ML20024H495
| ML20024H495 | |
| Person / Time | |
|---|---|
| Site: | Fort Saint Vrain  |
| Issue date: | 05/21/1991 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20024H492 | List: |
| References | |
| NUDOCS 9106040204 | |
| Download: ML20024H495 (9) | |
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UNITED STATES 5
i NUCLEAR REGULATORY COMMISSION
(([jl/f W ASHINGToN. D C 705ss
f SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULA110N SUPPORTING AMENDMENT NO. 82 TO FACILITY LICENSE NO. DPR-34 PUBLIC SERVICE COMPANY OF COLORADO FORT ST. VRAIN NUCLEAR GENERATING STATION DOCKET NO. 50-267
1.0 INTRODUCTION
By letter of November 21, 1983, as supplemented on April 25, 1990, February 22, March 6, March 27, April 23, and May 3, 1991, the Public Service Company of Colorado (PSC) proposed to amend License No. DPR-34 to delete the authority to operate the Fort St. Vrain reactor at any power level.
The Fort St. Vrain Nuclear Generating Unit (F M) was permanently shut down on August 18, 1989.
On May 16, 1990, the NRC published in the Federal Register a Notice of Con-sideration of Issuance of Amendment to Facility Operating License and Proposed No Significant Hazards Consideration Determination and Opportunity for Hearing related to the requested amendment.
The NRC received no public comments or requests for hearing.
The supplements received after publication of the Federal Register notice provided additional information that did not change the action described or affect the initial proposed no significant hazards consideration determination.
2.0 DISCUSSION AND EVALUATION The proposed amendment to possession only status is implemented by changing paragraph 2.C.(1) of License No. DPR-34 from " possess, use, and operate the facility" to " possess but not operate the facility."
License No. DPR-34 is also changed by revising paragraphs 2.C.(2) through 2.C.(5) to (1) delete authority to receive or use reactor fuel, but to allow previously used fuel to be retained at FSV; (2) allow continued possession of byproduct, source, and special nuclear material in sealed sources for instrumentation and monitoring equipment calibration, but not for reactor startup or operation; and (3) allow continued possession, but not separation of such byproduct and special nuclear materials which were produced in the previous operation of FSV.
In addition, paragraph 2.D.(1), " Maximum Power Level," is revised to prohibit the taking of the reactor to criticality or the operation of the facility at any power level.
In addition, the second sentence of paragraph 2.0.(2) is revised from "The licensee shall operate the facility in accordance with the Technical Specifications" to "The licensee shall maintain the facility in accordance with the Technical Specifications."
All of the above revisions to license No. DPR-34 reflect the deletion of authority to operate the reactor.
Therefore, since the effect of each of the revisions is to prohibit operation of the facility, the amendment does not result in significant risk to the public health and safety.
9106040204 910521 PDR ADOCK 05000267 P
_ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _. FSV was shut down on August 18, 1989, because of control rod failures.
The shutdown was made permanent because of a subsequent discovery of degradation of steam generator ring headers.
PSC began defueling on November 27, 1989, and completed the removal of one-third of the core (the maximum capacity of its onsite fuel storage wells) on February 7, 1990.
About two-thirds of the fuel will remain in the core and defueling will not be completed until resolu-tion of final disposition of the spent fuel.
PSC will either ship the spent fuel to a U.S. Department of Energy (DOE) facility in Idaho for reprocessing or will construct an independent spent fuel storage installation (ISFSI).
The Commission's Confirmatory Order, published in the Federal Register on May 7, 1990 (55 FR 18994), modified the FSV license to prohibit taking the FSV reactor to criticality or operating FSV at any power level.
The revised Technical Specifications (TS) at FSV limit the number of control rods that can be withdrawn from fueled regions such that the reactor cannot be made critical.
All other control rods are locked out so that they cannot be accidentally moved.
Control rods must be withdrawn from the fuel elements being removed from the reactor during defueling.
One-third of toe spent fuel has been removed from the core and placed in the fpel storage wells.
Boron poisoned defueling elements (without fuel) have been inserted in locations where fueled elements have been removed.
The removal of one-third of the fuel, the additional bcron in defueling elements, and the 15 restriction on control rod removal adequately protect the reactor from accidental criticality and prevent planned critical operations.
Amendment of the license to possession only status does not delete the require-ments of any of the T5.
All requirements that are related to the snutdown status of FSV remain in ef fect.
However, PSC is permitted to consider the permanent shutdown status of F5V with respect to its reviews of proposed changes at FSV pursuant to Section 50.59 of Title 10 of the Code of Federal Regulations (10 CFR).
