ML20137A483

SER Re CP&L Review of Power Uprate Process & Commitment Preventing Operation at Uprated Power Levels for Plant, Units 1 & 2

ML20137A483
Person / Time
Site:	Brunswick
Issue date:	03/18/1997
From:	NRC (Affiliation Not Assigned)
To:
Shared Package
ML20137A479	List: ML20137A475 ML20137A483
References
NUDOCS 9703200346
Download: ML20137A483 (11)

Text

. ~ _ _ . . .

44

[ p *t UNITED STATES

5

• ]

2 NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20066-0001 l *s*****/

j EVALMTION OF LICENSEE REVIEW AND CONCLUSIONS CAROLINA POWER & LIGHT COMPANY l

BRUNSWICK STEAM ELECTRIC PLANT. UNITS 1 AND 2

DOCKET NOS. 50-325 AND 50-324

1.0 INTRODUCTION

i i On December 23, 1996, Carolina Power & Light Company (CP&L or the licensee)

provided (Reference 1) the results of a CP&L review (action plan) of its work

processes and products associated with a 5 percent power uprate amendment i issued by the NRC on November 1,1996, for the Brunswick Steam Electric Plant, i Units 1 and 2 (BSEP 1 and 2). The review was initiated in response to l concerns raised both within the NRC staff and the utility regarding the i quality of the amendment submittal following licensee discovery, after amendment issuance, of errors in two assumptions and an acceptance criterion j used in supporting analyses. The analyses affected by the errors predict L suppression pool temperature response during a Station Blackout (SBO) event l and Loss of Coolant Accident (LOCA).

s i

CP&L's review concluded that the power uprate products are sound and support 3 operation at the uprated power level. By commitment, the licensee is awaiting j NRC concurrence with this position before proceeding to the uprated power L level.

I

2.0 BACKGROUND

On November 1, 1996, Amendment Nos. 183 and 214 for BSEP 1 and 2 respectively

. (Reference 2), were issued authorizing an increase in each unit's maximum i

power level from 2436 megawatts thermal (MWt) to 2558 MWt. The amendments

were issued in response to a CP&L application dated April 2, 1996 (BSEP 96-0123) (Reference 3), as supplemented by an earlier letter dated l November 20,1995 (BSEP 95-0535) (Reference 4), and by subsequent letters dated July 1,1996 (BSEP 96-0242) (Reference 5), July 30,1996 (BSEP 96-0287)

(Reference 6), August 7, 1996 (BSEP 96-0300) (Reference 7), September 13, 1996

! (BSEP 96-0340) (Reference 8), September 20, 1996 (BSEP 96-0348) (Reference 9),

l October 1, 1996 (BSEP 96-0362) (Reference 10), October 22, 1996 (BSEP 96-0392) t (Reference 11), October 22, 1996 (BSEP 96-0403) (Reference 12), and i October 29,1996 (BSEP 96-0412) (Reference 13). The licensee planned to

. implement the amendment in early November 1996 on BSEP 1 during the unit's i startup from the then current refueling outage B111RI. The amendment was to be implemented on BSEP 2 no later than the startup from its next refueling i outage, which is currently scheduled for the fall of 1997.

I k

ENCLOSURE 1 O346 970318 i h3] Dock e 05000324 PDR 2

i

I J

l 2

Prior to reaching uprated power levels the licensee identified several

' deficiencies. First, CP&L determined that a non-conservative input assumption had been made in the SB0 event analysis that pre-existed power uprate and that i

thepower of error uprate had been carried on the fonvard into the more recent analysis of the impact 580 event.

i Both analyses assumed an initial suppression pool water temperature of 90*F whereas Technical Specifications (TS) allow a higher suppression pool temperature of 95*F. Second, the licensee determined that an acceptance criterion for maximum suppression pool temperature of 220'F had been used in the 580 and LOCA power uprate analyses;

! whereas TS 5.2.2.b indicates that the suppression chamber design temperature j is 200*F. Third, the General Electric Company i i

performing the bulk of the analyses supportingower p(GE), the was uprate, licensee's not contractor !

j sufficiently familiar with the licensing basis of the facility and selected an inappropriate peak suppression pool temperature as a starting point in determining the impact of power uprate on the BSEP SB0 event.

i j At the time of discovery of the deficiencies it appeared that under uprated power conditions suppression pool temperature could exceed the 200*F i

1 suppression chamber design limit indicated by TS during both an SB0 event and a LOCA. Additional licensee review has shown, however, that the 200*F suppression chamber temperature criterion will not be exceeded for SB0 or LOCA at the uprated maximum power level.

