concern was satisfactorily addressed.
b.
Spurious Signals The spurious signals associated circuit concern is made up of two items:
The false water, control, and instrument readings such as
occurred at the 1975 Brown's Ferry Fire.
These could be caused by fire-initiated grounds, shorts or open circuits.
Spurious operations of safety-related or nonsafety-related
components that would adversely affect shutdown capability (e.g., RHR/RCS isolation valves).
(1) Current Transformer Secondaries Fire caused damage to current transformer secondaries was not an issue at Big Rock Point I because the normal IE Bus 2B is completely isolatable from the Emergency Diesel Generator along with instrumentation associated with the bus.
(2) High Low Pressure Interfaces The licensee identified a number of high low pressure interfaces all of which, with one exception were inherently protected by check valves in series with motor operated valves or air operated valves with manually operated hand switches.
The exceptions were the shutdown heat exchanger primary inlet valves M07056 M07057, M07059whichwereoperatedclosedandtheappropriatecIrcuit breakers 52-2P4 and 52-2P6 were kept open.
(3) Isolation of Other Fire instigated Spurious Signals The licensee determined that the potential existed for spurious signal actuation of a number of components.
Some of the components and the resolutions to the spurious were as follows:
System Component Resolution CRD Supply CV4090 Disable linkage from air operator Main Steam Drain M07065 Disabled closed Emergency Condenser M07062 Disabled closed Inlet Valves M07052 Reroute cable for coil actuation CRD Booster Pump PPP57 Provide and alternate power source RDS CV4180 SV498 Analysis was incomplete.
The CV4181 SV4985 licensee will analyze to determine CV4182 SV4986 the effects due to damage caused by CV4183 SV4987 a control room fire.
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The inspectors had the concern that should a multiple short circuit occur in the control circuitry for the RDS, that an
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uncontrolled blow down of PCS cooling fluid would develope.
The licensee, at the March 8, 1986 meeting, stated that a minimum of two shorts plus open circuits are required in order to actuate one RDS valve.
The actuating pushbuttons for each RDS valve are located in the same panel within inches of each other.and would have to experience identical failures when subjected to the same fire.
It is worth noting that damage to the pushbuttons could initiate both the required shorts and opens to activate the RDS
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valves. This type of occurrence was not considered by the licensee to be credible.
The most recent NRC position supports the opinion that multiple short circuits need only be considered in the case of high-low pressure interfaces.
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The licensees resolution meets the NRC criteria regarding the
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multiple short circuit actuation of devices and components.
The
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licensee proposed to manually operate the core spray valves, i
which are located in containment, in the event of fire caused i
damage to their control circuits.
The team was of the opinion i
that this operation would be required to provide makeup to the PCS and,.therefore, some means should be'provided, external to containment, to operate the core spray valves because an actuation of the RDS is not absolutely impossible.
The spurious signal concern has been addressed in an acceptable
j manner by the licensee.
t c.
Common Enclosure
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The common enclosure circuit concern is found when redundant circuits are routed together in a raceway or enclosure and they are not electrically protected or in a configuration such that fire can t
destroy both circuits due to inadequate fire protection.
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The minimum redundant systems at Big Rock Point I'are the Normal i
Class IE. Systems and the Alternative Safe Shutdown System. The cables for these systems are run separately and do not go through the same fire areas with the exception of containment (Fire Area 6). In
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containment, the cables for the Reactor Depressurization System (RDS)
and the Emergency Condenser, Inlet and Outlet Valves located on the south face of Steam Drum Enclosure wall, have a separation which is
less than 20 feet and no fire rated barrier is installed.
The licensee i
requested an exemption from the installation of radiant energy shields
by letter dated June 1, 1984.
By NRC letter dated March 27, 1985, the
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exemption request was granted.
The common enclosure concern for cables relating to the RDS and the Emergency Condenser which are installed in the Control Room / Cable Spreading Room has been adequately resolved by the existence of the Alternative Safe Shutdown System.
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The Common Bus concern has been addressed satisfactorily by the licensee.
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6.
Communications
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The only means relied upon for communication when-implementing Emergency Procedure EMP 3.10, which concerns a fire in the areas requiring alternative shutdown,:is the two-way portable radio system.
During the procedure walkdown, test of the system between the Control Room and the ASB, proved satisfactory.
