ML20236R277
| ML20236R277 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 07/14/1998 |
| From: | Powers K CONSUMERS ENERGY CO. (FORMERLY CONSUMERS POWER CO.) |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| 50-155-98-03, 50-155-98-3, NUDOCS 9807210335 | |
| Download: ML20236R277 (16) | |
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- W D f A CMS Energy Cimmny Big Rock Point Nuclear Plant Kenneek P. hnners 10269 l&31 Nonn Site General Manager Charlevoix, MI 49720 l July 14, 1998 Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 DOCKET 50 155 - LICENSE DPR 6 - BIG ROCK POINT PLANT - RESPONSE TO APPARENT VIOLATION IN NRC INSPECTION REPORT 98003(DNMS).
Based on the results of an NRC inspection at the Big Rock Point Plant, an apparent violation of NRC requirements was identified and forwarded by letter dated June 16, 1998. The report requested Consumers Energy Company to respond in writing to the apparent violation within 30 days, or request a predecisional enforcement conference. This letter and attachment satisfy the request by the Commission to respond in writing within 30 days of the date of the letter.
The apparent violation concerns the failure of the liquid poison tank discharge pipe located inside the tank. This condition was discovered during decommissioning activities to remove sodium pentaborate from the tank for disposal. The pipe had corroded and separated into two distinct parts: one above the level of the sodium pentaborate, and one that fell down into the tank. The actual time of the failure is unknown, however the investigation has determined that this situation existed for a considerable time during power and refueling operations. In this condition, the sodium pentaborate could not have been injected into the reactor vessel to reduce power if the control rod blades failed to perform their safety function. Alternate Boron Injection /j/
would have had to have been initiated to mitigate the consequences of the
/j event. -
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Kenneth P Powers Site General Manager CC: Administrator, Region III USNRC Of NRC Resident Inspector - Big Rock Point NRR Project Manager - OWFN, USNRC ATTACHMENT 9807210'335 980714 ADOCK 05000155 0
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CONSUMERS ENERGY COMPANY Big Rock Point Plant
! Docket 50-155 License DPR-(,6 RESPONSE TO APPARENT VIOLATION IN NRC INSPECTION REPORT 98003(DNHS).
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- -At the request of the Commission and pursuant to the Atomic Energy Act of 1954 l and the Energy Reorganization Act of 1974. as amended, and the Commission's l' Rules and Regulations thereunder Consumers Energy Company submits our l' response to NRC letter dated June 14, 1998, entitled " RESPONSE TC APPARENT VIOLATION IN PRC INSPECTION REPORT 98003(DNMS).
CONSUMERS ENERGY COMPANY l
l To' the best of my knowledge, information and belief, the contents of this submittal are truthful and complete.
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By- w_ c#uAA_.
Kenneth P Powers Site General Manager Sworn and subscribed to before me this 14th. day of JULY.1998. )
bsd, oknv Qfe$nw ennif[r Lynn41 elms Notary Public Charlevoix County, Michigan l
My commission expires August 29, 1999.
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l ATTACHMENT l
CONSUMERS ENERGY COMPANY BIG ROCK POINT PLANT DOCKET 50-155 RESPONSE TO APPARENT VIOLATION INSPECTIOll REPORT 98003 Submitted July 14, 1998 i
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l-Executive Summary Event Description l- On March 27, 1998 an unsuccessful attempt was made to discharge the contents of the liquid poison system (LPS) tank to a group of 55 gallon drums. On April 24, 1998, a
- j. boroscope inspection of the tank through the level instrumentation pipe was performed. The inspection revealed that the poison discharge pipe inside the tank was completely severed about 6 inches above the water line. The asbestos insulation on the LPS tank was then removed The LPS tank was opened and a visual inspection confirmed that the 3 inch discharge pipe was completely severed. The cause of
- ' severance was corrosion. It is uncertain when the pipe failed. The severed pipe l functioned as the supply line of poison to the reactor. Because the line was severed, poison would not have been delivered to the reactor if the system had been activated.
NOTE: THIS SYSTEM IS NOT. REQUIRED FOR DECOMMISSIONING.