On November 5,1996, immediately after notifying the NRC of the deficiencies  !

and before reaching the uprated power range on BSEP 1 startup, the licensee' l established a 95 percent hold on reactor power (equivalent to the former value for licensed maximum power) and advised the NRC of this decision. During a telephone conference with the NRC on November 14, 1996, the licensee committed to (1) conduct a review for root causes and additional problems and (2) continue the 95 percent power restriction until the NRC was satisfied that the root causes and implications of the issue were understood and appropriate l corrective actions taken. The licensee reiterated these commitments in a letter to the NRC_ dated December 3, 1996.

Reference 1 provided the results of the licensee's power uprate review.

Subsequent to the receipt of Reference 1, the NRC staff raised questions regarding the appropriateness of certain assumptions used in calculating control room dose following a main steam line break (MSLB).

In letters dated January 22, 1997 (Reference 14), February 15, 1997 (Reference 15), and February 28, 1997 (Reference 16), CP&L provided commitments for compensatory actions, where required, and final resolution for the above MSLB issue, for a second issue involving the potential for exceeding control room dose limits during a control rod drop accident, and for deficiencies in the control building heating, ventilation, and air conditioning system.

ENCLOSURE 1

3 3.0 EVALUATION The NRC staff reviewed the licensee's action plan and findings, as described in Reference 1. The NRC staff evaluated the comprehensiveness of the lic.ensee's plan. The NRC staff further evaluated the licensee's resolution of the specific findings discussed in Reference 1, which, as confirmed with the licensee by telephone on December 27, 1996, were the issues identified by the licensee as potentially impacting conclusions reached in either CP&L's power uprate licensing topical report (LTR) (Ref. 4) or in the NRC's safety evaluation (SE) regarding BSEP 1 and 2 power uprate (Ref. 2).

3.1 Action Plan CP&L's action plan addressed the following areas: root cause(s) identification, review for similar issues, determination of reason for late error discovery, determination of suppression chamber design basis, resolution of specific SB0 and LOCA issues, and development of long-term corrective actions. The licensee found two primary causes for the discrepancies initially identified. They were (1) a failure by CP&L to clearly define inputs for calculations and analytical and licensing acceptance criteria, which exacerbated a lack of GE personnel familiarity with the SB0 design basis, and (2) an error by GE in selecting an incorrect peak suppression pool temperature as a starting point in determining the impact of power uprate on the SB0 event. Additional issues were also identified stemming from the same root causes. CP&L's failure to clearly define calculation inputs and acceptance criteria early in the design process was the principal contributor to the delay in identification of the problem. Resolution of specific issues and long-term actions are discussed below.

Specific actions taken to implement the plan included the following: CP&L and GE performed investigations of the process used for the design and implementation of the power uprate modification to identify points where barriers broke down; CP&L completed reviews and certifications of the documents that formed a principal part of the basis for the LTR to ensure proper inputs were used; responsible GE engineers conducted reviews of calculations and Design Basis Documents used in their analyses for similar issues; numerical values provided in the LTR were reviewed against TS, the Updated Final Safety Analysis Report (UFSAR), and the NRC's SE (Ref. 2) to identify discrepancies; CP&L performed an additional review of Emergency Core Cooling System (ECCS), Containment, and Special Event analyses to ensure that the assumptions, inputs, and outputs are consistent with the UFSAR, TS, and power uprate; CP&L responsible engineers have reviewed and certified that inputs to power uprate calculation updates accurately reflect power uprate conditions, TS, and the UFSAR; and CP&L engineers responsible for those systems and programs which are part of the design basis and affected by power uprate have confirmed the consistency between those systems and programs and the design and licensing basis.

Given that the root causes identified by the licensee appear reasonable and the action plan was (1) appropriately self-critical and comprehensive in ENCLOSURE 1

_ _ _ _ _ _ . _ _ _ _ _ _ _ ____.___._______m______

i . .

i 4

i nature and (2) effective in identifying additional deficiencies, the NRC staff j finds the plan (review) acceptable.