PSC has indicated that it plans to repower F5V with a natural gas fired boiler but that it does not plan to bring natural gas onsite for repowering until after the Decommissioning Plan has been approved.
A revised license condition (2.D.(4)) has therefore been established to prohibit natural gas introduction within 0.5 mile of the plant for repowering the facility while any spent fuel or other radioactive graphite core components remain on site unless previously evaluated and approved by the NRC.
The 0.5 mile distance is the distance from a postulated rupture of the high pressure gas supply line to the point at which the concentration of the resulting gas / air mixture drops below flammable limits (0.4 mile), plus an additional 25 percent (0.1 mile).
This distance was calculated by the NRC staff assuming a natural gas release rate of twice the supply rate needed by the natural gas boiler.
During the time period from 1982 until 1987, the licensee permitted drilling of 14 natural gas wells witnin one mile of the Fort St. Vrain reactor.
In an analysis oursuant to 10 CFR 50.59, the icensee evaluated possible hazards associated with the well closest to the reactor building and concluded that the well did not create the possibility of an accident or malfunction of a different type than any evaluated previously in the FSAR.
After reviewing the license?'s analysis, the NRC staff requested that the licensee evaluate
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. additional hypothetical accident scenarios associated with these natural gas wells.
The licensee's submittal of February 22, 1991 provided detailed technical information regarding-the closest well which has piping that is located about 950 feet from the reactor building.
The licensee's contractor performed analyses which concluded that rupture of the 2 1/2 inch well piping would not produce flammable gas concentrations further than 120 feet from a postulated break and that detonation of the gas plume or explosion of a metering shed would not affect the structural integrity of the reactor or turbine building.
The licensee's submittal of March 6, 1991, provided a detailed description of the results of these analyses.
In the February 22, 1991 submittal, the licensee also concluded that routine gas recovery operations will not cause any seismic disturbances because (1) there are no plans for continual injection of fluids for secondary recovery in these wells; and (2) the wells were drilled straight down and thus are not located underneath any safety-related structures.
The NRC staff has reviewed these submittals and agrees with the licensee's conclusions.
The staff has_also performed independent flammability and explosive concentration limit calculations which further support these conclusions.
The staff also independently verified the explosive possibility from detonation of the vented metering shed (5 feet by 6 feet by 7 feet in size) located greater than 950 feet from the reactor building.
Both the staff and the licensee concluded that explosion of this shed would not affect the structural integrity of the reactor building.
By letter dated March 27, 1991, the licensee submitted the results of additional analyses of hypothetical worst case ruptures of natural gas collection piping which connects the wells in the vicinity of Fort St. Vrain to a much larger 16 inch diameter collection pipeline which typically operates at 150 psig.
The 1icensee concluded that a postulated break of either a 6 inch pipe located 1340 feet from the reactor building (Break 1) or a break of a 4 inch pipeline located 930 feet from the reactor building (Break 2) would constitute limiting scenarios for analysis of potential natural gas hazards.
The licensee did not evaluata possible rupture of the 16 inch collection pipeline which at its closest point is located about 0.85 mile from the reactor building.
The staff judges such analysis to be unnecessary since the NRC has previously analyzed larger, higher pressure natural gas pipelines located much closer to other reactors and has found them to be acceptable.I 21n the Construction Permit Safety Evaluation Report for TVA's Hartsville facility (NUREG-0014) issuec on April 8, 1976, the NRC evaluated (1) flammable gas concentrations at building air intakes, (2) thermal radiation fluxes, (3) external overpressure, and (4) missile generation created by possible accidents associated with a 22 inch diameter natural gas pipeline operating at a maximum pressure of 720 psig and located 2650 feet (0.5 mile) from safety-related structures.
The staff concluded that this pipeline "... represents no undue threat to the safe operation of the proposed Hartsville facility, and the accidents occurring to that pipeline need not be considereu in the design of the plant." Notwithstanding the structural differences between the Hartsville facility, which was analyzed and found acceptable, and FSV, the staff-judges the natural gas hazard at FSV to be less than at Hartsville, when considering the other significant factors such as pipeline diameters, pipeline pressure, and distance from pipeline to reactor.
. When evaluating the potential consequences of the possible collection piping ruptures, the licensee found that significant backflow of natural gas from the 16 inch collection pipeline through a 6 inch line would feed the ruptures at both Break 1 and Break 2 locations.
In order to reduce the potential flow rates due to backflow at these break locations, the licensee has closed a 6 inch valve located near the 16 inch pipeline (about 0.92 mile from the reactor building) and is now supplying natural gas to the collection pipeline through a smaller 1 1/2 inch bypass line.