Root.Cause-The phenolic' coating on the pipe broke down over time allowing the sodium pentaborate to interact with and corrode the carbon steel pipe.
- Safety Significance l
The Big Rock Point staff determined that the _ safety significance of this condition was low. Overall the effect of a failed liquid poison system on the.previously i
! evaluated core damage frequency would have been expected to be an approximate 4%
. increase.
Corrective Action BIG ROCK POINT The Big Rock Point Staff reviewed decommissioning surveillance testing on safety- a related SSCs (systems, structures, and components). SSCs important to the safe storage of spent fuel (ISSSF), and SSCs important to the monitoring and control of radiological hazards (IMCRH). All surveillance testing procedures were found to be satisfactory for the condition of the plant.
PALISADES NUCLEAR POWER PLANT Palisades _ Nuclear Power Plant does not have any non-safety related equipment with comparable significance to the Big Rock Point liquid Poison Tank Palisades also completed a review of all safety systems to identify any internally coated components l? within these systems installed at Palisades. No components were found to be
- internally coated. Either stainless steel, aluminum components or carbon steel components with a stainless steel cladding are used wherever there is contact with borated water. On July 9, 1998, Palisades transmitted an Operating Experience Report covering the subject on behalf of Big Rock Point.
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.ApparentLViolation l
Corrosion failure of the liquid poison tank discharge dip tube rendered the
. liquid poison system inoperable during sorne periods when the system was O required to be' operable. TS 5.2.3 " Liquid Poison System", states "The liquid
[ poison system shall be available for operation at all times during refueling and power operation. " The liquid poison tank being inoperable before September 20,1997c is an apparent violation of TS 5.2.3 (50-155/98003-01(DNMS)).
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Consumers Energy Company agrees with the' violation as stated.
I. _ Reason for the Violation Analysis _.
l Reoortable Condition:
On March 27,1998 an unsuccessful attempt was made to discharge the contents of the LPS tank to a group'of 55 gallon drums. The tank was supplied with an air source in order to push the liquid poison out the discharge pipe. Instead of the liquid poison discharging from the LPS l tanki air flowed out. A subsequent boroscope inspection of LPS tank
-internals revealed that the discharge pipe had totally corroded through
- and severed the pipe. The pipe break prevented liquid' poison from leaving the tank through the discharge line. The tank man way was l subsequently removed and'it was confirmed that the discharge line was
- severed.
Insoection Results & Observations:
- Both pipe ends were shipped to the Consumer's Energy laboratory for
- analysis -The lab stated ~that the phenolic coating was' completely
- stripped from the pipe, except for the'last 18 inches of pipe. It was l
' obvious that the break was caused by corrosion. From a visual inspection"of the tank inside walls, it was discovered that the coating
_ had failed or peeled off in many locations below the " water" line and was entirely gone from surfaces above the water line'. Another observation is that:there was red oxide colored rust on the surfaces
. that were above the water line, but generally not below the water line.
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Desian Facts:
The tank was purchased with specification M-27 which specified an 850 gallon carbon steel pressure vessel designed for 2000 psia at 650 F and internally lined with a baked phenolic coating. LC-24. The coating was to be a minimum of 5 mils thick. The interior pipes are schedule 40 and also are made of carbon steel and by specification are supposed to be lined inside and outside with the phenolic coating. The normal conditions of tank service are pressure of 0 to 50 psig.150 0F. The tank is designed to hold 20 % solution of sodium pentaborate. The tank was manufactured by National Tank & Boiler Company of Hazelwood.
Missouri in 1961. The tank was shipped to Lithcote Corporation of Melrose Park. Illinois for application of the phenolic coating.
The intent of the coating is to protect the surfaces from the sodium pentaborate which would exist as a slightly acidic solution. M-27 stated that the tank is designed for continuous service at 150 F. No service time limit was stated. Neither were periodic inspection requirements imposed. The plant license was for 40 years. Therefore it is assumed that the designers expected the coating to last the life of the plant, i.e. 40 years.