3.2 Resolution of Specific Issues 1

1 The licensee has developed resolutions for each of the specific issues

) identified in Reference 1.

The SB0 calculation deficiencies, which provided the impetus for the action i plan, were resolved by refinements to th~e calculation. The same calculation t

methodology was used, but more data points were incor) orated into the decay j heat curve. The licensee stated that incorporating tie additional data points t

into the decay heat curve results in a smoother, more accurate curve showing that less decay heat would reach the suppression pool. The licensee continued l using the American Nuclear Society (ANS) 5.1 standard for modelling decay heat

generation. A second refinement was made in the estimate of water in the l suppression pool at the beginning of the event. This corrected an error

! recently discovered, through CP&L's Improved Technical Specification (ITS)

! conversion project, in the calculation of suppression chamber water volume. A third refinement corrected an error in the original calculation and accounted

for the mass of water entering the suppression pool from the reactor. The NRC j finds the licensee's resolution of SB0 calculation deficiencies acceptable

! based upon the licensee's use of appropriate refinements to the original j calculation which result in the suppression pool temperature remaining below the maximum value allowed by TS of 200*F, even with a higher initial pool i temperature of 95'F. Therefore, the conclusions reached in the NRC SE for i power uprate (Ref. 2) remain valid.

l l The above error in calculation of suppression chamber volume rendered the suppression pool level band required by TS 3.6.2.1 invalid. As described in

! Licensee Event Report 96-15-01 dated December 11, 1996, the licensee has j established administrative controls to properly control suppression pool level

! until a TS change can be processed. The licensee submitted the necessary

! change to the NRC on January 15, 1997. The NRC staff finds the licensee's

! approach for resolution of this error acceptable based upon the temporary j controls in place over suppression pool level and the submittal of a TS

! change.

The LOCA analysis that pre-existed power uprate had determined that suppression chamber temperature would reach 205'F. That calculation was based upon use of the CONTEMPT-PS computer code. The LOCA analysis provided by the licensee in support of the power uprate amendment utilized different computer codes (M3CPT for short-ters and SHEX for long-term containment response). The

! power uprate amendment request estimated that suppression pool temperature i would reach 201*F following a LOCA. The licensee had never recognized, either i prior to power uprate or during the power uprate amendment process, that both

values exceeded the 200*F suppression chamber design limit specified in TS

!- 5.2.2.b. The NRC recognized this as an issue once the licensee had reported the SB0 problems described above. To address the problem, the licensee made a i refinement to the LOCA analysis by incorporating additional data points into i

ENCLOSURE 1 i

i 4

i i

5 j

the decay heat curve to show less decay heat reaching the suppression pool.

! Additional refinements included use of the recently-revised value for i

i suppression chamber water volume and a higher initial drywell temperature (for consistency with ITS analyses). The NRC staff finds the licensee's resolution

) of this LOCA calculation issue acceptable based upon use of appropriate j refinements to the calculation which result in the suppression pool temperature remaining below the maximum value allowed by TS of 200*F.

3 Therefore, the conclusions reached in the NRC SE for power uprate (Ref. 2)

. remain valid.

1 The licensee provided the results of its review to determine the correct value for suppression chamber design temperature. The licensee will submit a TS amendment to the NRC to raise this value to 220*F. That amendment will also

! address other suppression chamber design temperature limits. The NRC staff i finds that this error does not affect the conclusions reached in the NRC SE

] for power uprate (Ref. 2) in that the utility can now show compliance with the 3 more restrictive 200*F value under power uprate conditions.

CP&L identified an error in the power uprate LTR (Ref. 4) wherein the code of

! record for the control rod drive mechanism was incorrectly listed as ".. 1968

Edition up to and including the Winter 1969 addenda." It should have been

, listed as ".. 1968 Edition up to and including the Winter 1970 addenda."