Under this scenario a double-ended rupture at these break locations could be fed from one direction by gas from up to 10 wells, and in the other direction by backflow from the 16 inch pipeline, but limited by the maximum flow rate through the 1 1/2 inch bypass line.
This interim solution proposed by the licensee reduces the steady-state natural gas backflow release rates at Break 1 and Break 2 locations from 37.1 million standard cubic feet per day (scfd) and 10.6 million scfd, respectively, to 10.1 million scfd.
In actual practice, a large rupture in either the 6 inch or 4 inch line would cause the 10 wells feeding this system to rapidly isolate or " shut-in" automatically, due to the rapid pressure reduction.
Each of these 10 wells supplies natural gas from the wellhead through a three phase separator, which removes oil and water from the natural gas, to a measuring station and into the collection system piping.
A "high-low valve" is located at the inlet of the separators for each of these 10 wells.
The high-low valves automatically shut upon sensing low pressure, and are all set at approximately 25 psig.
Assuming a large rupture of a collection line, the wells nearest the rupture would be shut-in first as pressure dropped below about 25 psig, followed by shut-in of the wells located a greater distance from the rupture location.
In the event of a double-ended rupture of the 4 inch or the 6 inch collection line, all 10 wells connected to this system would be shut-in by the high-low valves within 3 minutes, oue to system depressurization.
The high-low valves are also designed to close when piping pressure exceeds 250 psig to limit the pressure in the collection piping system.
Quarterly surveillance tests are performed on the high-low valves by the operator of the gas wells to i
ensure they are operable to isolate the wells in both the high and low pressure l
modes.
In addition to the high-low valves, each well also has a " shut-in valve" located at the wellhead, which automatically actuates to isolate the producer pipe at the wellhead in the event of low well casing pressures.
These shut-in valves are pneumatic motor operated valves which are actuated by pressure switches sensing well casing pressure.
Pneumatic pressure is supplied by natural gas taken from downstream of the separators, The pressure switches l
are set to open the shut-in valves at a high pressure of approximately 350 psig and to close the shut-in valves at a low pressure of approximately 170 psig, for all 10 of the wells that feed the gas collection system in the vicinity of FSV.
In the event of a large rupture of the collection piping, the gas pressure in each well casing would drop below 170 psig and the pressure switch would cause the shut-in valve to be closed by a spring, isolating the well at the wellhead.
With the wellhead isolated, the gas pressure downstream of the separators would be nearly zero psig.
Eventually, the pressure in the natural gas reservoir would cause well casing pressure to increase to 350 psig.
Although the pressure switch would call for the shut-in valve to open, it
I l would rema'n closed by the spring since there is no pneumatic pressure available downstream of the separators to open it.
The operator of these 10 wells, Barrett Resources, checks operation of these shet-in valves and their pressure switch actuators on a daily basis.
In spite of the redundant isolation valves at each well, the licensee's analysis assumed that both valves at each of 2 wells failed open when the piping ruptured.
The staff has reviewed this assumption and agrees that it is sufficiently conservative considering the reliability of t'> valves and the periodic surveillance testing done by the well operators.
The licensee assumed a gas flow rate of 1 million scfd from e h unisolated well.
This assumed flow rate for 1 well is greater than the utrrent produc-tion capacity of all 10 wells combined.
The staff concludes that this flow rate is sufficiently conservative to account for possible future increases in production rates by periodic well recompletion (overhaul) and for temporarily higher short-term flow rates caused if some wells are shut-in allowing wellhead pressures to build up resulting in temporarily increased flows when the shut-in wells are reopened.
In addition to tne steady-state flow of gas released from the wells and from backflow from the collection pipeline, piping ruptures at Break 1 and Break 2 locations would also be fed by gas from the rapid depressurization of the gas contained within the collection system.
The licensee assumed that the collec-tion system was operating at the maximum pressure of ' ; psig (limited by the high-low valves) and that entire contents of the system (75,000 scf at 250 psig) were released in 1 minute for Break 1 and in 2 minutes for Break 2.
These initial releases were added to the steady-state flow rates from the wells and from backflow from the 16 inch line through the 1 1/2 inch bypass line.
The analyses summarized in the licensee's March 27, 1991 submittal concluded that flammable gas concentrations would exist no further than 225 feet from Break 1 and 250 feet from Break 2.
Since the reactor building is more than 900 feet from either of these break locations, flammable gases would not enter the reactor building.
