ML17214A541

Startup Test Rept.

ML17214A541
Person / Time
Site:	Saint Lucie
Issue date:	09/30/1983
From:	FLORIDA POWER & LIGHT CO.
To:
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ML17214A542	List: ML17214A541 ML17301A063
References
NUDOCS 8311030084
Download: ML17214A541 (289)

Text

83i1030084 83iiOi PDR ADOCK 05QOOSB'P l~

P PDR FLORIDA POWER AND LIGHT COMPANY ST. LUCIE NUCLEAR POWER PLANT UNIT 2 DOCKET NO. 50-389 LICENSE NO. NPF-16 STARTUP TEST REPORT SEPTEMBER, 1983

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TABLE OF CONTENTS I I SECTION PAGE 1 INTRODUCTION AND

SUMMARY

1-4

2. INITIAL FUEL LOAD 5-10

3. PRECRITICAL TESTING 1 1-12 a) RCS Flow and Flow Coastdown 13-14 b) CEDM Perf ormance 15 c) Incore Instrumentation Checkout 16 d) Pressurizer Spray Effectiveness 17 e) RCS Leak Tightness 18 f) Plant Chemical and Radio Chemical Analysis 19-20 g) Wide Range Nuclear Instrumentation Reading 21 h) Loose Parts Monitor 22 i) Reactor Protection System 23 j) Temporary Incore Instrument Channel Response 24 k) Safety Channel Pre-Critical Alignment Calibration 25

1) Start-Up/Control channel Pre-Critical Alignment and Calibration 26 4~ INITIAL CRITICALITY 27-35

5. LOW POWER PHYSICS TESTING 36-37 a) Radiation Shielding Evaluation 38-39 b) Moderator Temperature Coefficient 40 c) Differential Boron Worth 41-42 d) CEA Group Worth Tests 43-53 e) Critical Boron Concentrations Test 54-55 f) CEA Symmetry Test 56-57 g) Source and Intermediate Range Neutron Instrumentation Overlap 58 h) CEA Sequencing and Inhibit 59

6. POWER ASCENSION TESTING 60-61 a) Automatic Control System and Load Swing Test 62 b) Loss of Offsite Power 63 c) 10% Load Reduction Turbine Runback 64-67 d) Generator Trip with Shutdown Outside. Control Room 68 e) Generator Trip Test 69 f) Evaluation of Core Performance 70-82 g) At Power Moderator Temperature and Power Coefficient Test 83-84 h) Nuclear Power and Delta T Power Correlation 85-88 i) Nautral Circulation 89 j) Digital Data Processor Instrument Correlation 90 k) Ventilation and Air Conditioning System Capabilities 91-99

1) Forced Xenon Oscillation Test 100-102

Page 1 I

1.0

~ INTRODUCTION AND SIRBfARY 1.1

~ INTRODUCTION This report fulfills the requirement of Technical Specification 6.9.1.3 which states that a Startup Test Report will be submitted to the NRC within, COMPLETION DATE + 90 DAYS

1) 90 days after completion of the Startup Test Program 8-9-83 11-7-83

'OMMERCIAL DATE + 90 DAYS

2) 90 days following commencement of commercial power operation 8-8-83 11-6-83 INITIAL CRITICALLITY + 9 MONTHS

3) 9 months following Initical Criticali ty 6-2-83 3-2-84 whichever is earliest.

This report is required to be submitted prior to 11-6-83.

The Startup Test Program was organized and administered by FP6L personnel. The NSSS vendor (Combustion Engineering) and the Architect Engineer (Ebasco) reviewed the program prior to its inception and participated in the field testing and review of test results. The program was'ased on Regulatory Guide 1.68 Rev. 2 with exceptions noted in the FSAR Section 14.2.7.

The Technical Specifications (Section 6.9.1.2) dictate that the Startup Report shall address each test identified in the FSAR. For this reason, Chapter 14 was used as a guideline in preparing the test summaries. Wherever possible, this report follows the test description sequence from Table 14.2-2 of the FSAR.

The Startup Test Program consisted of several phases:

1 ~ Initial Fuel Load

2. Post Core Load Hot Functional Tests

3. Initial Criticality

4. Low Power Physics Tests

5. Power Ascension'ests

a. 20% Plateau

b. 50% Plateau

c. 80% Plateau

d. 100% Plateau The Startup Test Program began on April 6, 1983 with the loading of the first fuel assembly into the reactor vessels It terminated on August 8, 1983 with the declaration of commercial operation. Total test duration was 4 months, 2 days. Figure 1.1 lists the milestone dates during the test program.

Page 2

SUMMARY

INITIAL FUEL LOAD Fuel loading commenced on April 6, 1983 at 1909 hours0.0221 days <br />0.53 hours <br />0.00316 weeks <br />7.263745e-4 months <br /> and was completed on April 10, 1983. The Initial Fuel Load and Core Verification was planned for completion in 14 days. Eight to eleven day loadings were typical for preceeding CE plants. The actual fuel loading duration was 3 days 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> and 45 minutes with the core verification lasting approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 30 minutes. The total duration of fuel load and core verification was 4 days 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 15,minutes. The Unit f/2 Initial Core Load was completed at 1854 hours0.0215 days <br />0.515 hours <br />0.00307 weeks <br />7.05447e-4 months <br /> on April 10, 1983 POST CORE LOAD HOT FUNCTIONAL TESTING Post Core Load Hot Functional Testing began with the plant heatup of April 27, 1983. Testing was completed on May 30, 1983. Total duration was 33 days. In addition to the testing described in Chapter 14 of the FSAR, several other tests were performed primarily due to retesting requirements. These tests were:

RCS and Piping Thermal Expansion RCS Heat Loss

- Pressurizer Controls Test All of the above tests met the required acceptance criteria.

INITIAL CRITICALITY The reactor was initially brought to a critical state on June 2, 1983. A slow dilution followed CEA withdrawal lowering the boron concentration from 1783 ppm to 715 ppm. Measured RCS soluble boron concentration at criticality was in close agreement with predicted values and well within the acceptance critieria.

LOW POWER PHYSICS TESTS The Low Power Physics Tests began on June 2, 1983 following the approach to criticality. These physics tests were completed on June 5, 1983. All acceptance criteria were met.

POWER ASCENSION Power Ascension, testing preparations began on June 10, 1983. The. main generator was synchornized with the grid on June 13 and the 20% power plateau testing was started on June 16. After a brief time at 50% power, the plant underwent a 21 day outage to repair RCP seals, secondary chemistry and condenser cleaning, and a visual inspection of the secondary side of the steam generator for loose parts. 50% power plateau testing went on from July 14 through 19. 80% power testing was from July 20 through 24. 100% power was initially achieved on July 24 and the unit was decared commercial on August 8. Figure 1.2 gives a presentation of power history. Total elapsed power ascension test time- was 59 days.