Based on correspondence among Bechtel, National Tank & Boiler Company (the tank manufacturer) and Lithcote Corporation (lining vendor). it is apparent that the suitability of LC-24 was questioned. The tank specification specified a design temperature of 650 F.0 The tank vendor assured Bechtel that LC-24 was adequate for this service. The coating vendor. Lithcote Corporation, stated that LC-24 would not be suitable for 650 F but that temperatures above 300 F may damage the coating.
Lithcote did say that the coating could be used for normal operating conditions. Bechtel in a letter to Consumers Power expressed confidence in the suitability of LC-24 for the LPS tank based on Lithcote's confirmation and successful application at Humboldt Bay. Vendor corrosion testing of LC-24 was for a max of 30 days which would not be adequate for a 40 year cycle.
Tank inspection records during the manufacturing process were available.
The final inspection was completed at Lithcote Corporation. Melrose Park. Illinois on Jan 31.1962. The inspection report stated that the electrical resistance test of the coating was satisfactory with no leaks 4
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detected. Coating thickness was 6 to 8 mils. The inspection report specifically states that there is coating on tank and flanges but does not specify coating was on the dip tubes (discharge and sample pipes).
Operational Facts:
l l -There are no surveillance test requirements associated with inspecting l the tank internals or verifying flow can exit the tank. General
- l. Electric stated that a means should be provided for periodically l checking vessel integrity.
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- y. Several people who have long history at Big . Rock Point were interviewed I and none can. recall anyone for any reason removing the man way flange for any maintenance or inspection.
Probable Cause:
A phenolic coating should not be expected to last 40 years. According to an industry materials expert, a baked phenolic coating was one of the best choices for this application in the early 1960's However, the maximum expected service life would be only 10 years. With a 40 year
, operating license, other design considerations should have been implemented. Additionally, the air space above the water line was a highly corrosive environment. This air space.was enclosed and had water vapor from the liquid. The water vapor consisted of distilled water l which is highly corrosive because it lacks ions. There was also an ample supply of oxygen to the air space which was supplied every refueling outage.
Root Cause:
l The phenolic coating on-the pipe broke down over time allowing the carbon steel pipe to' rust and fail in the sodium pentaborate l
.. envi ronment. The cause of the phenolic coating breakdown could be any or all of the following:
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- 1) inadequate quality assurance in applying the coating on the l pipe.
- 2) inadequate curing of the coating.
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- 3) highly corrosive environment of the air space which contained distilled water vapor and plenty of oxygen from performing test procedure TR-26.
l l 4) inability of a 5 mil coating to last 40 years.
II. The corrective stens that have been taken and the results achieved.
NOTE: THIS SYSTEM IS NOT REOUIRED TO BE OPERABLE FOR DECOMMISSIONING.
A. SAFETY SIGNIFICANCE ANALYSIS The Big Rock Point staff has determined that the safety significance of this condition was low.
Overall, the effect of a failed liquid poison system on the previously evaluated core damage frequency of 5.45E-5 would be expected to increase approximately 4%. Contributing to the relatively small increase in core damage frequency are the following:
- Low initiating event frequency for non-turbine trip ATWS sequences.
- Low failure probability associated with a scram failure.
- Mitigating features included in the plant design and
- Large contribution to core damage from loss of coolant type initiating events.
Big Rock Point included several design / operating features that limited the safety significance of experiencing a liquid poison system actuation failure.
Discussed below are highlights (extracted from the May 5.1994 Big Rock Point IPE submittal) of the plant's key mitigative features following scram and poison injection failures:
- Tripping one or both reactor recirculating water pumps reduces reactor power to 60% and 50% of initial power. respectively.
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- An automatic trip of the recirculating water pumps would occur during a load rejection or upon activation of the emergency condenser.
- The plant secondary s_ide had full load rejection capability (turbine bypass valve and steam line designed to transport 100% of full power steam to the main condenser).
- The primary system steam drum safety relief valves were capable of relieving
'200% of full power steam.
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- Primary coolant inventory could be maintained during an AT14S with a recirculation water pump tripped if the main condenser, bypass valve /line, and feedwater each function as designed.
