ML19290E154
| ML19290E154 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 12/31/1979 |
| From: | NORTHERN STATES POWER CO. |
| To: | |
| Shared Package | |
| ML19290E143 | List: |
| References | |
| NUDOCS 8003040426 | |
| Download: ML19290E154 (13) | |
Text
.
The following changes, tests or experiments have been completed under the provi-sions of 10 CFR 50.59 (a) (1):
A.
Unit 1 and Common Components 1.
Unit 1, Cycle 5 Reload (Design Change 78L444)
The safety evaluation for Unit 1, Cycle 5 demonstrated that the core re-load will not adversely affect the safety of the plant.
Prairie Islar.d Unit 1 will operate in Cycle 5 with one region of fuel supplied by Exxon Nuclear Company (ENC).
The composition of the core will be 40 ENC assemblies (3.4 w/o U-235) and 81 partially e, ent West-inghouse assemblies.
Included is a Gadolinia Demonstration Program with 64 fuel pins containing I w/o gadolinia which are uniformly dispersed among sixteen fuel assemblies.
Exxon fabricates fuel assemblies which are identical to Westinghouse as-semblies in envelope dinansions, number of fuel rods, location and size of top nozzle holes and control rod guide thimbles. Principal differences include:
Grid Design - Exxon uses a Zircaloy grid with Inconel springs, whereas a.
Westinghouse assemblies have all Inconel grids. Zircaloy grids pro-vide better neutron economy, but are more susceptible to stress or radiation-induced relaxation.
b.
Clad thickness - Exxon uses a thicker Zircaloy clad, 30 mil clad, 237.
thicker than for Westinghouse fuel.
Pellet diameter - Because of the thicker clad, Exxon's pellet is c.
smaller in diameter than for the Westinghouse fuel.
d.
Pellet length to diameter ratio (L/D) - Exxon has an L/D ratio less than for Westinghouse.
The advantage of a lower L/D ratio is that it reduces th- 'ropensity for fuel rod bow due to pellet cocking.
Top nozzle - Exxon provides a removable top nozzle, to allow individual e.
rod replacement.
The following is a summary of the analysis performed in support of operation for Unit 1, Cycle 5:
Emergency Core Cooling System (ECCS) Analysis 2xxon has evaluated the Loss of Coolant Accident (LOCA) for a core composed of all Exxon fuel. The limiting break (as is the case with the Westinghouse analysis) is the double-ended cold-leg pipe guillotine break with a dis-charge coefficient of 0.4 (0.4 DECLG). The effects of upper plenum injection (UPI) were accounted for and result in a l'F it crease in peak clad temperature (PCT). Also accounted for in the analysis are t he effects of fuel rod ex-posure, uncertainties in fuel rod internal pressure, the enhanced fission gas release model, and code modifications and updates. The analysis shows that margin exists between the calculated PCT and the limiting PCT of 2200*F with an Fq limit of 2.21 up to 27,000 MWD /MTU peak pellet burnup. The peak pellet burnup during Cycle 5.will be less than 24,000 MWD /MTU. The results 40 7 {
of the ECCS analysis for the 0.4 DECLG break along with a comparison of Westinghouse results are given below.
Exxon (BOL)
Westinghouse Starting power level (%)
102 102 Total core peaking factor F 2.21 2.28 q
Peak Clad Temp.
(
- F) 2176 2179 Location (ft) 8.75 7.5 Maximum local clad / water reaction (%)
7.0 7.8 Location (ft) 9.0 7.5 Hot rod burst time (sec) 35.0 25.8 Location (ft) 6.0 5.75 Plant Transient Analysis Several plant transients were analyzed by Exxon based on an equilibrium Exxon fueled core.
The analysis is valid for an Fq of 2.32.
The follow-ing is a summary of each of the analyses.
Fast Control Rod Withdrawal This transient is initiated f rom 102% power and the reactor is assumed to be tripped by nuclear overpower at 118% wie a 0.5 sec delay time.
The rod withdrawal rate used was 100 pcm/sec.
Results show minimum DNBR of 1.97, RCS pressure increases by 9 psi, and core average temperature increases by less than 2*F.