Page 3 FIGURE 1.1 ST. LUCIE UNIT 2 STARTUP MILESTONE'DATES MILESTONE 1983 DATE Core Load Start April 6 Core Load End April 9 Pos t Core Loa d Hot Func tionals 'S tar te d Hea tup April 27 Post Core Load Hot Functionals End Testing y 30 Initial Criticality June 2 Lov Pover Physics Test Start June 2 Low Power Physics Test End June 5 Full Pover License Received June 10 Start Power Ascension Testing June 10 Reached 20% Plateau June 16 Reached 50% Plateau July 14 Reached 80% Plateau July 20 Reached 100% Plateau July 24 Commercial Operation Start August 8

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Page 5 C

I 2.0 INITIAL CORE LOAD Fuel loading commenced on April 6, 1983 at 1909 hours0.0221 days <br />0.53 hours <br />0.00316 weeks <br />7.263745e-4 months <br /> and was completed on April 10, 1983. The Initial Fuel Load and Core Verification was planned for completion in 14 days. Eight to eleven day loadings were typical for preceding CK plants. The actual fuel loading duration was 3 days, 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> and 45 minutes with the core verification lasting approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 30 minutes. The total duration of fuel load and core verification was- 4 days, 8 hours and 15 minutes. The Unit f/2 Initial Core Load was completed at 1854 hours0.0215 days <br />0.515 hours <br />0.00307 weeks <br />7.05447e-4 months <br /> on April 10, 1983.

Initial,. fuel loading was performed,in accordance with a step-by-step procedure prepared by Florida Power and Light Company Operations Organization reviewed by Combustion Engineering., the Facility Review Group and approved by the Plant Wi nager. Florida Power and Light Company and Combustion Engineering provided continuous coverage for the fuel loading operation to ensure that nuclear safety was adequately sa fe-guar ded.

The detailed procedure that was used for initial fuel loading included:

a) Defined personnel authorities and responsibilities.

k b) Communication requirements between the control room, refueling machine, fuel storage area, and the neutron monitoring station.

c) Requirements for personnel and radiation monitoring.

d) Requirements to ensure proper Reactor Coolant System flow and level and that Technical Specifications for fuel loading are being met.

e) Requirements to verify serial numbers, orientations, and core locations of fuel assemblies, control element assemblies, source assemblies and temporary detectors.

f) Inverse multiplication plot requirements to assure a safe fuel loading.

g) An inverse multiplication criticality estimate for fuel loading following the seating of each fuel element.

h) Requirements;for boron concentration, sampling frequency, boron injection flow path, and borated water sources.

i) Provisions for ensuring proper response of the startup and temporary neutron detectors to neutron sources installed in the core.

Page 6 At 1934 hours0.0224 days <br />0.537 hours <br />0.0032 weeks <br />7.35887e-4 months <br /> on April 6, 1983, fuel assembly No. 1, containing neutron source No. 1, was loa'ded into core location Y-12. The Initial Core Load was completed at 1854 hours0.0215 days <br />0.515 hours <br />0.00307 weeks <br />7.05447e-4 months <br /> on April 10, 1983, when fuel assembly No. 217 was loaded into core location Y-7.

Figure 2-1 shows the fuel loading sequence. Figures 2-2 and 2-3 show fuel assembly and CEA locations by their respective serial numbers.

The neutron count rate was monitored during loading on four separate detector channels, Temporary Detector A in location V-7 and Temporary Detector B in location V-15, were installed prior to fuel loading and Startup Channels 1 and 2. Following the completion of step 140, Temporary Detector B was moved to location D-15.

Previous to fuel loading, a background countrate with no fuel or neutron sources in the core was taken. The acceptance criteria was upheld in that the background signals for each plant startup channel and temporary fuel loading channel were determined prior to the introduction of the source into the vessel and initial fuel loading. The dummy fuel assembly containing the first neutron source was positioned near both temporary and startup detectors to provide a response check prior to loading fuel. As was observed, the temporary fuel loading channels and startup channels responded with a signal that showed an increase above background, thereby, meeting the acceptance criterion for the detectors.

The source was then loaded into the first fuel assembly, and initially the core was loaded by placing the first fuel assemblies on the west side of the core. Succeeding assemblies were inserted in a manner to provide for a compact well coupled partial core. The loading generated a partial core, nine assemblies wide, on the west side of the reactor. As the loading progressed, the nine assembly wide slab was extended across the reactor to the east side. Once the slab was complete from west to east, the loading then proceeded to fill the south portion of the core. When the south portion of the core was finished, the loading progressed to the north side to complete the core.

Independent plots of inverse count rate versus the number of fuel assemblies loaded were maintained to ensure the reactor remained subcritical at all times during loading. The inverse count rate ratio plots remained level when geometric effects were discounted.

No major problems were encountered during fuel loading. All problem areas were corrected.

Page 7 Fuel loading was conducted with the spent fuel pool dry, refueling cavity full to the top of the fuel transfer tube flange and the reactor vessel filled to above the vessel nozzles but below the internals support ledge. A refueling boron concentration of ) 1720 ppm boron was maintained with shutdown cooling flow through the core in accordance with the Technical Specifications at all times.

The location, serial number and orientation of all fuel assemblies, CEA's (not including four fingered CEA's) and neutron sources were visually verified and Appendix 3 (Fuel Loading Verification Check) of Preoperational Test Procedure 2-1600021, Unit 2 Initial Core Loading, was satisfactorily completed.

I page 8 FIGURE 2-1 Pifi7. le- 2 T~GTIAL CORK LOADING CORE LOAD'QfG Sc.QUENCK Y X W V 7 8 R P NML, K J HG F 6 0 C 8 2L2 203 204 205 206 207 208 209 2LO 211 202 OL 200 199 197 195 194 193 192 179 180 81- 182 183 184 185 188 189 190 191 1? .44 47 46 45 43 48 -84 101- 102-18, 19 20 21 42 49 67 82 109 103 LL7 120. 135 t4-T5 t3 1'7 14 23 41 40 50 5L 80 87 99 98 104 105 137 12 11 6 13 24 39 52 6L 70 79 97 106 115 123 132 9

to 8 7 12 '25 38 53 60 71 78 96 107 114 124 131 t gd I , ~40 7 10 2 '7 26 37 59 90 95 108 125 130

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8 30 29 28 27 36 55 94'09 112 &t6 129

31. 32 33 34 35 56 57 74 93 110 127 1 28 142 143 L44 145 47 48 151 152 153 154 L65 164 163 162 158 157 ~ 156 155 166 169 70 171 172 173 174 178 177 176 175

• Tuel Assembly Cancaining lfeucran Source X: Temporary Dececcor Locacian

Page 9 FIGURE 2-2'ZZ Zo.' flfXT~Coa CamrZC CTnZ 1 CORZ 4~ (aZL)

Y X W V 7 S R P NML K J HG F K 0 C B CO25 COOS C039 C027 CO06 COLS C210 C201 B020 1) 6 C008 CD30 C038 C101 BQ17 A034 BOSS A066 B01 025 063 CL02 CO32 088!4 057 B012 A026 B047 A058 B025 A04 067 P049 3058 AOSO C033 029 106 006 A060 B066 A045 B019 A062 B03 068 056 A022 B064 C108 C011 019 062 029 B061 A055 B033 A018 B074 A06 041 002 B068 A007 B069 .C020 203 063 BOSO A027 BO43 A016 B076 A042 B03 006 042 A064 B065 A004 C209 14 036 13 12 049 I4003 B022 A071 B054 A044 B029 AOS 035 020 B038 A011 B078 0808 11 001 051 09 !8 040 A017 B030 A043 B028 A037 B03 053 037 A012 3015 AOLO B071 C002 9

'10 8

003 07 046 AOOL B026 A036 B018 A038 8032 A04 023 019 5053 008 B072 C21 4

~0004 016 C04 0 7

13 059 B057 A014 B079 AOOS B034 A052 B02 021 045 A039 B077 A072 C212 037 009 023 B060 A073 B014 A070 B080 A028IB02L 015 B048 A056 BOOL C025 010 C107 BOOS A030 B013 A051 B044 A035 3073 40 011 A03-" BO08 C104 C014 Ou I4065 B003 A033 B070 A013 B059 *06I$024 032 B004 A047 C024 C022 C103 B002 A024 8052 A069 8016 048 007 C105 C018 C009 CO17 C204 C21'075 C205$ 206 CO21 C034 CO12 C013 C035 C007 NOTE: l. .">>uel assembly orientarfon: 'erial nubber in S'w'arner.