The licensee stated that communication between the ASB and
the Containment, which is a steel sphere, is poor but there are no local
actions to achieve Hot Shutdown requiring Containment entry under the
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failure assumptions required by Appendix R.
i 7.
I The inspector examined the plant emergency lighting system relative to 10 CFR 50, Appendix R, Section III.J. 10 CFR 50, Appendix R, Section III.J
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requires that emergency lighting units with at least an eight hour battery
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power supply shall be provided in all areas as needed for operation of safe shutdown equipment and in access and egress routes to those areas.
a.
Eight Hour Discharge Test On December 11 and 12, 1985, at the request of the inspectors a full discharge test was performed on four emergency lighting units to
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i determine the operability of the units in their installed condition.
i The following four lighting units were those chosen during the
inspectors' plant tours:
(1) Plant Lighting Unit No. 2, located in the Screenwell and Pump House Generator Room (EL.589'-0"), this unit j
continued to light after eight hours; (2) Plant Lighting" Unit No. 4, located south of Reactor Feedwater Pump No. 2 (EL.616'-0 ), this units'
-lamps went completely out at approximately seven hours; (3) Plant
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Lighting Unit No. 5 located along Stairway No. 8 near the containment personnel lock (EL.616'-0"), this unit continued to light after eight hours;and(4)PlantLightingUnitNo.27,locatedalongStairway i-No. 9, North Wall (EL.593'-0 ), this units' lamps went completely out l-at approximately six hours.
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In summary, two of four emergency lighting units failed the eight hour discharge test.
The licensee provided the inspectors with Deviation Report i
No. D-QG-84-83, dated August 16, 1984, which identified two emergency lighting units that failed to meet the eight hour requirement.
The
licensee had been issued a citation in December, 1982 for not having
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L in place a testing program for emergency lighting units.
This
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deviation repurt was written the first time the lighting units had an
extensive surveillance test performed on them.
Consequently, it could
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not be determined that the licensee met Section III.J as described in
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licensee letter dated July 9, 1982. Subsequently, additional random testing of other emergency lighting units (approximately ten of thirty-one units) also failed to meet the eight hour requirement.
Additionally, emergency lighting unit failures were also identified at Palisades Nuclear Station which were using the same type of units (Exide Model FSS).
As a result of the licensee's investigation which indicated inherent problems with the Model FSS circuit boards, the licensee determined to replace the FSS Model with an Exide Model F100 unit.
The Big Rock Point Plant purchased sixty-six (66) of the Model F100 units.
However, most recently (December, 1985) similar problems with the F100 Model were identified at Palisades.
By letter dated April 14, 1986, current licensee permanent corrective action entails a modification to add an additional battery of the same amphere-hour capacity (as is now installed) in parallel to the existing battery.
This modification is scheduled to be completed by September 1, 1986.
In reviewing the information regarding the emergency lighting unit problems, the inspector noted that licensee action had been taken to correct the deficiencies, however, untimely and at present not completed corrective action has been taken by the licensee to resolve this problem.
This item is considered a violation (155/85022-04) of 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," which is applicable to the fire protection Quality Assurance Program.
During the May 8, 1986, inspection visit, an inspector verified that portable hand-held type battery powered lanterns are available for plant operator use in the control room as an interim compensatory measure until long term resolution is accomplished.
As mentioned above, according to the licensee's April 14, 1986 transmittal, this modification will be completed by September 1, 1986.
b.
Installation of Emergency Lighting Units By licensee letter (B. Johnson to D. Crutchfield) dated March 19, 1981, Consumers Power Company stated that the portions of Appendix R which are applicable to the Big Rock Point Plant include Section III.J, Emergency Lighting.
Further stating that Consumers Power Company intent was to complete those modifications for Section III.J as prescribed in 10 CFR 50.48 (to be completed by November 17,1981).
By licensee letter (D. VandeWalle to D. Crutchfield) dated July 9, 1982, Consumers Power Company stated that the requirements of Section III.J has been completed as committed to by licensee letter dated March 19, 1981.
The inspectors examined the licensee's compliance with Section III.J of Appendix R to 10 CFR 50 which requires that emergency lighting units with at least an eight (8) hour battery power supply shall be provided in all areas needed for operation of safe shutdown equipment and in access and egress routes to those areas.