Slow Control Rod With6awa_1 This transient is initiat ed from 102% power using a withdrawal rate of 2.5 pcm/sec.
The transient is terminated by overtemperature AT or overpower AT which is reached at 3i sec after the start of the transient.
Rod in-sertion is assumed to be delayed by 6 sec.
Results show power increases to 112%, RCS pressure inc reases by 59 psi and the minimum DNBR is 2.03.
Loss of Reactor Coolar.- Tlaw The case analyzed was the less of power to both RCP's from 102% power.
BOL values were used and the trip was assumed to occur from low flow.
Re-sults show a minimum DNBR of 1.87 and RCS pressure increases by 26 psi.
Locked Pump Rotor In this transient, the instantaneous seizure of one RCP from 102% power, the effects of pressurizer spray and power-operated relief valves were ignored. A]so steam dump to the condenser was not allowed and the feedwater pumps were assumed to trip with the reactor.
The reactor is assumed to be tripped by a low flow signal with a resulting minimum DNBR of 1.09, with Tavg increasing by 13*F and RCS pressure increasing by 57 psi.
The number of fuel rods expected to experience DNB is calculated to be less than 1%.
Loss of External Electric Load This transient, the complete loss of load, assumes a reactor trip does not result from the turbine trip, and that pressurizer spray and power-operated reliefs are inoperative. Also condenser steam dump and automatic reactor
control are assured to be inoperative. The criteria for this transient are that the pressurizer safeties limit pressure to 110% of design and there a
will be no PNE.
Results show the reactor is tripped on high pressure at 13 sec wiv.. a peak pressure of 2537 psia.
The pressurizer safetit s open from 15.3 to 17.5 sec.
The RCS temperature increases by 23*F and minimum DNBR is.~.i5.
Steamline Break This transient is analyzed from hot zero power end-of-life conditions. The most reactive RCCA is assumed stuck out of the core and minimum capability (i.e., one pump available) of the SI system. Low pressurizer pressure and level was used as the initiating signal for SI.
The analysis was done for a b re ak at the exit of the steam generator (600% rated flow) with offsite power available and a 10 second delay in the start of the SI pump.
Results show a return to criticality at about 10 see with a peak power of 52% at 56 see when borated water from SI reaches the core. The minimum DNBR was 1.35.
For a small steam line break the core does not return to criticality.
Other Transients The following transients: Startup of Inactive Loop, Feedwater System Mal-
' functions, Excessive Load, and Loss of AC Power result in a reduction in MDNBR from steady state conditions. However, they were not reanalyzed be-cause they did not result in as large MDNBR changes as in the original analysis and would not be limiting for an Exxon-fueled core either.
Safety Analysis The Cycle 5 core will consist of 81 partially spent Westinghouse-supplied fuel assemblies and 40 fresh Exxon assemblies (3.40 w/o U-235) containing 64 pins with I w/o gadolinia distributed among 16 assemblies-The reac-tivity coefficients of Cycle 5 are bounded by the coefficients used in the safety analysis and are applicable for a Cycle 4 length of 10,900
-600/+200 MWD /MTU. Actual Cycle 4 length was 11,097 MWD /MTU.
Cycle 5 length is projected to be 11,300 MWD /MTU with 10 ppm of boron.
Analysis shows acceptable peaking factors with the use of PDC-II method of power distribution control, and adequate shutdown margins. The moderator temp-erature coefficient is predicted to be +1 pcm/'F at HZP-ARO-BOL; however, the isothermal temperature coefficient is predicted to be negative.
The BOC worth of gadolinia poison is predicted to be equivalent to the worth of 65 ppm boron and the effects of gadolinia will disappear by mid-cycle.
Analysis shows no penalties are required for the effects of gadolinia or rod bow.
The results of the rod ejection transient shows energy deposi-tion in the fuel pellet of less than 130 cal /gm which is less than the 280 cal /gm stated in Reg. Guide 1.77.
Startup and Operating Analysis shows all physics parameters to be within acceptable limits and consistent with previous data.
2.