2. ALL serial numbers are prexixed vith "L2".

Page 10 PXGURE 2-3 UNIT i'. 2 'Eif'XTTAL CORE LOADZ'HG CYCLE' CORK KAP (CM'S)

Y' N V 'T S 8 P NMt. K J HG l E 0 G 8 A 79 78 77 76 75 74 72 69 68 '7 17 66 61 60 57 56 13 4 53 54 53 51 50 49 47 46 12 45 11 43 37 10 38 9

8 36 35 34 30 7 28 27 24 22 20

-' 17 16 14 l0 ifOTE: Z l. The four i"ngered CM's (d's 80, 81, 82, 83) ~Ml be ~stal'ed as part oi the uppe guide strucrure foll~ng co@piet'on oi fuel load.

2~ CM oz'ntatKon: Ser"al ~f on Sw'eb,

Page 11 POST CORE LOAD HOT FUNCTIONAL TESTS (PCHF)

Several of the tests required prior to initial criticality require installation of the fuel and all reactor internals as a prerequisite.

These tests (Post Core Hot Functional Tests) are conducted after initial fuel loading and complete the prerequisites for initial criticality. A list of the requird tests follows:

a) RCS Flow and Flow Coastdown b) CEDM. Performance c) Incore Instrumentation Checkout d) Pressurizer Spray Effectiveness e) RCS Leak Tightness f) Plant Chemical and Radio Chemical Analysis g) Wide Range Nuclear Instrumentation Readings h) Loose Parts Monitor i) Reactor Protection System

3) Temporary Incore Instrument Channel Response k) Safety Channel Pre-Critical Alignment Calibration

1) Start-Up/Control Channel Pre-Critical Alignment and Calibration m) Auxiliary Feedwater System Automatic Actuation system n) Natural Circulation The above tests are described in Sections 3.a through 3.d. The instrumentation portion of many of the instrumentation and controls tests-were performed as a prerequisite to either Core Load or PCHF testing.

In addition, those items or systems which require maintenance or had testing deferred from pre-core hot functional tests were tested during PCHF testing. This included:

a) RCS Heat Loss b) RCS Component Expansion c) Piping Thermal Expansion d) Reactor Coolant Gas Vent System e) Post Accident Monitoring System f) Primary Sample System Retest g) Shutdown Cooling Heat Exchanger Retest h) Boron Flow Control Valve Retest i) RTD Time Response Retest

]) Generator Vent System Retest RCS heatup in preparation for Post Core Hot Functional (PCHF) testing began on April 27, 1983. However, an approximate one week delay in continued heatup resulted due to repairs on the 2A Auxiliary Feedwater pump. During the time Diesel Generator testing was completed and other PCHF prerequisite testing continued.

RCS heatup to 300 F and entry into Mode 4 (> 200 F) continued on May 7, 1983 where the plant entered into the Shutdown Cooling Mode and Shutdown Cooling Heat Exchanger retesting was completed. During this time a pressure boundary leak was detected and repaired on a Safety In)ection drain line socket weld. RCS heatup to 532 F and entry into Mode 3

(> 325oF) continued on May 13, 1983 where RTD Time Response and Reactor Heat vent testing was completed.

Page 12 3.0 POST CORE LOAD HOT FUNCTIONAL TESTS (PCHF) (Cont.)

.On May 14, 1983 abnormal pressures on the 2A2 Reactor Coolant Pump (RCP) seal were observed indicating partial RCP seal degradation. A subsequent plant cooldown and depressurization for 2A2 RCP seal change out took place resulting in a one week delay in the test program.

On May 22, 1983 RCS heatup to normal operating temperature and pressure-commenced following which, the main core of the PCHF tests were conducted. 'All PCHF tests required as a prerequisite to initial criticality'ere complete on Nay 30, 1983. These tests were reviewed by the Facility Review Group and determined to have satisfactorily met their.

acceptance criteria.

Page 13 3.a RCS FLOW COASTDOWN 6 MEASUREMENT 3.a.1

Purpose:

The objectives of this test were as follows:

( 1) To measure the reactor coolant flow rate and core pressure dr ops ~

(2) To obtain the reactor coolant pump flow coastdown characteristics.

3.a.2 Test Results All possible 1, 2, 3 and 4 pump combinations of the reacotr coolant pumps were run with complete sets of hand and TDAS data of pump steam generator and vessel DP at design temperature and pressure were preformed for baseline data and no unusual pump oscillations were found that would effect present plant operating pumps confirurations.

The reactor coolant flow rate for 4 pump steady state operation at design temperature and pressure was determined using pump differential pressures and pump curves. This value of 396,502 gpm using the TDAS computor system method and calibration correcting all instruments was found to be well between the two required values of 388,400 gpm determined by CE. The flow coastdown characterics plot was found to exceed the predicted DNBR curve that was. assumed in the. safety analysis per CE preliminary on site study.

This coastdown plot (attached) shows the exceeding of the FSAR curve valves on all counts.

3.a.3 Conclusions Objective one of this test provides ample data for meeting the flow acceptance criteria along with suppling CE with much data on 1, 2, and 3 pump combinations which will be available for further studies and evaluation. Oh)ective two provides data to meet the required coastdown acceptance criteria along with also providing data to'- CE for later review. and studies of baseline information.

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Page 15 1

7 3.b.

~ ~ CONTROL ELEMENT DRIVE MECHANISM PERFORMANCE TEST 3.b.l

Purpose:

The objectives of this test were as follows:

1) To demonstrate the operation of the control element drive mechanism with extension shaft installed.

2) 'o measure the control element assembly withdraw and insertion"speeds."

3) To demonstrate the operation of the control element assembly position indication systems.

4) To demonstrate the operation of the control element drive mechanism control system protective interlocks and alarms associated with individual CEA motion.

5) To measure the control element assembly drop times.

6) To demonstrate the operation of the control element assembly decelerating devices.

7) To demonstrate the operation of the manual trip function.

3.b.2 Test Results:

All of the-objectives were satisfactorily completed. The mean drop time of the 5 finger CEA's was 2.36 seconds and of the 4 finger CEA's was 2.26 seconds; None of the CEA drop times were, in excess of W + (2 ox) of 2.45 seconds for the 5 finger CEA's and 2.33 seconds for the 4 finger CEA's. Several CEDM's demonstrated sluggish operation of the gripper mechanism that resulted in the CEA slipping. This was corrected during testing by time and voltage adjustments. All CEA's moved at 30 inches/minute. CEA position indication displayed CEA position to within 2.50.inches of actual position and agreed withieach control system interlocks and alarms actuated at their prescribed position. All CEA's decelerated just prior to reaching full insertion. Manual trip caused all CEA's to fully insert from a partially withdrawn-position.

3.b"3

Conclusions:

No CEA drop time exceeded the Technical Specification 3.1.3.4 of 3.0 seconds to 90% insertion. The deceleration devices operated to slow CEA insertion prior to full insertion and CEA's operated at 30 in/min. CEA position is indicated to within 2.50 inches of actual position and with individual CEA motion operated, All CEA's full insert upon actuation of a anual Trip.