(1) As discussed in Paragraphs 3, 4, and 5 of the inspection report, in the event of a fire in any one of the following six areas:
the control room; the electrical equipment room; the exterior
cable penetration room; the containment electrical penetration area; the condensate pump room; or the turbine generator room the alternate shutdown system may have to be utilized, thereby requiring an individual (s) to walk outside in the yard area to the Alternate Shutdown Building (ASB).
In addition, an individual (s) may be required to perform actions in the Emergency Diesel Generator (EDG) Building also located outside in the yard area.
Plant Emergency Procedure EMP 3.10, Revision 130, dated December 6, 1985, regards the proceduralizing of the Alternate Shutdown System which includes actions necessary to safely shutdown the plant in the event of a major fire that affects the Main Condenser /Feedwater Systems or the RDS/ Core Spray Systems.
This procedure directs individuals to perform actions in the ASB and EDG Building.
During a walkthrough of EMP 3.10, the inspectors observed that no fixed eight hour emergency lighting battery powered units were installed outside in the yard area.
However, the operators required to perform these actions are required to have in their possessien an operational flash light which would be sufficient to allow them to perform their functions.
The licensee has submitted an exemption request for the outside yard lighting to NRR.
The licensee has committed to comply with the results of the NRR review of the exemption request.
(2) According to the licensee's Safe Shutdown equipment document based on a postulated fire in the Emergency Diesel Generator Room that involves both redundant fire water pumps, the use of the Standby Diesel Generator located outside the protected area may be required to provide essential electrical power for safe shutdown.
An inspection team member performed a walkthrough of the outside route to be used by the operator as procedurally required to be sent co manually start the Standby Diesel Generator. The inspector did not observe any eight hour emergency lighting battery powered
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units or other identifiable installed eight hour emergency lighting system along the access route or inside of the trailer where the Standby Diesel Generator is installed. The licensee's staff concurred with the inspector observations.
However, the operators required to perform these actions are required to have in their possession an operational flash light which would be sufficient to allow them to perform their functions.
The licensee has submitted an exemption request for this lighting to NRR for review.
Exemption For the Oil Collection System Section III.0 of Appendix R to 10 CFR Part 50 requires that the reactor coolant pump be equipped with an oil collection system if
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Section III.0 specifies that'the oil collection system shall be so designed, engineered, and installed, the failure will not lead to
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fire during normal or design basis accidents and that there is
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reasonable assurance that the system will withstand the Safe Shutdown l
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In the letter dated February 9, 1982, from T. Bordine,'CPC, to D. Crutchfield, NRC, the licensee requested an exemption from 10 CFR 5').48 Appendix R,Section III.0.
The licensee indicates in this letter that calculations of the June 15, 1979 submittal to the
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NRC demonstrated that a recirculation pump oil fire will not affect i
the operation of safe shutdown equipment located in this area. The analysis assumed that the fire consumed all of the oil in one pump j.
with the~only means of heat removal being the ventilation system.
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In the letter dated April 5, 1982 from H. Denton, NRC, to
D. VandeWalle, CPC, the exemption states in part "The licensee has l
also calculated the effects of an uncontrolled fire in the area
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This calculation is-based upon a spill from one pump, consisting of -
31.75 gallons of lube oil with a heat of combustion of 20,400 BTV's/lb.
Assuming totally efficient combustion and only heat loss being through
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the room ventilation system, the licensee estimates a temperature rise
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of 163*F."
l The April 5, 1982 letter indicates the licensee estimate assumes that the sprinklers would not operate; if the sprinklers operated properly as expected the temperature rise would be negligible.
The inspector
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reviewed the calculations provided in the February 9, 1982 letter and
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observed that the licensee calculations indicates that of a total heat content of 4,313,784 Btu would be produced by the lube oil fire, and that 313,664 BTU / min (or 8018 lbs of air X 39.12 BTU /lb) will be
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absorbed by the room air.
The licensee's conclusion that 313,664 BTU / min can be removed from the room by the ventilation system was
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found to be incorrect.
Therefore, the temperature will not stabilize at 163*F about ambient temperature as described in the licensee's
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analysis but will rise to a much higher temperature.
In addition, the licensee analysis takes credit for the use of the ventilation system
l to remove heat from the recirculation pump room.