Part Length Rod Removal (Design Change 79L511)
The four part length rod assemblies were removed from Unit 1 and replaced with thimble plug assemblies. The potential for undesirable core trans-ients prevented the use of the part length rod assemblies. Anti-rotational devices were installed on the drive units to hold them out of the core.
The following analysis support the modification:
a.
Thermal Effects Physics analysis, as well as incore monitoring, indicates that there will be no adverse effect of the plug assemblies on the core power dis-tribution. Since the plugged fuel assemblies have no adverse effect on the design core flow distribution, calculated core thermal margin will be unaffected.
b.
Hydraulic Effects Hydraulic aspects were considered with respect to the installation of the thimble plug assemblics.
Since the plug assemblies are already ex-tensively used in existing fuel assemblies with no adverse effects, it can be concluded that there will be no adverse effects from the instal-lation of these additional thimble plugs, c.
Neutronic Effects The removal of part length rods has no impact on any physics infcrmation generated in the past for Prairie Island Units No.1 and 2.
The use of part length RCCA's has been prohibited by Technical Specifications and they have been locked in the full out pocition during operation. The installation of thimble plug assemblies will have no influence on the physics characteristics of the reactor. The lowest position of the plug assemblies will not be within several inches of the top of the fuel.
Therefore, operation with installed plugs will not invalidate any of the physics parameters.
d.
Accident and Transient Analyses Based on foregoing discuseion, the following conclusions relating to accident and transient analyses can be reached.
1.
Impact on Probability of Occurrence A potential safety concern is that the probability of some event previously analyzed can be increased due to the replacement of PLRCCA's with thimble plug assemblies. No information exists which suggests that the replacement of PLRCCA's with thimble plug as-semblies increases the probability of any event previously analyzed.
2.
Other Malfunctions Not Previously Analyzed No information exists which suggests that the replacement of PLRCCA's with thimble plug assemblies introduces a possibility for an ac-cident or any malfunction of a different type than those previously an alyze d. Hence, it is concluded that the replacement of PLRCCA's with plugs does not introduce the possibility of events not pre-viously analyzed.
3.
Margin of Safety It is evaluated that the consequences of replacing the PLRCCA's with thimble plug assemblies does not reduce the margin of safety, as defined in-the bases for applicable technical specifications.
4.
Summa ry The probability of occurrence of events has not increased and the consequences of these events remain within those reported in pre-vious analyses.
The possibility of other types of accidents or malfunctions has not increased. Hence, the information presented in this report leads to the conclusion that operations of Prairie Island Units with the thimble plug assemblies instead of PLRCCA's does not present any danger to the health and safety of the public.
3.
Safety Injection Initiation Fodifications (Des ign Change 79L527)
This design change replaces the present prer urizer loc pressure-low level SI actuation with a 2/3 pressurizer low pressure only logic. This change will equal or better present SI response to all breaks affecting the pres-surizer.
The basis for this modification utilizes three of the four existing pres-surizer pressure channels for safety injection actuation and two of the four channels for control system functions.
Control and protection re-quirements set forth in IEEE-279, are addressed by interlocking two separate pressure control channels such that a single pressure transmitter failure will not cause power operatee relief valve actuation.
The remain-ing heater control and pressurizer spray valve control system functions are not interlocked since inadvertent actuation does not require safeguards actuation.
All current ECCS analyses are valid and appropriate for plants with safety injection initiation as a f unction of pressurizer pressure signals only, which previously had safety injection initiated on coincident pressurizer pressure and level signals. The ef fect of changing to a pressure only signal will result in either an earlier initiation of safety injection, or no change in the time of safety injection initiation for all break locations.
For a small break located in the pressurizer, the pressure only signal would assure that it is initiated. For the worst small breaks, which are cold leg breaks, currently existing small break analysis assumptions con-cerning safety injection initiation time are appropriate. Additionally, the effect of safety injection initiation time on peak clad temperature is negligible when initiation times being considered correspond to RCS pressures above 1400 psia. The svitch to a pressure only safety injection signal results in a negligible impact on large break analyses.
4.