Mi

Page 16 3.c INCORE INSTRUMENTATION CHECKOUT 3.c.l Purpose The objectives of this test were as follows:

(1) To obtain incore thermocouple comparison data'2)

To measure fixed incore detectors leakage resistance at normal operating temperature.

(3) To demonstrate the operation of the~moveable incore detector system.

3.c.2 - Test Results Objectives 1 and 2 were satisfactorly completed. Objective 3 was not completed satisfactorly. The redundant path switch for the moveable incore switch could not be tested because of hardware malfunctions. A Plant Work Order has been prepared to correct the hardware malfunction during the first outage. The movalbe incore system is fully operational without the redundant path switch. A single drive machine or detector failure would limit-operation to 50 percent of the available detector paths.

3.c.3 Conclusions Objectives 2 and 3 were acceptance criteria for the test.

Objective 2 was completed satisfactorily. Objective 3 wasn.'t completed satisfactorily as noted in the test results, however, the system is operational and will be completed during the first refueling outage.

Page, 17 3.d. PRESSURIZER SPRAY EFFECTIVENESS 3.d.l

Purpose:

The objectives of this test were as follows:

1) Establish setting of the pressurizer continuous spray values.

2) Verify that RCS pressure can be reduced at the design rate using. normal pressurizer spray flow.

3.d.2 Test Results:

The continuous spray valves were adjusted to provide respective spray line temperatures of 25 and 28 F lower than the average cold leg temperature. The observed rate of pressurizer pressure drop with full spray flow was 125 psi per minute.

3.d.3

Conclusions:

Both'ontinuous spray valves were satisfactorily adjusted to provide adequate flow for. minimizing thermal shock to the spray nozzle without causing excessive pressurizer cooldown and pressure reduction. This was accomplished by adjusting the continuous spray valves to obtain spray line temperature 25 F to 30 F lower than the average cold leg temperature.

The second part of this test verified, that full pressurizer spray flow was effective in reducing system pressure at a rate greater than 65 psi,per minute. This was accomplished by, establishing-,

normal conditions for maximum spray line flow and recording pressurizer pressure drop on a strip chart recorder with spray valves full open. Pressurizer functional tests for pressure and level control were conducted during Pre-Core Hot Functional Testing. Retests for the following equipment realignments and modifications were satisfactorily completed as part of this test; pressurizer heater relay modification; backup mode operation of "C" charging pump, pressurizer high-low pressure alarm setpoint.

Page 18

~

3.e

~ REACTOR COOLANT SYSTVf LEAK TIGHTNESS 3.e.l Purpose The objective of this test is to verify that the reactor Coolant system operating leak integrity is within the required valves.

3 ' ~ 2 Results This test was done in conjunction with the required weekly plant survillence procedure which-isolates the make up water supply to the volume -control tank and monitors its level drop over time..

The level changes in various other containment located tanks (i.e.'afety injection, Reactor Drain, Quench) were also monitored to Determine increases/decreases in tank levels.

Volume changes in these tanks were not observed so all leakage found fell in the unknown or system boundry leakage class.

The RCS leak integrity was found to be far below the 1 gpm unknown value acceptance criteria so no farther action was deemed procedurally necessary to located exact causes of leakage.

3.e.3 Conclusion The objective of the procedure was accomplished satisfactory and the 1 gpm unknown leakage acceptance criteria was met easily with no notable problems in accomplishing it.

Page 19 3.f PLANT CHEMICAL AND RADIO CHEMICAL ANALYSIS 3.f.l

Purpose:

1) To ensure that the primary and secondary systems water chemistry meet the criteria set forth in the St. Lucie Plant Chemistry Procedures Manual for system protection.

2) To correlate corrosion data and fission product buildup data to power evels.

3.f.2 Test Results:

Chemical and Radiochemical tests were performed as specified in the Chemistry Procedures Manual and Preoperational Test Procedures No. 2-3400081, which verified chemistry parameters and conformance to specifications for 200 F, 532 F, Startup Mode, 20, 50, 80 and 100% power.

3.f.2.1 . Primary:

All parameters were within limits for the specified modes. Hydrogen was not added to the system prior to initial criticality.'ithuim was maintained at the high end of the specification for a full 10 days during the preconditioning period (no boron) and also throughout the power ascention program. No abnormal isotopic mixes were noted for the perido of power ascention.

3.f.2.2 Secondary:

Maximum steam generate blowdown was maintained as a primary objective for the major part of power testing.

(2) Condensate and feed systems were flushed to achieve as low as possible solids concentrations prior to initiation of feed to the steam generators.

(3) Hydrazine residuals were kept at 3 times the dissolved oxygen concentrations.

(4) Secondary Chemistry control was based upon the EPRI guidelines and specifications.

(5) Cation conductively remained high, resulting in power limitations during the ascention period. Samples were analyzed by both Combusion Engineering and Westinghouse. None of the know aggressive attack agents were identified. The apparent cause of the abnormal cation conductivity peaked at 14 umhos and was brought toward specification by limit power operation and maximum blowdown rates.

Page 20 3.f

~ PLANT CHEMICAL AND RADIO CHEMICAL ANALYSIS: (Cont.)

~

3.f.3

Conclusions:

Chemical testing, both primary & secondary, showed that the plant was in good condition. It showed that chemistry could be controlled within specified limits and that out of specification parameters could be'remedied in a timely manner. It should be noted that the 'limits for S/G and condensate/feed cation conductivity are of recent development and were derived from operating plant experience, not startup of a new unit.

Page 21 3.g

~ WiDE RANGE NUCLEAR INSTRUMENTATION READINGS 3.g.

~ ~ 1 Objective To collect information regarding the temperature effects of neutron monitoring of the core by the wide range nuclear instrumentation. This test provides information to relate core loading count-rates to critical approach count-rates.

3+go 2 Test Results The, temperature effect on the neutron monitoring instrumentation was recorded at six temperatures plateaus. The count-rates. were recorded from each source range detector.

3ogo3 Conclusions It can be seen from the test results, that the count rates increased approximately 300% as temperature rose from ambient conditions to 532 F. This information explains the increase in count-rates from cold shutdown conditions to pre-critical hot standby.

Page 22 3.h LOOSE PARTS $ 10NITOR 3.h.1

Purpose:

The objective of this test was to obtain a set of baseline data that are used to set alarm setpoints and that are used in the future to analyze data provided by the Loose Parts l&nitoring System during plant operation.

3.h.2 Test Results:

Twenty sets of baseline data was collected at various plant conditions including low, intermediate and full power (G) levels were calculated at 100% power. These

'cceleration were found to be well below the level's produced by a 0.5 ft. lb impact at 3 feet from the transducer.

Point Background 0.5 ft lb Impact 0.36 G 5 G & 4 G 0.34 G 4 G & 4 G 0.22 G 1.1G& 1.1G 0.34 G 2.4 G & 1.9 G 0.18 G 2.7 G & 2.4 G 0.12 G 3.1 G & 2.4 G 0.14 G 3.8 G & 4.7 G 0.20 G 3.1 G & 3.6 G 3.h.3

Conclusions:

A complete set of baseline data was recorded and will be available for future reference. Minimum trigger setpoints were identified to allow setting of the alarm triggers.