The licensee also calculated maxitum overpressures resulting from postulated detonation of these clouds of natural gas and concluded that the maximum dynamic overpressure of 1.0 psig for Break 2 would not affect the structural integrity of the reactor building which is designed to withstand a static cverpressure of 1.44 psig associated with a 300 mph wind loading.
The NRC staff reviewed these conclusions in the March 27, 1991 submittal and requested the licensee to consider the dynamic lead factor effect in converting the dynamic overpressures resulting from postulatt.d natural gas explosions to equivalent static pressures for assessing structural effects on the reactor building.
The NRC also requested the licensee to further analy2e the struc-tural effects of the overpressures on the reactor building since the fort St.
Vrain USAR states that limited damage to the upper siding of the building would occur at wind speeds of 300 mph.
The licensee responded in a submittal dated April 23, 1991 which provided a more realistic analysis of the mass of natural gas assumed to detonate.
In this submittal the licensee postulated detonation of (1) all natural gas from the initial collection piping depressurization transient and (2) the portion 1
6-of the subsequent steady state release that was within flammable concentration limits.
This submittal also considered the overpressure effects resulting from an elevated detonation since natural gas typically rises because it is lighter than air, The maximum resulting dynamic overpressure at the reactor building calculated by the licensee under these conditions was 0.45 psig for the Break 2 scenario.
The licensee's submittal of May 3, 1991 provided a consultant's report which stated that an unconfined cloud of natural gas would be expected to deflagrate (burn) and not detonate.
The consultant analyzed the overpressure effects of such a deflagration and concluded that the resultant overpressure would be equivalent to a wind loading of about 67 mph.
Nevertheless, the May 3 submit-tal assumed that detonation did occur producing an overpressure shock wave of 1.0 psig.
(This assumption is quite conservative since it is equivalent to assuming a dynamic load factor greater than 2.0.)
The licensee analyzed the drag ef f ects on the reactor building upper siding resulting f rom this over-pressure and concluded that the siding would not be damaged.
The NRC staff reviewed the assumptions used by the licensee in performing the analyses described in the April 23 and May 3, 1991 submittals and concluded that they were reasonable and appropriately conservative.
The staff acknow-ledges that the possibility of detonation of an unrestrained cloud of natural gas is remote and agrees with the licensee that the dynamic overpressure from a postulated detonation would not damage the reactor building.
In addition to reviewing the licensee's analysis as described above, the NRC staff has performed its own independent calculations which confirmed that flammable gas concentrations would not exist at the reactor building.
The l
staff's independent analysis resulted in a maximum equivalent static pressure of less than 1 psig at the reactor building from postulated detonation of the natural gas-cloud.
Tno staff concludes that these independent calculations are sufficient to provide reasonable assurance of the accuracy of the licensee's more sophisticated calculations which were done with computer codes developed by the Federal Emergercy Management Agency, the U.S. Department of Transporta-tion, and the U.S. Environmental Protection Agency.
Since the FSV spent fuel is now contained in the core and in the spent fuel storage wells, in she staff's judgement, the protection afforded by these massive structures (the prestressed concrete reactor vessel is a reinforced, prestressed concrete structure with 9 foot thick walls and the spent fuel storage wells are steel structures surrounded.by reinforced concrete) is more than adequate to ensure the safety of the speat fuel from hypothetical l
detonations of natural gas released from postulated pipe ruptures.
l One ci several possible methods of cooling both the core and the spent fuel storage wells is with the redundant, safety grade liner. cooling system.
Even if one assumed that the upper reactor building siding was damaged by a postu-lated detonation of natural gas, the liner cooling system components are either located below the refueling deck or are protected from tornado missiles so that they could not be affected by failure of the siding.
In addition, the decay hc3t load from this spent fuel is now so low that both the core and the spent fuel storage wells could go without any cooling for over three weeks
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. before reaching normal operating temperatures.
Even if power or cooling water for the liner cooling system were somehow lost, the licensee would have at least three weeks to repair the damage or, alternatively, could bring in external supplies of cooling water.
The NRC also examined the licensee's interin, solution (closing the 6 inch valve and supplying natural gas to the 16 inch collection pipeline through a 1 1/2 inch bypass line) to ensure that no unacceptable consequences resulted from this configuration.
Reducing the effective pipe diameter would result in a slight increase in the average operating pressure of the collection piping from 130 psig to 155 psig.
Because the high-low valves on each well close at 250 psig, the operating pressure in the collection system would not exceed 250 psig.
All natural gas release rates used in the flammabilty and detonation analyses were conservatively estimated by the licensee to occur at this maximum pressure.