Additionally, the allowable stress reported in the LTR should have been 25,860 psi rather than 26,060 psi. Given that the calculated stress under power

, uprate of 20,790 psi continues to be below the allowable stress, the NRC staff 1

finds that the conclusions reached in the SE for power uprate (Ref. 2) are not impacted by this error.

l i CP&L found that Table 6-3 of the power uprate LTR (Ref. 4) incorrectly

! characterized certain values for condenser temperature rise as State National l Pollutant Discharge Elimination System (NPDES) limits. The NPDES permit i effluent temperature limit pertains to the ocean discharge mixing zone

temperature. Compliance with that limit under power uprate conditions was i evaluated by the licensee in the LTR and by the NRC staff under the

" Environmental Assessment and Finding of No Significant Impact" (61 FR 55673) associated with the power uprate amendment. Therefore, the NRC staff finds

that the conclusions reached in the NRC's environmental assessment for the

{ power uprate amendment are not impacted by this error.

1 CP&L found that the power uprate LTR (Ref. 4) incorrectly stated that standby i liquid control system (SLCS) "...was found to have the capability to deliver i the ATWS [ Anticipated Transient Without Scram] required flowrate of 86 gpm at l the increased reactor pressure..." The ATWS rule (10 CFR 50.62) requires that

! the SLCS provide a flowrate resulting in reactivity control equivalent to

injection of 86 gpm of 13 weight percent sodium pentaborate decahydrate

, solution at the natural boron-10 isotope abundance into a 251-inch inside diameter reactor vessel. The LTR (Ref. 4) should have stated that

BSEP 1 and 2 will continue to meet the ATWS rule requirements by having a

capacity to inject 66 gp

n of 13 weight percent sodium pentaborate solution, which is the equivalent value for the BSEP 218-inch reactor vessels. This

[ ENCLOSURE 1 i

l

I' i

i i

' equivalent value has been accepted by the NRC staff in previous license amendments. Given that the licensee will continue to meet ATWS rule

! requirements for SLCS boron injection, the NRC staff finds that the

! conclusions reached in this subject area in the NRC SE for power uprate (Ref.

2) remain valid.

CP&L identified an increase in Reactor Water Cleanup (RWCU) heat-exchanger j room peak pressure over the previously evaluated result for the High Energy i

Line Break (HELB) event. The peak pressure increased from 18.4 psi to 19.1 I psi. The licensee has determined that the RWCU heat-exchanger room can l withstand the HELB peak pressure increase. Given that the increase in peak pressure can be tolerated, the NRC staff. finds that the conclusions reached in

this subject area in the NRC SE for power uprate (Ref. 2) remain valid.

l CP&L noted that value for reactor vessel volume (21820 cu. ft.) used as an i

input for calculating containment response following a LOCA (for uprated power l

conditions) differed from the value (18670 cu. ft.) listed in the Design Features section of TS (TS 5.4.2). CP&L determined that the higher value used

! in the analysis included an additional volume contribution to account for i feedwater and was a more conservative input assumption for determining l

containment accident response (with the SHEX code) for power uprate. The TS value was used in the CONTEMPT-PS model in the original containment analyses.

Since the more conservative value was used in containment analyses for power i- uprate and this was the analysis considered by the NRC staff for power uprate,

the conclusions reached in this subject area in the NRC's SE for power uprate

(Ref. 2) remain valid.

While the power uprate LTR (Ref. 4) assessed the radiological dose effects of l power uprate for the LOCA, MSLB accident, Fuel Handling Accident, and Control l l Rod Drop accident (CRDA) at the exclusion area and low population boundaries,  ;

it was deficient in only presenting control room doses for the LOCA; however, '

l the MSLB accident is the limiting accident at normal power levels for control i room dose. The licensee, as discussed in References 1 and 14, has completed a  !

! calculation of control room doses following an MSLB showing acceptable j

results, i.e., doses within General Design Criterion (GDC) 19 limits. The NRC i

! staff has raised questions regarding the validity of certain assumptions used l

in the licensee's calculation and in an earlier independent NRC calculation i i for this accident. The key question involves determining the appropriate dillution factor for coolant activity entering the turbine building from the L

i assumed steam line break. Until these questions are resolved, the licensee i has committed (Ref.14) to administrative 1y limit the specific activity of the 4

reactor coolant to less than or equal to 0.1 microcuries/ gram dose equivalent

, 1-131. This has been implemented by a change to a plant procedure (OAl-81,  ;

l' " Water Chemistry Guidelines"). The NRC has verified that this change is in place. The licensee also committed in Reference 16 to provide the results of j a revised analysis of this accident using assumptions more acceptable to the NRC staff by April 15, 1997. Should the final calculation indicate a control i room dose in excess of GDC 19, as committed in References 14 and 15, the 4 licensee will submit a TS amendment appropriately limiting coolant activity.