Page 23 3.i REACTOR PROTECTION SYSTEM (PRE-CRITICAL TEST) 3.i.l Objective a) To verify trip and pre-trip setpoint settings are in accordance with Chapter 16 (Technical Specifications).

b) To demonstrate operability of the by-pass logic and .the trip logic circuitry.

c) To demonstrate operability of the manual reactor trip initiation circuit.

3.i.2 Test Results The RPS setpoints were installed and verified by inputting test signals to trip each bistable. The by-pass and trip logic were exercised to verify setpoints and function. The manual trip logic was initiated and power interruption to CEDMCS power supplies was verified.

3.i.3 Conclusions The RPS performs at the Tech Spec setpoints to meet the design specification.

Page 24 3.j TEMPORARY INCORE INSTRUMENT CHANNEL RESPONSE Temporary Incore Instrument Channel Response Test (Preoperational Test Procedure 2-1210082, Neutron Response of Temporary Fuel Loading Channels and Plant Startup Nuclear Channels).

Purpose The two objectives of this test are to determine the background signal as measured by the temporary incore instrument channels prior to the introduction of a source and performance of a response check of these channels using a start-up source.

Test Results A background determination for the temporary detectors was completed on April 6, 1983. The following background counts were obtained:

Temporary Detector A: .007 CPS Temporary Detector B: .012 CPS Following the background determination, the dummy assembly with startup source No. 1 was introduced into the vessel for a response determination of each channel. The following response counts were obtained:

Temporary Detector A: 1325.47 CPS Temporary Detector B: 1799.15 CPS The acceptance criterion was upheld in that the base count rates for the temporary fuel loading channels were determined prior to the introduction of the source into the vessel and initial core loading.

In addition, the temporary fuel loading channels responded with a signal that showed a significant increase above background*. Therefore the acceptance criterion for these detectors was upheld.

• CE Letter NST-82-348A

\

Page 25 3.k SAFETY CHANNEL PRECRITICAL ALIGNMENT AND CALIBRATION 3.k. 1 Objective a) To perform final calibration and alignment of the safety channel drawers.

b) To verify associated alarms, protective functions and by-passes occur at the correct setpoints.

3.k.2 Test Results The safety, channels were calibrated in accordance with the. Hfg's instruction manual. The alarms, protective 'functions, and by-passes were all demonstrated to function at the tech spec setpoints.

3.k.3 Conclusion The safety channels have been demonstrated to satisfactoriuly meet their design limits.

Page 26 3.1 START-UP/CONTROL CHANNEL PRECRITICAL ALIGNMEiVZ AND CALIBRATION 3.1.1 Objection To perform final calibration and alignment of the Start-up/Control channel dxawers 3.1.2 Test Results

, The Start-up/Control channel drawexs were calibrated and aligned in accordance with- the iifg's tech manual.

3.1.3 Conclusions

'he Start-up/Control channels provide source and power range neutron monitoring capability within the intended design limits.

I Page 27

4. INITIAL CRITICALITY Initial criticality was achieved on June 2, 1983 at Reactor Coolant System (RCS) conditions of 533 F and 2240 psia. The RCS boron concentration prior to dilution was 1783 ppm. The approach to criticality began by withdrawing the Control Element Assembly's (CEA's) in specified increments with count rate data taken after each increment. During this withdrawal, CEA Sequencing and Inhibiting was verified to be functioning properly in accordance with FSAR test

14. 2, 12.3H. Criticality was subsequently achieved by deborating the, RCS to a boron concentration of 715 ppm. Immediately prior to achieving criticality, one decade of nuclear,"instrumentation overlap was"observed in accordance with FSAR'test 14.2.12.3G.

Throughout the approach to criticality, two independent sets of inverse multiplication plots were maintained. Two plots of inverse count rate versus RCS dilution time were maintained during the dilution phase.

Periodically, count rates were obtained from each Startup and Vide Range Logarithmic Channel. The ratio of initial average count rate to the count rate at the end of each time increment was the value plotted.

The CEA withdrawal sequence and intervals are shown in Table 4-1. The.

RCS dilution sequence and'intervals are shown in Table 4-2. The rate versus CEA position points for the two Startup Channels are inverse'ount shown in,Figures 4-1 and 4-2. The inverse count rate versus RCS dilution time is shown in Figures 4-3 and 4-4. The RCS boron concentration versus dilution time: is shown in Figure 4-5.

After achieving initial. criticality, CEA Group 6 was'sed to control neutron flux. Conditions were stabilized at 4 x 10 X power and the critical data shown in Table 4-3 was recorded and compared with predicted values.

In summary, initial criticality was achieved in a safe and orderly manner. There was good agreement between the measured and predicted boron concentrations.

Page 28 TABLE 4-1 CEA WITHDRAWAL SEQUENCE STEP

• CEA GROUP INCHES WITHDRAWN SU11M S U 2 1 M 12.9.1 68 0.86 0. 87 12.9.2 134 0.80 0.90 12.9.3 68 0.84 0.91 12.9.4 134 0.80 0.88

12. 10. 1 99 0.82 0.90

12. 10.5 134 0.82 0.87

< 55 12.10.7.1 98 0. 77 0.73 12.10.7.5 134 0.81 0.80

< 55 12.10.8.1 98 0.75 0.81 12.10.8.9 134 0.75 0.84

< 55 12.10.9.1 98 0.77 0.78 12.10.9.5 134 0.74 0.79

< 55 12 10 10 1 98 0.76 0.79 2.10.10.10 135 0.75 0.77

< 55 12.11 66 0.78 0.80

• Steps Erom Initial Criticality Procedure, Preop 2-0030221

Page 29 TABLE 4-2 RCS DILUTION SEQUENCE DILUTION DILUTION RCS BORON STARTUP STARTUP TIME TIME DATE TIME CHEMICAL CHANNEL 1 CHANNEL 2 (MINUTES ) (HOURS) ANALYSIS 1/M 1/M 6-1-83 1945 1783 1.00 1.00 15 0.25 2000 1767 0.96 1.05 25 0.42 2010 1708 0.93 1.02 40 0.67 2100 1686 0.98 0.93 70 1.17 2130 1591 0.90 0.91 100 1.67 2200 1483 0.88 0.80 130 2.17 2230 1377 0.76 0.85 160 2.67 2300 1301 0.79 0.78 190 3.17 2330 1220 0.68 0.70 220 3.67 6-2-83 0000 1138 0.69 0.64 250 4.17 0030 1080 0.64 0.62 280 4.67 0100 991 0.57 0.59 310 5.17 0130 949 0.51 0.51 340 5.67 0200 890 0.44 0.43 369 6. 15 0229 843 0.40 0.36 374 6.23 0330 889 0.40 0;43 389 6. 48 0345 839 0.40 0.40 404 6.73 0400 826 0.36 0.40 419 6.98 0415 801 0.35 0.35 434 7.23 0430 784 0.30 0.29 449 7.48 0445 767 0.26 0.27 464 7.73 0500 754 0.23 0.25 479 '.98 0515 741 0.21 0.20 495 8.25 0530 737 0. 16 0. 16 509 8.48 0545 0.13 0.12 524 8.73 0551 716 0.02 0.02 530 8.83 0700 715

Page 30 F IGURE,4-1 ST. LUCIE UNIT 2 ATTAI%iENT OF INITIAL CRITICALITY BOL, 1st CYCLE, 533 F, 2240 PSIA .