Containnent and Auxiliary Building Cooling (Design Change 76Y002)
This modiff. cation, when completed, will provide cooling for Unit 1 and 2 containment and the Auxiliary Building. New liquid chiller units will provide the cooling utilizing new CRDM shrouds, existing FCU's, existing unit coolers, new unit coolers, ventilation duct coil units, and modifi-cations to duct work.
The system is not yet in service but approximately 350 square feet of galvanized metal is installed in Unit 1 containment which contributes 26.6 cubic feet (1st day) and 0.46 cubic feet (thereaf ter) of hydrogen.
The volume increase is <0.0025 percent. This contribution along with contributions due to other modifications in Unit 1 containment (cal-culated from H2 Generation in Containment Log Book) does not signifi-cantly increase the post LOCA hydrogen content as determined in the FSAR.
5.
Turbine 011 Lif t System (Design Change 79L541)
This design change added the bearings 1 and 2 to the turbine oil lift system. This fix was necessary to eliminate bearing wipe on coast-down and turbine startup. The replacement pump required a larger motor (15 H.P. to 30 H.P.).
The effect of this increase on the emergency diesel generator was analyzed.
Motor #122-28 is fed from MCC 1AA2 which is fed from MCC 1A2 via Bresker
- 122-4 rated at 225A.
Bus ampacity must be greater than or equal to the full load current rating of all motors on the bus plus 25% of the highest rated motor on the bus (NEC 430-24).
The proposed loading on MCC lAA2 is as follows:
Motor #
Load 1H; FLA 122-1 1 Turning Gear Oil Pump 50 59 122-2 1 Turning Gear 40 52 122-3 11 Turbine Gen Air Side Seal Oil Backup Pmp 20 26 122-12 1-2 Turbine Bldg C1g Wtr Hdr Bypas, Valve
.66 2.3 122-28 11 Turbine bil Lift Pmp 30 36.5 100% FLA + 25% largest FLA = (59 + '2 + 26 + 2.3 + 36.5) +.25(59)
= 190.55A ' 225A Bus capacity The worst case load (190.55A) is less tht a bus capacity (225A). Therefore, there is no additional hazard to equipment or personnel resulting from this design change.
6.
Hot Leg Loop B Sample Line Modification (Design change 77L441)
This design change removed 160 feet of 3/8" tubing from the B loop primary sample line that comprised the delay coil. The elimination of the delay coil removed a crud trap and reduced a high radiation field. The decay of N-16 is still effective without the delay coil because of the long sample line to the sample sink.
Radiation levels at the sample sink did not increase.
7.
Classify Equipment Heat Removal System as Non-Safety Related (Safety Eval-uation #28)
The purpose of the unit coolers is to remove heat from the various locatit as which house equipment that is required to operate during emergency plant conditions. Specifically, the unit coolers in question cool the following equipment :
a.
Auxiliary feedwater pumps b.
Component cooling water pumps c.
Safety injection pumps d.
Containment spray pumps
A study was conducted to determine if the unit coolers must function during such emergencies in order for the listed equipmenc to perform its expected safety function.
The ability o' the pumps to continue operating if the unit coolers fail is dependent upon the continuing operation of the pump motors. Motors are purchased sith a class of insulation specified.
Insulation life, and, therefore, zotor life, is dependent upon the motor temperature.
This study assumed the cooJars were not working during the emergency and calculated the resulting higher ambient temperatures. Based upon these temperatures, decreases in motor insulation life were calculated. Results indicate that after 40 years, only the component cooling pump may fail to operate.
In this case, replacement or rewinding of the component cooling pump motor (s) af ter 37 years is recommended. With this procedural modifi-cation, the conclusion is that the unit cooler system can be classified as a non-safety system.
8.
QA Reclassification of Selected Cooling Water Lines (Safety Evaluation #35)
Equipment heat removal coolers were determined not to be necercary for safe operation of safety equipment. The supply and return piping and associated equipment from these unit coolers can be reclassified as non-safety related QA Type III.
This is justified based on the study conducted under safety evaluation #28 and the design criteria which allow a 5" diameter break in the cooling water system without jeopardizing the ability to supply the cooling water required for safeguards operation.