{ The NRC staff finds that the licensee is providing adequate attention to the i ENCLOSURE 1 i

i-

r-----^-------~-- - - - - --------

! 7 4

i resolution of this issue and that this administrative limit is appropriate i

under uprated power conditions for ensuring acceptable MSLB control room doses while outstanding questions are being resolved. On a related matter the NRC and CP&L determined during the review of power uprate that the existing TS

surveillance requirement for the control room emergency ventilation system

! (CREVS) chtrcoal filter does not test the charcoal under accident conditions, i The licens1e subsequently performed a laboratory test of the charcoal under L accident conditions and satisfactory results were obtained. By Reference 15,

the licentee committed to submit a TS amendment request to correct the j surveillance test by April 30, 1997.

In carrying out the action plan, the licensee identified an error in an accident analysis not directly impacted by power uprate. The affected i analysis is the CRDA at power levels of less than 5 percent. At these low power levels, mechanical vacuum pumps are used to remove non-condensible gases from the condenser, and condenser off-gas bypasses the normal holdup and j filter train and flows directly to the release stack. The existing analysis l ignored an installed automatic isolation function for this pathway and assumed i no isolation of the release path for 10 minutes. It then inappropriately i assumed that dose in the control room would end instantaneously; however,

! under such a scenario, control room dose would actually continue because 3 radioactive gases and particulate activity that entered the control room 5

emergency ventilation system during the release would continue to recirculate

through the control room for some period of time. The licensee believes that i

control room dose under this scenario would exceed GDC 19 criteria. A recent licensee recalculation shows, however, that when credit is given for the j automatic isolation of this pathway on a high stack monitor signal, control i' room doses are acceptable. The inappropriate assumption in the existing

} analysis, i.e., that assumed control room dose would cease at 10 minutes, and

{ the resulting inappropriate conclusion masked the importance of the installed

! automatic pathway isolation function. Based upon the newly recognized

! significance of this function, the licensee satisfactorily tested the i

isolation logic for the function on both units and, by commitment described in Reference 16, will maintain a clearance to prevent operation of the mechanical i vacuum pumps unless all control rods are inserted. By Reference 15 the i licensee committed to upgrade the mechanical vacuum pump trip function to use i redundant, safety-related sensors for actuation. By letter dated

March 5, 1997 (Reference 17) the licensee submitted a revised accident 4

analysis to the NRC reflecting the upgraded trip function and a TS amendment i to incorporate the automatic trip function. Given that this issue concerns I operation at low power levels only and therefore is not directly related to i power uprate, the NRC staff finds that it does not affect the conclusions

! reached in the NRC SE for power uprate j (Ref. 2).

4 l The licensee identified errors in TS Bases for the high pressure coolant

! injection (HPCI) and automatic depressurization system (ADS). For the HPCI j system, the TS Bases do not reflect the operating pressure increase reviewed i and approved by the power uprate amendment. Corrected pages are provided in i Enclosure 2. In the case of the ADS, there is a discrepancy between the TS ENCLOSURE 1 ll s

a ._ - -. .

i i

)'

for the system and its TS Bases regarding allowed out-of-service times. The ADS discrepancy is not related to power uprate and will be corrected during

the ITS conversion. l l The licensee has initiated long-term corrective actions which include (1)

revising the UFSAR and the facility's Design Basis Documents (DBDs) to ensure j that the containment analysis inputs are clearly defined and (2) performing an  ;

evaluation of the verification and validation practices for outsourced j engineering work. Additionally, the licensee will factor the lessons-learned

, from power uprate into the evaluations being performed for the NRC design

' basis information request issued pursuant to 10 CFR 50.54(f) on October 9, 1996. The NRC staff finds that the first two long-term actions are directed at the root causes identified by the licensee and are therefore appropriate. Given that a formal mechanism has been established by the NRC to

ensure the licensee reviews its design basis and the licensee's comitment to

incorporate the lessons learned from power uprate into this review, the NRC

, staff finds the licensee's long-term corrective actions acceptable.