L - The emergency condenser system was capable of extending the time required to reach low reactor water level. The existing normal operation shell side inventory lasts 30 minutes with the reactor operating at full power.
- There was a large containment free-volume and ultimate strength for the relatively low thermal power.
- High pressure. high capacity injection capability was not' included in the Big Rock Point design. This would have limited the impact of the Large Early Release F. action (LERF). With only a limited amount of-low pressure feedwater available, overpressurization of the containment would not have been an-issue.
- Emergency Operating-Procedures provided instructions for reactivity control.
! reactor pressure control, and reactor inventory control during ATWS conditions that would have resulted in rapid shutdown and adequate core cooling. Instructions were also provided to protect-the containment from over-pressurization should power operation continue without the ability to achieve subcriticality.
The normal steam flow during full power operation was approximately 1E+06 lbs/hr with normal. recirculating water flow ten times greater (at 1E+07 lbs/hr). Tripping one of the two recirculating water pumps would have reduced coolant flow such that reactor power would drop to 60% of its initial level
.(tripping of.the second pump results in an additional 10% drop in power).
Plant modifications resulting from the alternate rod injection analysis
-included an automatic trip of one recirculating water pump during 1) load 7
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RF9PON9F TO APPARFNT VTOIATinM TN TN9PFCTTON RFPORT 60.144/QRnn1(DNMR) rejection events and 2) operation of the emergency condenser.
The plant's secondary side was designed with the ability to withstand a full load rejection from full power. The main condenser, bypass valve and bypass steam line were sized to accept the steam flow associated with full power operation. The automatic opening of the bypass valve was keyed to steam line pressure (reactor pressure plus 10 psi would initiate valve opening) and an anticipatory signal generated parallel with opening of the plant 138 kv output circuit breaker. The bypass system was designed to prevent a high reactor pressure condition and actuation of the primary system safety relief valves for any ATWS in which the main condenser remained available and the bypass valve remained open.
This was significant in that if feedwater would have remained available, the secondary side of the plant could have removed all of the steam produced in the reactor, condensed it and returned it to the primary system. The reactor would have continued to operate even though a scram failure had occurred and poison injection was not available. This provided the operator with an indefinite amount of time in which to bring the reactor subcritical (via control rods or alternate boron injection).
The primary system was designed with six spring loaded code safety relief valves attached to the steam drum. Each valve was rated in excess of 100 lb/hr relieving capability at 1870 psia (110% of design). The size and number of relief valves provided an equivalent 200% full power relief capacity. This capacity would have allowed the primary system to remain within code allowable limits even if: 1) the reactor had been isolated at full power. 2) failure of the reactor to scram occurred and 3) no mitigating systems functioned as designed.
The emergency condenser was equipped with two independent tube bundles, each capable of removing about 5% of normal reactor power. Operation of the emergency condenser during an ATWS had the beneficial effect of limiting the amount of steam leaving the primary system through the safety relief valves, thus extending the time period for depletion of the primary system to the low reactor water level set point (and Reactor Depressurization System [RDS]
automatic actuation). The shell of the emergency condenser included a volume of water equivalent to about 30 minutes of heat removal without makeup. The makeup supplies were capable of only about 2% of reactor power. Once depleted, steam would then be released to the containment at a rate similar to that had the emergency condenser had not actuated.
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The containment free volume is approximately 1E+06 cubic feet. The large containment volume to reactor power level ratio extended the time required to raise containment pressure and temperature to design conditions. Plant response analysis suggested that, if reactor shutdown could have been effected
- prior to RDS actuation, containment design conditions would not have been l exceeded. Best-estimate analyses performed suggest that the ultimate strength of containment would not have been exceeded until internal pressures exceeded 79 psig. This pressure was not expected to be exceeded for over an hour (following an ATWS) given RDS and core spray operation without reactor shutdown.
On May 5, 1994 (supplemented by a May 27, 1994 letter) Consumers Energy submitted the response to Generic Letter 88-20 Individual Plant Examination For Severe Accident Vulnerabilities, for Big Rock Point. Evaluation results performed on those potential accidents included a failure of the reactor protection system. These Anticipated Transients Without SCRAM (ATWS) evaluations included the potential for LPS failure. The LPS is a manually initiated system designed with single failure proof concepts applied to active components. This design philosophy provided a system with a highly reliable actuation system, the weakest link being the operator initiating the system.