The 24" cooling water return header sections from the Aux /Turb wall to the first elbows outside this wall can also be reclassified as non-safety re-lated QA Type III.
This is justified because this piping is isolated during emergency conditions and no safety related lines penetrate this section of piping.
9.
_S.I. Low pressure Only One Channel only (Safety Evaluation #39)
NRC IE Bulletin No.79-06A of April 14, 1979 directs facilities that use pressurizer water level coincident with pressurizer pressure for automatic initiation of safety injection to trip the low pressurizer level setpoint bistables such that, when the pressurizer pressure reaches the low setpoint, safety injection would be initiated regardless of the pressurizer level.
placing all pressurizer low level bistables in trip would yield a one-out-of-three coincident safety injection on low pressure.
It is felt that this approach would present an undesirable risk for spurious safety injection through testing error, inverter failure or in general, any instrument failure that would result in loss of one pressurizer pressure channel.
A spurious safety injection is undesirable from the standpoint of the transient and automatic actions it causes which could seriously hamper a normal recovery.
Specific concerns are feedwater isolation and isolation of the reactor coolant pump seal return lines.
Feedwater isolation re-moves the normal source of core cooling following a reactor trip. Loss of reactor coolant pump seal return puts undue stress and pressure perturbations on seals and could ultimately lead to premature seal failure and a loss of coolant accident.
A preferable approach to placing all pressurizer level channels in trip is to place only 1 level channel in trip. This would significantly reduce the likelihood of a spurious safety injection and still provide automatic actuation on loss of pressure regardless of level. The approach would be used as an interim measare until the completion of a two-out-of-three co-incident safety injection on low pressurizer pressure design change.
Placing one level channel in trip would afford only single channel loss of precoure protection. However, the operational history and confidence in pressurizer pressure instrumentation is very gocd and it is extremely un-likely that the channel would f ail to perform if required. Additionally, Special Order No. 172 requires that safety injection be manually initiated whenever 2 pressurizer pressure channels indicate below 1815 psig regard-less of pressure level. The remaining two pressure / level channels will also be in service.
During routine testing the level bistabic will be removed from the tripped mode at the start of the test and returned to the tripped mode following completion of the test.
Note that the associated status light and the
" Pressurizer Low Level SI Channel Alert" annunciator will be on.
10.
S.I. on 1 out of 3 Low Pressure (Safety Evaluation #40)
NRC IE Bulletin, No.79-06A of April 14, 1979, directs facilities that use pressurizer water 2evel coincident with pressurizer pressure for automatic initiation of safety injection to trip the low pressurizer level setpoint bistables such that, when the pressurizer pressure reaches the low setpoint, safety iajection would be initiated regardless of the pressurizer level.
This rer,uirement will be accomplished by manually tripping the pressurizer water ?.etel bistable trip switches on the test panels in the protection racks that input to the safety injection actuation logic (LC426B, LC427C, LC428E). This will result in safety injection actuation on one-out-of-three pressure signals. Note that the associated status lights and the " Pres-surizer Low Level SI Channel Alert" annunciator will be on.
During the monthly Analog Protection Functional Test SP 1003 (2003], the level bistables will be removed f rom the tripped mode at the start of the test and returned to the tripped mode following completion of the test.
This is felt to be a more desirable approach during testing than placing only the associated level channel in the untripped mode as recommended by Westinghouse NSD letter of April 16,1979 (NSP-79-533) concerning the IE Bulletin. The duration of the test is 12-16 hours per month.
11.
Natural Circulation Test (Safety Evaluation #41)
Demonstration of the plant's natural circulation capabilities is being done for operator training. This is to familiarize operators with the parameters which occur during natural circulation.
Natural circulation has been reviewed in the FSAR under the analyses for the Loss-of-Flow Accident (for the initial coastdown) and the Station Blackout (for subsequent operation). The Loss-of-Flow and Station Black-out analysis data was verified by the Plant Preoperational Tests. Also data from Beaver Valley Station station-blackout which occurred at 100%
power has been compared against our pre-op data and in very similar.
Since natural circulation has been reviewed in the FSAR, tested during
preoperational testing, and compared against experiences of other plants, this test does not affect the safety and health of the general public.