STARTUP CHAtlNEL NO, 1 1.0 0.9

0. 8 C'

7 0.6 0.5 t

K-O O 0 Ai Cfl

0. 3 0.2 0.1 0.0 lh 0

Ch O Ch Ch Ch Ch O O r r C90 CO Ch Ch O CV CV Q (4 ~ ~ O O O O O O H O O

CV CV CV STEPS FROM INITIAL CRITICALITY PROCEDURE PREOP 2-0030221

Page 31 FIGURE 4-2 ST. LUCIE UNIT 2 ATTAIVAENT OF INITIAL CRITICALITY BOL, 1st CYCLE, 533 F, 2240 PSIA STARTUP CHANNEL iVO. 2 1.0 0.9 O.S 0.7 0.6 0.5 0.4 I I I I 0 3 I e 0.2 1 I 1 I 0.1 0.0 C

~ w C C CO CO Ch C C C C

~ ~

CV CV C4 C13 C C

~ C

~

CV CV CV C4 C C13 STEPS FROH INITIAL CRITICALITY PROCEDURE PREOP 2-0030221

Page 32 FIGURE 4-3 ST. LUCIE UiVIT 2 ATTAIV'fENT OF INITIAL CRITICALITY'OLI 1st CYCLE, 5330F, 2240 PSIA STARTUP CHANNEL iVO. 1 7ERO PO'HER, CEA GROUP 6 AT 77 IiVCHES 1.0 0.9 0.8

~ M CD I I 0 0.7 CD 0.6 I I I ~ . s 0.5 K I' 4

I O 0.4 I j CD fQ Cfl lY fd 0.3 1 M

0.2 0.1 0

0 2 3 4 5 6 7 8 DILUTION TIlE (HOURS)

Page 33 FIGURE 4-4 ST. LUCIE UNIT 2 ATTAI%1ENT OF INITIAL CRITICALITY BOL, 1st CYCLF., 533 F, 2240 PSIA STARTUP CHANNEL NO. 2 ZERO POtiERI CEA GROUP 6 AT 77 INCHES 1.0 0.9 I

~ ~ I I '

I 0.8 I -I I I I I I

I I

i i I

~

I r

0' 0.6 0.5 0.4 0.3 0.2 0.1 0

I 0 1 2 3 4 5 6 7 8 9 DILUTION TINE (HOURS)

Page 34 FIGURE 4-5 ST. LUCIE UNIT 2 BOL 1st CYCLE REACTOR COOLAiVT SYSTEif BORON CONCENTRATION VS DILUTION TI+s.E 1800 1700 1600 1500 l

1400 1300 1200 1100 I

1000 J.

~

900 1 i

800 700 0 1 2 3 4 5 6 7 8 9 DILUTION TIifE (HOURS)

I I Page 35 TABLE 4-3 CRITICAL CONDITIONS AND CEA CONFIGURATION PAKQKTER PREDICTED MEASURED CONDITION VALUE RCS TEMPERATURE 532 F 533'F RCS PRESSURE 2250 PSIA 2240 PSIA RCP'S OPERATING CEA GROUPS WITHDRAWN, IN INCHES UEL UEL UEL UEL UEL UEL UEL 77 77 RCS BORON CONCENTRATION (PPM)

NOTE: UEL Upper Electrical Limit

Page 36

5. LOW POWER PHYSICS TESTS (LPPT)

The St. Lucie Unit 2 initial core consists of two hundred seventeen (217) fuel assemblies each containing two hundred thirty six (236) fuel rods/burnable poison rods and five (5) Control Element Assembly (CEA) guide tubes. Fuel assemblies are divided into three (3) distinct groups by enrichment, Type A, B and C. Sixteen (16) fuel rods in all Type B and sixteen (16) Type C fuel assemblies are replaced with burnable poison rods. In addition, eight (8) Type .C fuel assemblies have twelve (12) fuel rods replaced with burnable poison rods.

In addition to soluble boron in the Reactor 'Coolant System (RCS),

reactivity control is provided by eighty-three (83) CEA's. CEA's are inserted into and withdrawn from the core by means of eight-three (83)

Control Element Drive Mechanisms (CEDM's). Four (4) CEA's have only four (4) fingers and are placed into two (2) fuel assemblies on the four (4) core edges. Figure 5.0-1 shows the core locations of the CEA's. The CEDM's are arranged into eight (8) CEA Groups. Those groups are further defined by function. CEA Group A and B are Shutdown Groups. CEA Groups 1 through 6 are Regulating Groups. Figure 5.0-1 also displays the relative core location of the CEA Groups.

CEA Group movement is restricted as a function of power level in order to insure that CEA configurations not analyzed for in the safety analysis do not occur'. The mechanism for this is the Power Dependent Insertion Limit (PDIL) of the Technical Specifications. Automatic control and alarm features as well as operator instructions and training prevent insertion of CEA groups into the core below the PDIL. The lower the reactor power, the greater the CEA insertion allowed.

LPPT consists primarily of the measurement of reactivity worths of components which can vary the critical condition of the core. To speed the collection of this data, as well as to enhance its accuracy, a digital computer which solves the kinetic equation for reactivity was used. All raw data was collected, reduced and analyzed onsite by both FPSL and CE personnel. In all cases, measured data met applicable acceptance criteria.

Page 37 FIGURE 5.0-1 ST. LUCIE PLANT UNIT NO. 2 CEA/CEDM LOCATIONS N

Y X N V T.. S R P NML K J HQ .F E D C S A A-.88 (80) 2-79 2-68 79} 78

-87 3-67 4-5 3-60 B-80 (72) (76) (75) (74) (73) 1-78 A-55 B-43 B-36 A-48 1-69 (72) (71) (70) (69) (68) (67)

B-86 5-47 6-20 5-44 (66) (65) (64) (63) (62)

A-54 A-27 B-L9 B-12 A-24 (61) (60) (59) (58) (57) (56) 3-66 1-4 4-8 3-61 55 (53) (52) (51) 2-77 B-42 B-18 A-3 B-13 B-32 2-70 (50) (49) (48) (47) (46) (45) (44) 4-59 6-23 1-7 -1 1-5 -21 4-5?

(43) (39) (38)

AM.

(83) (42) (41) (40) (37)

(81) 2-76 -41 B-17 A-2 B-14 B-38 2-7 (36 (35) (34) (33) (32) (31) (30) 3-65 4-10 1-6 4>>9 3>>62 (29) (28) (27) (26) (25)

A-53 A-26 B-16 B-15 A-25 A-50 (24) (23) 2Z) (21) (20) (19)

B-85 5-46 6-22 5-45 B-82 (18) (17) (16) (15) (14) 1-75 A-52 B-40 -39 A-5L 1-72 (13) (12) 11 10 (9) (8)

B-84 3-64 4-58 3-63 B>>83 (7) (6) 5 (4) (3)

<<74 2-73 (2) (1)

(S2}

A+0 LEGEND Group CEDM No ~ 1 ~

CEA NO. (X) 2 ~

Page 38 5.a RADIATION SHIELDING EVALUATION TEST 5.a.l Purpose

1) Measure neutron and gamma radiation dose rates during startup testing as a function of reactor power level.

2) Establish baseline radiation levels for future comparisons

3) Compare the measured radiation levels as a function of reactor power levels to predicted design'adiation levies in chapter 12 of the FSAR.