Given the discharge pipe failure internal to the LPS storage tank, initiation of the siphon action needed to transport the liquid poison solution into the reactor would not have occurred. The ATWS accident sequence analysis showed that LPS failure was dominated by the operator failing to initiate the firing sequence. This time dependent failure rate ranged between 0.3 (sequences requiring operator action within 2 minutes) to 0.01 (sequences requiring operator action within about 12 minutes).
The dominant ATWS sequence contributor (greater than an order of magnitude than other ATWS sequences) was initiated by a turbine trip. The effect of assuming no LPS will .be discussed with respect to this initiator. For the remaining event trees the summation of the product of initiating event frequency and the failure to SCRAM probability, without crediting any mitigative actions, will be used to estimate the impact of a failed LPS, This sum is less than 5% of the base-line core damage frequency.
From the turbine trip event tree, there are two sequences that contribute approximately 90% of the overall ATWS contribution to core damage. These sequences include success of the main condenser as a heat sink and LPS failure. The LPS failure is d6minated by the operator failing to provide 9
RFRPANRF TO APPADFNT VTnt ATTON TN TNRPFETTAN DFPnRT Rn.166/QRnnUnNMR) injection within 2 minutes (this operator action included tripping the reactor recirculating water pumps and poison initiation). If the poison system failed to inject due to mechanical means the operator action would remain applicable -
I for the recirculation water pump trip action. Thus the sequence probability would remain the same. With-the pumps tripped and steam bypassed to the main i condenser the plant could survive the turbine trip without the reactor scram.
l Time would be available to pursue other means of inserting the control rods or providing. alternate poison injection.
. The turbine trip sequence would have been expected to proceed as follows:
The reactor is operating at 100% power with the turbine-generator on-line. A
' trip occurs. (turbine stop valve closure and the generator output breaker opens). ' As the stop valve closes, pressure rises within the main steam line and ultimately the primary system. The pressure increase in the primary system causes flux-levels to increase which would trip the neutron monitors
- l. initiating a-reactor scram. The turbine bypass valve also opens to control pressure by sending steam directly to the main condenser (the bypass system and condenser were designed for 100% load rejection capability). The
. operators would respond to the turbine trip by checking for reactor scram and I attempting manual scram actions for an automatic scram failure. Failing this the. operators would then trip the reactor recirculating water pumps and initiate LPS injection. Tripping the recirculating water pumps reduces reactor power output to 60% of its previous value. This reduc. ton in power reduces the heat' removal' demand placed on the secondary side. At this_ point the plant can continue to operate in this fashion without injecting liquid poison. The emergency operating procedures would then be utilized for !
alternate boron injection.
The results presented in the May submittal indicate that two sequences from the turbine' trip event tree quantification accounted for greater than 85% of i the ATWS contribution to the core damage frequency. Included in the sequence was the failure to inject liquid poison into the reactor vessel. For these two sequences the dominant failure mode was the operator failing to perform ;
the. actions of. injecting poison and tripping the pumps. For this sequence l approximately 2 minutes are available for the operator to perform the required i actions. - The action to trip the pump and inject were considered to be the same event. Therefore, for.the quantification, if the LPS mechanical and electrical contribution were set to 1.0. the operator action would remain due to tripping of the recirculating water pump. Ultimately. the sequence frequency would remain the same, 10 i
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BIG ROCK POINT RISK COMPARED TO THE INDUSTRY Figure 1 compares BRP to the industry at the time of the IPE submittal in 1994. The 1994 IPE CDF of 5.4E-5 is slightly less than the industry mean. This includes BWR and PWR design features inherent to Big Rock Point. Some of the key modeling conservatism included:
- 1) Below-core Loss of Cooling Accidents (LOCAs) dominate plant risk. No Post Incident System recovery was credited.