k 4.0

SUMMARY

CONCLUSION h Based upon the NRC staff findings detailed in Section 3.0 above, the NRC staff 4

concludes that the licensee has conducted an acceptable review for additional problems and that, given the actions taken by the licensee to address identified deficiencies, the conclusions reached by the NRC staff in the power uprate SE (Ref. 2) remain valid. The NRC staff, therefore, does not object to

! the licensee's removal of its comitted hold point of 95% power on BSEP 1.

l

5.0 REFERENCES

1. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, December 23, 1996.

i I 2. D. C. Trimble, U.S. Nuclear Regulatory Comission, letter to W. R.

! Campbell, Carolina Power & Light Company, " Issuance of Amendment No.183

To Facility Operating License No. DPR-71 and Amendment No. 214 To 1 Facilitv Operating License No. DPR-62 Regarding Power Uprate,"

i Novem M I, 1996, i 3. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear i Regulatory Comission, "105% Thermal Power Uprate," April 2,1996 (BSEP l 96-0123).

4. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear

. Regulatory Comission, " Power Uprate," November 20, 1995 (BSEP 95-0535).

5. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear

. Regulatory Comission, July 1,1996 (BSEP 96-0242).

1 4 6. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, July 30, 1996 (BSEP 96-0287).

ENCLOSURE 1

1 9 .

i l

7. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear  !

l Regulatory Commission, August 7,1996 (BSEP 96-0300). '

8. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear l Regulatory Comission, September 13, 1996 (BSEP 96-0340),

i j 9. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear j Regulatory Comission, September 20, 1996 (BSEP 96-0348).

10. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, October 1,1996 (BSEP 96-0362).

11. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, October 22, 1996 (BSEP 96-0392).

l

12. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, October 22, 1996 (BSEP 96-0403).

13. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, October 29, 1996 (BSEP 96-0412).

14. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, January 22, 1997 (BSEP 97-0033).

15. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, February 15, 1997 (BSEP 97-0069).

16. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, February 28, 1997 (BSEP 97-0099).

17. W. R. Campbell, Carolina Power & Light Company, letter to U.S Nuclear Regulatory Comission, March 5,1997 (BSEP 97-0012).

Principal Contributors: D. Trimble L. Brown R. Frahm, Sr.

R. Goel J. Hayes D. Shum C. Wu Date:

ENCLOSURE 1

)

3/4.5 EMERGENCY CORE COOLING SYSTEM i

l BASES 3/4.5.1 HIGH PRESSURE COOLANT INJECTION SYSTEM j RACKGROUND:

The High Pressure Coolant Injection

! driven turbine-pump unit, piping and valvesto(HPCI) system provide steamconsists of a ' steam to the turbine, i

and piping and valves to transfer water from the suction source to the core via the feedwater system line where the coolant is distributed within the reactor vessel through the feedwater sparger. Suction piping for the system 4

is provided from the condensate storage tank (CST) and the suppression pool.

Pump suction for the HPCI system is normally aligned to the CST source to minimize injection of suppression pool water into the reactor vessel.

However, if the CST water supply is low or if the suppression pool level is

high, an automatic transfer to the suppression pool water source assures a j

water supply for continuous operation of the HPCI system. The steam su> ply to

{

the HPCI system turbine is piped from the main steam line upstream of tse

' associated inboard main steam line isolation valve.

The HPCI system is designed to provide core cooling at reactor pressures between 1164 psig and 150 psig. Upon receipt of an initiation signal, the I j HPCI system turbine stop valves and turbine control valves open risultaneously

! and the turbine accelerates to a specified speed. As the HPCI system flow j increases, the turbine governor valve is automatically adjusted to maintain design flow. Exhaust steam from the HPCI system turbine is discharged to the i suppression pool. A full flow test line is provided to route water from and i

to the CST to allow testing of the HPCI system during normal operation Mthout

injecting water into the reactor vessel.

i The High Pressure Coolant Injection system (HPCI) is provided to assure that the reactor core is adequately cooled to limit fuel cladding temperature in the event of a small break in the nuclear system and loss of coolant which j does not result in rapid depressurization of the reactor vessel. The HPCI j system permits the reactor to be shut down while maintaining sufficient l reactor vessel water level inventory until the vessel is de>ressurized. The HPCI continues to operate until reactor vessel pressure is i>elow the pressure 4

! at which Low Pressure Coolant Injection (LPCI) system operation or core spray j system operation maintains core cooling.