5.a.2 Test Results A comprehensive series of radiation survey 's were conducted during the power escalation phase of start-up testing. Surveys were taken at the 3-5%, 20%, 50%, 80% and 100% 'reactor power levels at selected locations in the REactor Containment Building, REactor Auxiliary Building, Fuel Handling Building, Control Room Controlled area. Measurements were taken at mechnical and electrical penetreations of the reactor auxiliary and the escape funnel in the spent fuel pool area to determine if radiation streaming (principally neutron) from the reactor containment building was occuring. Additional measurements of neutron radiation in the reactor containment building to determine the neutron energy spectrum were performed by the Baltele Pacific Northwest Labs.

5.a.3 Conclusions The survey 's performed within the reactor auxiliary building were compared to the predicted radiation dose rates in chapter 12.3 of the FSAR and were found to be in good agreement with the FSAR.

Passageways, laboratories, locker rooms and offices ere below the predicted gamma dose rate of 0.25 mre'm/hr. No neutrons were found at the penetration areas during any of the survey's. The control room, turbine building, out of, doors radiation controlled area and-fuel handling building were less than 0.25 mrem/hr gamma radiation and no neutron radiation was detected in these areas with streaming was detected at the personnel,excape tunnel on of. the spent, fuel pool area.'t '100% reactor power. the the,62'levation dose rates at the excape tunnel that are attributable to the streaming are 4 mrem/hr neutron and 2 mrem/hr gamma.

Page 39 5.a

~ RADIATION SHIELDING EVALUATION TEST (continued) 5.a.3

~ ~ Conclusions (continued)

At the 20% reactor power level, the 62'levation of the reactor containment building was above FSAR predicted dose rates (2.5 mrem/hr - 15 mrem/hr). The principle contribution to the dose rate was from neutrons. The area affected the most was to the west of the reactor. Neutron dose rates west of the steam generator cubicles ranged from 10 mrem/hr to 100 mrem/hr. Gamma dose rates ranged from 1.5 mr/hr to 30 mr/hr. At the 100% reactor power level all elevations -within the building were in excess of FSAR predictions. The principle contributor to the dose rates were due to neutrons. Gamma radiation levels on the 23'nd were essentially within predicted valves with general45'levations area dose rates ranges of 4-14 mr/hr. The 62'levation gamma dose rates exceed FSAR predicted values for combined neutron and gamma dose rates. Gamma general area radiation levels ranged to 400 mrem/hr. Areas of highest dose rates are in the vicinity of the neutron shield wall attachments to the reactor refueling cavity and west of the steam generators to the containment building wall. The primary reason for the higher dose rates (neutron and gamma) is the streaming of neutrons, between the reactor missle shield and part height shield walls west of the refueling cavity. Scattering of the neutrons from the containment wall and air appear to affect the entire 62'levation.

Upon conclusion of the Battele neutron energy spectral analysis the neutron data will be reviewed and any necessary neutron dose .

rate corrections will be made as indicated by the study. It is expected that significant reductions in neutron dose-rates will be indicated based on neutron energy. After dose rate corrections have been made a final conclusion as to the adequacy of the containment building shielding will be made.

Page 40 5.b Temperature Coefficient of Reactivity Measurement 5.b.l Purpose The moderator temperature coefficient of reactivity can be either negative or positive, depending upon the magnitude of the Reactor Coolant System boron concentration. The moderator temperature coefficient cannot be measured directly but it can be derived from a measurement of the isothermal temperature coefficient.

5.b.2 Test Results isothermal temperature coefficient of reactivity measurement

'he was made with CEA Groups 5-B fully withdrawn and CEA Group 6 at 113 inches withdrawn. The measured isothermal temperature coefficient is the result of the average coefficient measured by several plant heatups and cooldowns. Throughout the measurements, reactor power was maintain'ed below the point of adding nuclear heat to minimize reactivity effects of doppler feedback. Reactor Coolant System ramp temperature changes were affected by proper positioning of atmospheric dump valves. The measured moderator temperature coefficient was .265 x 10 Delta rho/

F'.b.3 Conclusions The measured moderator temperature coefficient was in satisfactoq.agreement with the predicted value of

.157 x 10 Delta rho/ F and met all of the following test acceptance criteria:

The moderator temperature coefficient is less positive than

+ 0.5 x 10 Delta rho/ F in accordance with Technical Specifications.

The moderator temperature coefficient is less positive than

+ O.l x 10 Delta rho/ F: and less negative than -2.10 x 10 Delta rho/ F in accordance with the Safety Analysis.

The measure) moderator temperature coefficient is within

+ 0.3 x 10 Delta rho/ F of the predicted value.

Page 41 5.c DIFFERENTIAL BORON WORTH MEASUREMENTS 5.c.l Purpose Soluble boron in the form of dissolved boric acid in the Reactor Coolant System provides variable react1vity control over the life of a core. It can supplement the reactivity control provided by CEA Groups. However, its principle function is to compensate for burnup of excess reactivity as core depletion proceeds. The critical boron concentrations were measured for var1ous CEA configurations as presented in Section 5.e. The CEA Group worths were measured as descr1bed in Section 5.d. Using these measurements, the boron effect on reactivity was determined.

5.c.2 Test Results CEA Group integral reactivity worths were measured using the soluble boron swap technique described in Section 5.d. In addition, as presented in Sect1on 5.e, the soluble boron concentrations associated with steady state endpoints were measured during the CEA Group worth measurements. A comparison of measured and predicted inverse boron worth for the various endpoints.is presented in Table 5.c-l.

5.c.3 Conclusions Results ind1cate that measured boron worths were in satisfactory agreement with predictions and well within the acceptance criterion of + 10 PPM/% Delta rho.

Page 42 TABLE 5.c-l INVERSE BORON WORTH

SUMMARY

COLUMN 1 COLUMN 2 COLUMN 3 COLUMN 4 COLUMN 5 COLUNN 6 CHANGE IN CBC MEASURED SOLUBLE INSERTED DESIGN SOLUBLE MEASURED CRITICAL CEA FROM ARO NON-OVE RLAP INVERSE BORON WORTH INSERTED BORON CONCENTRATION CONFIGURATION CRT rICAL VALUE CEA WORTH (DELTA PPM/% DELTA PHO) INVERSE BORON WORTH (PPM) (DELTA PPM) (%DELTA RHO) (COLUMN 3/COLUMN 4) (PPM/% DELTA RHO) 6-4 8 LEL 599 3-A 8 UEL 125 1.5827 78.979 72.517 6-1 9 LEL I 416 A,B 8 UEL 308 4.42325 69.632 69.008 l 6-B 9 LEL 207 Ae UEL 517 7.40685 69.&00 68.767

Page 43 5.d CEA GROUP WORTH tKASUREiMNTS 5.d. 1 Purpose During reactor operation, nearly all excess reactivity is held down by soluble boron concentration in the Reactor Coolant System and burnable poison shim rods in the fuel assemblies.

Additional hold down and reactivity control is provided by moveable Control Element Assemblies (CEA's). These CEA's are arrayed in symmetrical groups about the core (see Figure 5.0-1),

The number of CEA's in each Regulating and Shutdown CEA group and the function of each group is described in Table 5.d-l. All CEA Group measured worths displayed in the Table are non-overlapping over the full range of CEA movement at various Reactor Coolant System boron concentrations.

5.d.2 Test Results All CEA Group reactivity worths were measured using a soluble boron swap method, either dilution or boration, to maintain criticality while inserting or withdrawing CEA Groups in increments. The reactivity trace generated on the reactivity computer by this evolution was then analyzed to obtain the-relationship between CEA Group positions from full in to full out and integral reactivity worth at these positions.

After the most reactive CEA, CEA B-83, was swapped with CEA Group A, the net integral worth of CEA Group A was measured using the:-standard boron swap, technique.