12.
Operating with Low First Stage Turbine Pressure (Safety Evaluation #42)
Due to the recent turbine blade failures on Unit 1 HP turbine, it is necessary to operate with these blades removed (all blades between control stage and #5 FW heaters extraction zone). This turbine condition will change the relationship between 1st stage pressure and reactor power (%).
The output of both 1st stage pressure transmitters is calibrated in %
power. The relationship between 1st stage pressure and power is linear.
Because the 100% lst stage pressure will be reduced with HP turbine blades removed, it is necessary to re-span the 1st stage pressure trans-mitters to reflect 100% power accurately for the " modified" turbine con-dition.
Information supplied by Westinghouse Steam Turbine group calculates the 1st stage pressure at 100% power to be 294 psig (fermerly 492 psig).
By re-spanning ist stage pressure transmitters' output to reflect this, the transmitters ' output (in % power) will not change with respect to turbine or reactor power.
Parameters controlled or af fected by 1st stage pressure channels and as-sociated signals are:
PT 485: Permissive P7 Steam Generator Level - Level Setpoint Steam Dump " Load Rej. Control" Tavg/ Tref Rod Insertion Limit Rod Control PT 486: Permissive P7 Steam Dump (Loss of Load)
If calibrated 1st stage pressure span is greater than actual, (i.e., cal.
of 294 psig where actual is say 284 psig) permissive P7 and steam dump control will be less conservative, but block of Auto Rod withdrawal, rod control of Tavg and associated overpower setpoints will be more conserva-tive.
Effects on steam generator 1cvel and rod insertion limit (alarm only) will be negligible.
If calibrated 1st stage pressure span is less than actual, the opposite of above is true.
Therefore it is necessary to verify 1st stage pressure calibration during start-up as follows:
PT 485 & PT 486 will be calibrated according to Westinghouse criteria a.
before startup.
b.
A Tavg vs. % NIS power curve will be submitted to operators before startup with instructions to maintain Tavg within 1-1/2*F of curve.
Operators will use manual rod control if necessary, Calorimetrics will be run at various power levels while coming up to c.
full power.
First stage pressure will be plotted against actual reactor power.
d.
First stage pressure channels will be re-spanned at power if necessary based on the results of Step c (or if operators are re-quired to go to manual rod control).
Because re-spanning 1st stage pressure transmitters will keep the relation-
ship between 1st stage pressure transmitter output (% power) and reactor power the same, this change presents no safety hazard to the general public and presents no unreviewed safety concern.
B.
Unit 2 Components The following changes and evaluations which were discussed in Section A, Unit 1 and comm:;n components, are also applicable to Unit 2.
A3 D.C. 79L527 A6 D.C. 77L441 A7 S.E. #28 A8 S.E. #35 A9 S.E. #39 A10 S.E. #40
REPORT OF CHANGES TO THE NSP OPERATIONAL QUALITY ASSURANCE PLAN Northern States Power Company (NSP) submitted its Operational Quality Assurance Plan, Rev 2, to NRC Division of Operating Reactors for review by letter dated November 22, 1977. A letter from D K Davis, NRC Operating Reactors Branch #2, dated December 29, 1977, stated that the Operational Quality Assurance Program, Rev. 2, is acceptable for the operations phase of the Monticello and Prairie Island Nuclear Generat ing Plant s.
By letter dated June 27, 1978, NSP submitted its Operational Quality Assurance Plan, Rev. 3, to the Director, Of fice of Nuclear Material Safety and Safeguards (with copy to Division of Operating Reactors).
Revision 3 incorporated Quality Assurance requirement s for the use of packages for transport of radioactive materials, pursuant to 10 CFR 71.51, and included minor editorial, organization and title changes. A letter from the NRC Transportation Branch, Division of Fuel Cycle and Material Safety, dated April 2, 1979, transmitted Quality Assurance Program Approval for Radioact ive Packages, No. 0083, Rev. O.
Revision 4 to the NSP Operational Quality Assurance.'lan was internally re-viewed and approved on Jans.ry 24, 1980.