The inspector i
disagrees with this position because the ventilation system should be j
deenergized at the time of the fire to reduce the intensity of the fire and the amount of oxygen fed to the fire.
In addition, the
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ventilation system may be damaged and become incperable due to the fire.
l The licensee's analysis did not appear to consider the affects of
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localized heat transfer on vital equipment.
The analysis did not
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demonstrate that a lube oil fire would be contained and would not j
affect safe shutdown equipment or involve the other recirculating pump lube oil supply.
It is not clear that the licensee has provided
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the NRC with accurate information that led the NRC to conclude that
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k the licensee's exemption request should be granted.
This is
. considered an Open Item (155/85022-05) pending resolution from NRR.
Until resolution of this issue is achieved, the licensee has issued
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an Operations Memo to Plant Operators emphasizing the importance of activating the Recirculation Pump Room sprinklers upon receipt of a fire alarm in that room.
An on going re-review of the temperature
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-rise in this room is being performed by the licensee and as discussed in the licensee's April 14, 1986, transmittal, if any corrective
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j-action is necessary.
8.
Control of Combustibles
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The inspectors performed a plant tour of the Big Rock Point Plant facilities verifying the plants conformance to the applicable sections of 10 CFR 50, t
Appendix R, and the remaining fire protection program features as described in the plant's operating license and associated documents.
During the inspectors tour of the Turbine Deck the inspectors observed l
fourteendrumseachcontaining215poundsofmIxedbedionexchangeresin
located directly beneath cabling needed for the Alternate Shutdown Panel
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(safety-related).
In addition, three 55 gallon drums containing oil were i
located nearby which if spilled would pose the possibility of igniting the
. drums of resin and/or an exposure fire hazard potential to damage the Alternate Shutdown Panel cabling.
This lack of control of combustibles is j
considered a violation (155/05022-06) of Section 6.8.1 of Technical
Specifications.
Discussions held between the Senior Resident Inspector
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(SRI) and the lead inspector regarding the licensee's control of combustible program indicated that the licensee's past history of controlling and
enforcing their control of combustible procedures has typically been adhered to, although the SRI did make mention that during the post-refueling outage time frame that the licensee has lacked enforcement of their control
of combustible procedures.
This coincided with the above inspection finding
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having been found approximately three weeks after the plant restarted from
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a plant outage.
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At the time the observations were made regarding the fire exposure hazards, the licensee's staff took immediate corrective action in relocating the
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fourteen resin drums.
According to the licensee's April 14, 1986, i
transmittal, to prevent the recurrence of improperly stored combustibles, the Plant staff has been reminded to be more aware of transient fire loads j
and has been directed to remove or clean up such materials as soon as
ongoing work activities are completed.
Since this finding is considered to be an isolated occurrence, no further licensee action is required. Also,
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based on the~above, consideration was given for mitigating the severity li level of this violation.
l 9.
Detection and Suppression
In several areas of the plant, the inspectors observed that heat / smoke l
detectors and sprinkler systems were not installed according to NFPA standards.
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Reactor Coolant Pump Detection and Suppression System In the letter dated August 31, 1979 from D. Bixel, CPC to D. Ziemann, NRC, the attachment states in part "The recirculating pump area spray system will be a dry pipe system provided with a deluge type valve which will control the flow to the system.
Operation of the spray system will be initiated by opening the deluge valve which will permit water to flow to the piping system and to the spray nozzles. Approved fire detection devices located in the same area as the spray nozzle will provide the alarm in the control room.
The deluge valve will be located in an accessible area and shall be capable of remote manual operation from the control room.
The deluge valve will be normally closed. A lock switch in the control room will be provided.
The spray nozzles will be automatic type with a spray density of.35 gpm/ft and spray angle of 65 and 140.
The operating temperature of fusible element will be 250 F.
Each spray nozzle will have a noncombustible heat collector firmly fastened over it.
Heat collector will be designed and installed not to interfere with the spray pattern."
Suppressica NFPA 13 Section 4-1.1.1 states, " correct location of automatic sprinklers withrespecttoceilingsorbeamsandwoodjoisttoobtainsuitable sensitivity."
The location of the sprinklers are not in accordance with NFPA 13 and it is questionable that they will operate as designed.
In the photographs provided to the inspector from the licensee, the sprinklers are not equipped with " heat collectors" as previously indicated to the NRC in the letter dated August 31, 1979 from D. Bixel CPC to D. Ziemann, NRR.