- 2) The Reactor Depressurization System (RDS) success criteria conservatively required the availability of 3 out of 4 trains. Analyses have demonstrated j
- that the most limiting below-core LOCAs require only one train of RDS.
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- 3) If RDS were unavailable, analyses have demonstrated that the emergency condenser would be sufficient to depressurize the primary system for low i pressure injection for the very-small below core break spectrum. Emergency !
condenser operation during a LOCAs was never credited.
- 4) Primary system reflood was never credited.
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- 5) The proceduralized manual operation of the alternate core spray injection l path was never credited. l B. INVESTIGATION OF BIG ROCK POINT SAFETY-RELATED SYSTEMS FOR PAST AND CURRENT OPERABILITY 26 safety-related systems and their functions were examined and verified by surveillance test information to have been capable of performing their intended safety function. Decommissioning Systems that are safety-related. I important to the safe storage of spent fuel and important to the monitoring and control of radiological hazards have also been evaluated for adequate i surveillance tests and potentially corrosive environments. All surveillance testing procedures were found to be satisfactory for the condition of the plant.
C. PALISADES NUCLEAR POWER PLANT Safety related systems and components at Palisades which are normally in a standby mode, which may be stagnant or essentially stagnant and which contain >
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RFRPONRF TO APPADFMT VTOl ATTON TN TNRPFCTTON RFPORT Rn.1RR/QRanVnNMR) corrosive or potentially corrosive fluids are confined to the borated water systems This includes portions of the Containment Spray High Pressure Safety Injection. Safety Injection Tanks and piping Low Pressure Safety Injection.
Chemical and Volume Control. Spent Fuel Pool Cooling and Radwaste Systems.
The Iodine Removal System, which connects to the Containment Spray System and which formerly contained sodium hydroxide and hydrazine for post-LOCA treatment of Containment Spray water, was drained and retired in place in 1996. Palisades does not have any non-safety related equipment with comparable significance to the Big Rock Point- Liquid Poison Tank.
Palisades has completed an initial review of all safety class systems to identify any potential internally coated components installed at Palisades.
The result of this review found no components which are internally coated.
The results show that either stainless steel components or carbon' steel components with a stainless steel cladding are used wherever there is contact with borated water.
The issue of material integrity of potentially stagnant portions of stainless steel borated water systems has been previously addressed in response to IE Bulletin 79-17., " Pipe Cracks in Stagnant Borated Water Systems at PWR Plants" l (Note: This IE was issued to PWRs. Big Rock Point was/is a BWR. During the 1979/1980 Palisades refueling outage, ultrasonic examinations and hydro / leak tests were conducted on stainless steel piping which has been postulated to contain stagnant borated oxygenated water. The examinations and tests were performed partially in response to the normal Palisades Inservice Inspection Program and partially in response to IE Bulletin 79-17 and canvassed all areas of concern. The results.of these examinations and tests revealed no deficiencies and were reported to NRC staff by letters dated August 25, 1979.
February 1. 1980 and May 9. 1980.
The Inservice Inspection and the Inservice Pressure Test Programs are established and satisfy the 1989 Edition of ASME Section XI. The purpose of t these programs is to examine and test the safety related piping systems and I- components to identify potential corrosion mechanisms such as the mechanisms L identified with the Liquid Poison Tank. These two programs at Palisades have L not identified any similar types of failures as discussed above. Palisades also inspects selected non-safety related systems when failure mechanisms such as flow-assisted corrosion and. microbiological induced corrosion could be active.
1 0 INDUSTRY NOTIFICATION 1
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A Licensee Event Report has been initiated and will be submitted in August, 1998, to describe the event. An Operating Experience Report has also been generated by Palisades Nuclear Power Plant on behalf of Big Rock Point on July
- 9. 1998, to inform the industry of the event.
III. The corrective steos that will be taken to avoid recurrence.
As a result of the Big Rock Point Liquid Poison Tank event. Palisades intends to reevaluate the results of the examinations and tests performed in conjunction with the IE Bulletin 79-17 response and ensure that all potentially affected areas continue to be monitored appropriately.
IV. The date when the facility will be in full comoliance.
The facility is currently in full compliance.
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