We have concluded that the changes do not decrease the ef fectiveness of NSP's Operational Quality Assurance Program.
Although the changes became ef fect ive in 1980, a summary of the changes is included with this report of 1979 changes, tests and experiments for convenience and more t imely document at ion.
Copies of the Operational Quality Assurance Plan, Rev 4, are available at the Monticello and Prairie Island Nuclear Generating Plants and at the NSP corporate of fice for review by IE-III personnel.
Summary of Changes 1.
Page 1; NSP Fire Protect ion Program Outline has been added to Section 1.0 to provide a basis for incorporating fire protection QA requirements into the Operational Quality Assurance Program.
2.
Page 2; ANSI N 45.2.9 has been deleted.
Record requirements have been explicitly identified in Section 19 and Section 5.
3.
Page 2; Changed commitment to the current revision of ANSI N 45.2.12.
4.
Page 3; Revised the exceptions to ANSI N18.7-1976.
Eliminated environmental monitoring since it is not a safety-related act ivity.
Referenced the section of the Q.A. plan that explicity identifies records management.
5.
Page 4; Revised the exceptions to ANSI N18.7-1976.
Provided explicit references to the sections of the Operational Quality Assurance Plan or the Construct ion Quality Assurance Program with regard to various 5.0 subsect ions of ANSI N18.7-1976.
. 6.
Section 2.0; Full implementation of the Operational Quality Assurance Programs was changed from " Commercial Operation" to " sat isf actory com-pletion of the pre-operational and startup test program" Commercial Operation" is not an easily identified point in plant history.
7.
Sect ion 3.0; Numerous changes were made in this section due to NSP organiza-tional changes including the following:
(a) Promotion of the General Manager Power Production to Vice Pres ide nt Power Product ion (the Vice President Power Production report s to the Executive Vice President - D W Angland).
(b) Trans fer of Nuclear Support Services to Power Production.
(the Manager Nuclear Support Services reports to the Vice President Powe r Product ion).
(c) Transfer of Supplier Inspection responsibility from the Plant Er:gineering & Cons truct ion Department to the Quality Assurance Section of Power Production.
(d) Promotion of the Plant Quality Engineer to Superintendent Quality Engineering (the Superintendent Quality Engineering reports to the Plant Manager).
8.
Sect ion 4.2; The Power Production & System Operation Level of the Program has been deleted due to reorganization.
The requirements associated with the following organizations will be incorporated into the Corporate Level Administrative Control Direct ives :
(a)
Maintenance & Testing Department (b)
System Operat ion (c)
Fuel Supply 9.
Page 30; The Spent Fuel Bridge Crane has been added to Table 4-2 (Item 18).
10.
Section 5.2.2; The responsibility for major modifications has been assigned to the Plant Engineering & Construction Department, (PE&C).
Such modifica-tions are required to be performed in accordance with the provision of the PE&C Quality Assurance Program.
The required provisions of the PE&C Quality Assrance Program are id e nt i fied.
11.
Section 7.5; Inspection Procedures have been added to the list of required procedures.
12.
Sect ion 9.2 ;
The applicable elements associated with vendor's Quality Assurance Programs have been changed from 10CFR 50 Appendix B to ANSI N 454.2-lC 76 to establish program consistency.
13.
Sect ion 11.2; Brazing has been added.
- 14.
Sect ion 12; This section has been revised to explicitly identify the ins pect ion program-The intent is to explicitly identify the scope of the inspection program in a manner consistent with the inspection require-ments of ANSI N 18.7 - 1976.
15.
Sect ion 13.2 ;
Inservice Inspection function testing of pumps and valves has been added.
16.
Sect ion 16.4; Independent verification of safety tagging has been added.
17.
Sect ion 16.6; Independent verification of bypasses and requirements asso-ciated with fire protect ion bypasses has been added.
18.
Section 19; The following changes have been made:
(a) Record retention periods have been added.
(b) Becords management requirements have been added.
19.
All Sect ions; The references included in each section have been deleted.
The Administrative Control Directives and Administrative Work Instructions utilized to implement the requirements of the Operational Quality Assurance Plan will be identified in the index required by Section 4.8.