The fire detection and suppression system for the reactor coolant pump area are not installed per NFPA Codes.
Heat Detectors NFPA'72E Section 3-4.1 states in part " Spot type heat detectors shall be located upon the ceiling not less than four inches from the side walls... and 12 inches from the ceiling."
The licensee indicated to the insnector that the heat detectors are on the same level as the automatic s' rinkler piping.
The inspector was p
unable to find heat detectors in the photographs forwarded to the inspector.
Based on the licensee's statement, the location of the heat detectors are not located in accordance with NFPA 72 and their installation is questionable.
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In the letter dated December 17, 1979 from D. Ziemann, NRC to D. Hoffman it states in part, "an appropriate water spray system L.'il be installed for the recirculation pump oil hazard;... Additionally these modifica-tions are being designed in accordance with appropriate NFPA standards.
On this basis, we find that the design of these modifications provides the protection we intended in preparing our SER."
Region III's Concerns The inspector reviewed Attachment 4 of the previously stated August 31, 1979 letter from CPC to NRC and discussed this sprinkler system with the licensee.
The licensee also forwarded the inspector with several photograph's of the area.
The inspectors concerns are noted below:
It should be noted, that even if the heat collectors were installed it would still be questionable if the sprinklers would function as designed.
This issue is considered an Open Item (155/85022-07) pending resolution from NRR.
The Safety Evaluation Report (SER) dated March 8, 1983 indicated, "The licensee states that several modifications have been made inside containment to allow rapid fire detection and fire brigade action."
The SER also states, "The installed early warning detection system would provide prompt detection of incipient fire conditions and fire hose are distributed throughout containment."
During the inspectors tour in containment, it was observed that detectors were not installed throughout containment as per NFPA Codes.
The inspector did not notice an arrangement of detectors throughout containment that would provide prompt detection of incipient fires.
This is considered an Open Item (155/85022-08) pending resolution from NRR.
Condensate Pump Room Fire Detection The Big Rock Point response to Appendix A Guidelines of Branch Technical Position APCSB 9.5-1 states, " Smoke Detection Systems installed at plant construction complied with the revision of NFPA 72D in force at the time of construction.
Detection systems bein modificationswillcomplywithNFPA72D.ginstalledaspartoftheplant Section 3-5.1.1 of NFPA 720 states, " Automatic fire detectors shall be located, maintained, and tested in accordance with the Standard on Automatic Fire Detectors, NFPA 72E."
NFPA 72E Section 4-3.7.3 states, "If the beams exceeded 18 inches in depth and are more than eight feet on centers, each bay shall be treated as a separate area requiring at least one spot type of line-type detector." The inspectors observed in the Condensate Pump Room Elevation 593' -0" of the Turbine Building that the ionization fire detectors were not installed according to 72E.
In the condensate pump room there are beams greater than 18 inches in depth and more than eight feet on center.
Based on the ceiling configuration, each bay required at least one detector per NFPA 72E.
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in the initial design and specified the location of the detectors.
The
licensee has been requested to provide a valid engineering analysis for the location of the detectors in the condensate pump room.
This is
considered an Open Item (155/85022-09) and will remain open pending NRC review and acceptance of the licensee's analysis.
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Control Room Fire Detection System
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Section 5.3.6.b of the licensee's Safety Evaluation Report dated April 4, 1979, requires the installation of smoke detectors in the control room (area - wide protection) and in the cabinets (localized protection).
However, during the inspectors plant tour of the control room, it was observed that only the area-wide installation of smoke detectors in the control room had been performed.
Although the control room cabinets were observed to be open on top allowing the products of combustion during a fire condition to travel freely into the control room area.
The licensee also provided the inspectors with documentation showing NRR had accepted
this configuration.
Yet the inspectors observed that the three fire
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detectors located in the rear of the control room were placed behind return air ducts which raised the concern of a delay in response time of these detectors.
The inspectors review of NFPA 72E and the manufacturers recommendations on placement of fire detectors indicated that relocation of these three fire detectors to be desirable.
This item was discussed with the licensee's fire protection staff and is considered to be an Open Item (155/85022-10) pending NRC review of the licensee's reanalysis.
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10.