1 i APPLICABILITY:

The HPCI system is required to be OPERABLE during OPERATIONAL CONDITIONS i 1, 2, and 3 when there is considerable energy in the reactor core and core i cooling would be required to prevent fuel damage in the event of the break in i the primary system piping. In OPERATIONAL CONDITIONS 1, 2, and 3 when reactor i steam done pressure is less than or equal to 150 psig, the HPCI system is not i

required to be OPERABLE because the low pressure ECCS systems can provide j sufficient flow below this pressure.

I 3

1 1

4

)

3 REVISED BY NRC LETTER DATED l March 18, 1997

{ BRUNSWICK - UNIT 1 B 3/4 5-1 i - _ __

2 i

3/4.5 EMEncrNCY CORE COOLING SYSTEM j RASES l

{

3/4.5.1 HIGH PRESSURE C0OLANT INJECTION SYSTEN l

j RACKGROUND:

1 i The High Pressure Coolant Injection i

driventurbine-pumpunit,pipingandvalves(HPCI)systemconsistsofastaan to provide steam to the turbine, I and piping and valves to transfer water from the suction source to the core j

via the feedwater system line where the coolant is distributed within the j

reactor vessel through the feedwater sparger. Suction piping for the system

' is provided from the condensate storage tank (CST) and the suppression pool.

4 Pump suction for the HPCI system is normally aligned to the CST source to minimize injection of suppression pool water into the reactor vessel.

j However, if the CST water supply is low or if the suppression pool level is j high, an automatic transfer to the suppression pool water source assures a a

I water supply for continuous operation of the HPCI system. The steam supply to the NPCI system turbine is piped from the main steam line upstream of the associated inboard main steam line isolation valve.

l The HPCI system is designed to provide core cooling at reactor pressures between 1164 psig and 150 psig. Upon receipt of an initiation l~

signal, the HPCI system turbine stop valves and turbine control valves open i

simultaneously and the turbine accelerates to a specified speed. As the HPCI system flow increases, the turbine governor valve is automatically adjusted to i maintain design flow. Exhaust steam from the HPCI system turbine is i

discharged to the suppression pool. A full flow test line is provided to i

route water from and to the CST to allow testing of the HPCI system during normal operation without injecting water into the reactor vessel.

The High Pressure Coolant Injection

! assure that the reactor core is adequatelycooled (HPCI)tosystem is provided limit fuel cladding to j temperature in the event of a small break in the nuclear system and loss of

' coolant which does not result in rapid depressurization of the reactor vessel.

The HPCI system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurized. The HPCI system continues to operate until reactor pressure is below the pressure at which Low Pressure Coolant Injection operation or Core Spray system operation maintains core cooling. (LPCI) system l APPLICABILITY:

l

! The HPCI system is required to be OPERABLE during OPERATIONAL i CONDITIONS 1, 2, and 3 when there is considerable energy in the reactor core

and core cooling would be required to prevent fuel damage in the event of a j break in the primary system pipinfl. In OPERATIONAL CONDITIONS 1, 2, and 3 i when reactor steam done pressure < s less than or equal to 150 psig, the HPCI i

system is not required to be OPERABLE because the low pressure ECCS systems j' can provide sufficient flow below this pressure.

i "

i i

i REVISED BY NRC LETTER DATED March 18, 1997

! BRUNSWICK - UNIT 2 B 3/4 5-1

. - . ~ . _ - _ . . . - _ _ - . - . - - . _ . . . . .

DISTRIBUTION:

" Docket' File, PUBLIC PDII-1 Reading File S. Varga J. Zwolinski G. Hill (4)

C. Grimes, DOPS/0TSB ACRS OPA OC/LFDCB C. Berlinger R. Emch R. Frahm, Sr.

G. Hubbard R. Jones L. Marsh J. Wermiel R. Wessman R. Goel M. Hart D. Shum C. Wu C. Patterson M. Shymlock cc: Brunswick Service List i

i