Furthermore, the collection piping is designed to withstand a pressure of 720 psig and has been tested to a pressure of 1080 psig.
Thus the slight increase in operating pressure associated with closing the 6 inch valve will not result in a significant increase in the likelihood of piping rupture.
However, the licensee's March 27, 1991 submittal notes that periodically (about twice a month) the 6 inch valve must be opened in order to perform pipeline maintenance or surveillance activities.
While these activities are ongoing, the licensee has committed that "the 6 inch valve will be contin-uously manned by an operator who he been instructed to promptly close the valve in the event a pipeline ruptu.e is observed or suspected." The licensee has indicated that rupture of-this piping would result in gas escaping at sonic velocity which would create a very loud roar and woLid also create a large cloud of dust.
Thus the operator would be able to both hear and see the presence of a large rupture.
The licensee's March 27, 1991 submittal also stated that closing the 6 inch valve is an interim solution since the pipeline operator wants this valve to be open in the winter months to prevent any possibility of-condensate freezing and clogging up the 1-1/2 inch line.
Because of this concern, the licensee is investigating additional anclyses or the installation of redundant automatic isolation valves as final solutiuns to this problem.
Thc licensee committed to consider the opening of this valve (other than for maintenance or surveil-lance as described above) as equivalent to introducing a new-source of natural gas which will require NRC review and approval of a licensee analysis which demonstrates that such natural gas will not present an unacceptable hazard.
Accordingly, the NRC has included this commitment in License Condition 2.D.(4) established as discussed previously to address possible introduction of new sources of natural gas.
Thus, based on the evaluation described above, the NRC concludes that there is adequate assurance that the presence of the natura.1 gas wells on the Fort St.
Vrain site will not result in an accident with radiological consequences which could cause a significant impact on public health and safety.
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3.0 STATE CONSULTATION
In accordance with the Commission's regulations, the Colorado State official was notified of the proposed issuance of the amendment.
The State official had no comments.
4.0 ENVIRONMENTAL CONSIDERATION
The amendment changes a requirement with respect to installation or use of facility components located within the restricted area as defined in 10 CFR Fart 20.
The NRC staff has determined that this license amendment to a POL allows the 1icensee to make changes to the facil'ty orovided that (1) changes comply with the requirements of 10 CFR 50.59 (that is, no Technical Specifica-tion change or unreviewed safety question for the defueled status of the facility), (2) the change does not foreclose the options or materially affect the cost of decommissioning, and (3) the change does not involve major structural changes to radioactive components of the facility (although the licensee may proceed with some activities such as decontamination, minor component disassembly, and shipment and storage of spent fuel if these activities are permitted by the license and 10 CFR 50,59).
Thus when the POL is issued, the licensee is only required to satisfy the requirements that are appropriate for a r on-operating, defueled facility, and other components that are no longer required may be significantly altered under the POL.
Some non-radioactive coriponents and structures not required for safety in the shutdown condition, ray be remaved and shipped offsite and non radioactive cleaning materials may be disposed of offiste.
However, these do not involve " decommissioning" of the facility (53 FR 24019).
These are activities that the licensee may carry out without NRC approval of a decommis-sioning plan and may be carried out under the existing license.
Consequently, these activities are not associated with this licensing action.
Smaller radioactive components may also be removed ano shipped offsite, provided that such activities do not foreclose alternative decommissioning methods or materially affect the cost of decommissioning.
The direct environmental impacts of such potential activities under the POL are within those previously evaluated in the NRC's August 7, 1972 Final Environmental Statement for operation of Fort St. Vrain.
The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure.
Additionally, there are no special circumstances attendant to this action which would foreclose alternative ways to conduct decommissioning that would mitigate or alleviate some significant environmental impact.
The Commission has previously issued a proposed finding that this amendment involves no sig-nificant hazards consideration, and there has been no public comment on such finding.
Accordingly, this amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).
Pursuant to 10 CFR 51.22(b) no environmental llapact statement or environmental assessment need be prepared in connection with the issuance of this amendment.
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- 5. 0 CONCLUSION The Commission made a proposed determination that the amendment involves no significant hazards consideration, which was published in the federal Register (55 FR 20364) on May 26, 1990.
The NRC has received no requests for liaring and no public comments.
The staff has concluded, based on the considerations discussed above, that
- (1) there is reasonable assurance that the health and safety of the public will not be endangered by maintenance of the facility in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
Principal Contributors:
Deter B. Erickson Richard Dudley, Jr.
Date: May 21,1991 t
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