Radiant Energy Heat Shield
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Section III.G.2 of of Appendix R to 10 CFR Part 50, requires the proper separation of cables, equipment and associated non-safety circuits of redundant trains.
Section III.G.2.f indicates that separation of cables
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and equipment and associated non-safety circuits of redundant trains by a i
noncombustible radiant energy shield may be utilized inside containment.
In the Safety Evaluation Report dated March 8, 1983, Enclosure 1, the licensee was granted an exemption to Section III.G.2 requirement for separation of cables and equipment for the emergency condenser inlet-valve circuitry and the reactor depressurization and core spray systems circuits on the emergency condenser deck. The licensee committed to protect one emergency condenser outlet valve with a noncombustible
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radiant energy shield which is based on the fact that the amount of.
combustible material on the emergency condenser deck was negligible.
I The location of the " change-out area" reduced the effectiveness that the heat shield may have provided, and appears contrary to the Safety Evaluation Report that the amount of combustibles is negligible.
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i During the July 18, 1986 exit meeting, the licensee committed to control i
combustibles in this area.
During periods other than cold shutdown
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combustible material will be removed when the area is not occupied or the
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i material will be stored in metal containers.
The licensee's performance in controlling combustibles in this area will be monitored in the future.
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11. Technical Specifications The inspectors examined certain fire protection technical specification sections including the fire detection instrumentation, fire suppression, fire hose stations, and penetration fire barrier sections.
During the inspectors review of the fire detection section, during the December 1985 it was noted that the Alternate Shutdown Building fire detection system had not been added to Table 3.3-8, although, the licensee's staff indicated plans to include this system in a revision to technical specification in the future.
The inspectors also rede mention to the licensee of updating their Penetration Fire Barrier Technical Specifications to include fire doors and fire dampers.
By licensee letter dated March 4, 1986, a Technical Specification change to Sections 3.3.3.8 and 3/4.7.12, respectively, incorporates the mentioned changes.
No further action is necessary by the licensee.
Further, as a result of Appendix R modifications and the upgrading of certain fire protection features which change the plants fire protection features as originally detailed in the licensee's Fire Protection Program Evaluation document dated March 29, 1977, the inspector's requested the licensee to update this document so as to reflect the present plant fire protection features.
In addition the licensee committed to providing a comprehensive fire protection summary document before startup from the upcoming refueling outage (startup's Aprilis currently planned for December, 1986) as described in the licensee 14, 1986 transmittal.
This is considered an Open Item (155/85022-11) pending the licensee submittal.
No violations or deviations were identified during review of this area.
12.
Fire Brigade Drill The inspectors requested the licensee to conduct an unannounced fire brigade drill.
This fire brigade drill was performed on December 11, 1985, on a backshift at approximately 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br /> and witnessed by two NRC inspectors positioned at different ventage points.
The fire brigade drill included a postulated oil fire at one of the reactor feedwater pumps on the turbine deck.
The inspectors participated in the post-drill critique noting that all five fire brigade members responded promptly in a coordinated team effort.
Additionally an individual from the Health Physics Department also responded to provide technical assistance to the brigade leader on radiation hazard concerns.
Further, adequate fire equipment was brought to the fire scene including protective clothing and self contained breathing apparatus, and utilized properly. The inspectors did observe marginal communication difficulties at the fire scene which was later discussed at the post-drill critique and was to be followed up on by the responsible licensee staff.
Based on the above, and those actions mentioned by the licensee's staff simulated as taken in the Control Room to safely shutdown the plant, the inspectors determined the fire brigade drill to be successful including the obtaining of the predetermined objectives.
No deviations or violations were observed in review of this area.
13.
Open Items Open items are matters have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both. Open items disclosed during the inspe,ction are discussed in Paragraphs 2, 7, 9, 10, and 11.
14.
Exit Meeting The inspectors met with licensee representatives denoted in Paragraph 1 at the conclusion of the inspection on July 18, 1986, and summarized the scope and findings of the inspection.
The licensee acknowledged the statements made by the inspector.
The inspector also discussed the likely informa-tional content of the inspection report with regard to documents reviewed by the inspector during the inspection.
The licensee did not identify any such documents as proprietary.
In addition, a meeting was held on May 8, 1986, at the Big Rock Point Plant as requested by NRR to further discuss the inspection findings from the December 9-13, 1985, March 5-7, and 31, 1986 inspection visits.
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