The integral worths of all Shutdown and Regulating CEA Groups were measured at 532 + 2 F and are compared with predicted values in Table 5.d-l. The integral reactivity worth curves are displayed in Figures 5.d-l through 5.d-8.

5.d .3 Conclusions The measured,CEA Group integral reactivity worths are in satisfactory agreement with predi.cted values as shown in Table 5.d-2. The total measured CEA worth for C'EA 'Groups 6 through B within the acceptance criteria of + 10% of design 'as predictions to assure shutdown margin, consistent with accident analysis assumptions, throughout core life.

Page 44 TABLE 5.d-1 CEA WORTH

SUMMARY

CEA NUMBER FUNCTION MEASURED DESIGN WORTH ACCEPTABLE RANGE GROUP OF OF WORTH (% Delta rho)

CEA's CEA's (% Delta rho) (% Delta rho)

To 0.4228 Re ulatin 0.3653 0. 3728 From 0.3228 To 0.4245 Re ulatin 0. 3725 0.3745 From 0.3245 To 0.9679 Re ulatin 0.8449 0.8799 From 0.791 To 1.1812 Re ulatin 1.0360 1.0738 From 0.9664 To 0.7039 Re ulatin 0.6433 0.6399 From 0.5759 To 1.3143 Re ulatin l. 1613 1.1948 From 1.0753 To 3.2806 24 Shutdown 2.9836 2.9824 From 2.6842 To 1.8986 18 Shutdown 1.7840 1.7260 From 1.5534 Net CEA Shutdown Worth: 9. 1909

• Net worth measurement made while most'*reacti've CEA (CEA B-83) fully withdrawn in accordance with Technical SPecification 3.10.1.

Page 45 TABLE 5.8-2 CEA SHUTDOWN MARGIN SALARY CEA MEASURED DESIGN . PERCENT GROUPS  % Delta rho  % Delta Rho DIFFERENCE 6 thru B 7.4069 7.5181 1.4798%

Page 46 FIGURE S.d-l ST. LUCIE UNIT 2 INTEGRAL CEA GROUP WORTH CYCLE 1, 0 EFPH, 532 + 2 F, 2250 + 15 psia CEA GROUP 6 0 '00 ~ ~

0.475

~ ~

0. 450 0.425 0.400 0.375 0.350 0.325 o 0,300 t ~

I I I ~ ~ ~ I I I I ~ ~ I I ~

0.275 I ~

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~ ~ I I I ~ ~ t \ ~

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, .0. 250 I \ I I ~ I I I ~ ~ I t t ~

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~ 0.225 I I ~ ~

t

~

H L 0.200 I ~

0. 175

0. 150

0. 125 0 100

~

0.075 0.050 0.025 0

0 10 20 30 40 50 60 70 80 90 l00 ,llO l20 40 CEA WITHDRAWAL (INCHES)

Page 47 FIGURE 5.d-2 ST..LUCIE UNIT 2 INTEGRAL CEA GROUP WORTH CYCLE 1, 0 EFPH, 532 + 2 F, 2250 + 15 psia CEA GROUP 5 0.500 0.475 0.450 0.425 0.400 ~ ~

0.375 C

I \ ~

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~ I I y y I I

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~ ~ I 0.150 0.125 0.100 0.075 0.050 0.025 0

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 CEA WITHDRAWAL (INCHES)

Page 48 FIGURE 5.d-3 ST. LUCIE UNIT 2 INTEGRAL CEA GROUP WORTH CYCLE ), 0 EFPH, 532 + 2 F, 2250 + 15 psia CEA GROUP 4 1.00 I ~ ~

0. 95

0. 90 0.85 1 ~

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Page 49 FlGURE 5.d-4 ST. LUCXE UNTT 2 INTEGRAL CEA GROUP WORTH CYCLE 1, 0 EFPH, 532 + 2 F, 2250 + 15 psia CEA GROUP 3 2.00 t

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Page 50 FIGURE 5;d-5 ST. LUCIE UNIT 2 INTEGRAL CEA GROUP WORTH CYCLE 1, 0 EFPH, 532 + 2 F, 2250 + 15 psia CEA GROUP 2

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Page 51 FIGURE 5.1-6 ST. LUCIE UNIT 2 INTEGRAL CEA GROUP WORTH CYCLE 1, 0 EFPH, 532 + 2 F, 2250 + 15 psia CEA GROUP 1 2.00

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Page 52 FIGURE 5.d-7 ST. LUCIE UNIT 2 INTEGRAL CEA GROUP WORTH CYCLE 1, 0 EFPH, 532 + 20F, 2250 + 15 ps1a CEA GROUP B

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Page 53 FIGRUE 5.(j-8 ST. LUCIE UNIT 2 INTEGRAL CEA GROUP NET WORTH CYCLE 1, 0 EFPH, 532 + 20F, 2250 + 15 psia CEA GROUP A 2.00 I \ I I ~ I ~ I

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Page 54 5.e CRITICAL BORON CONCENTRATION MEASUREMENTS 5.e.l Purpose Critical boron concentration measurements were performed at various CEA configurations at relatively constant RCS temperature and pressure. The purpose of these measurements was to obtain an as-built value for the excess'eactivity loaded into the core and .to provide a basis for verification of predicted CEA Group reactivity worths.

5.e.2 Test Results Boron concentration values were the stabilized averages of multiple chemical analysis measurements made of the Reactor Coolant System (RCS). Boron endpoint techniques were used when required. This technique borates (dilutes) CEA's out near UEL*

(in near LEL+*). After RCS conditions stabilize and the RCS boron concentration has been analyzed, the CEA's are quickly moved to UEL (to LEL), reactivity stabilized and CEA's quickly moved back in (out) to their bite position. The reactivity change (reactivity being plotted on a recorder of the reactivity computer) is measured. The amount of reactivity added (subtracted) is converted, via boron worth, to an equivalent Delta,PPM. This Delta PPM is added to (subtracted from) the measured boron concentration. This technique gives a safe, fast and accurate, method of determining critical boron concentrations at hard to achieve CEA positions (relatively low reactivity worths at UEL's and LEL's).

5.e .3 Conclusions As Table 5.e-l illustrates, the results indicate that measured critical boron concentrations were in satisfactory agreement with predictions and well within the acceptance criteria of + 50 PPM.

• UEL ~ Upper Electrical Limit

• • LEL -Lower Electrical Limit

Page 55 TABLE 5.e-l BORON ENDPOINT

SUMMARY

CEA CONFIGURATION MEASURED DESIGN ACCEPTABLE RANGE (PPM)

To Desi n + 50 PPM 761 ARO 724 711 From Desi - 50 PPM'= 661 6-4 8 LEL To Design + 50 PPM = 643 3-A 9 UEL 599 593 From Desi - 50 PPM = 543 6-1 9 LEL To Design + 50 PPM ~ 448 A,B..Q UEL 416 398 From Design 50 PPM = 348 6-B 9 LEL To Desi n + 50 PPM 2 A 9 UEL 207 194 From Desi 50 PPM = 144

Page 56 S.f CEA Symmetry Measurements 5.f.l Purpose The reactivity differences of symmetric CEA's were measured as one of numerous verification tests on both fuel and CEA manufacture and as designed placement into the reactor vessel.

The measurement was performed by alternately swapping in and out all regulating and shutdown individual CEA's with their symmetric neighbors*. All CEA's were verified coupled to their Control Element Drive Mechanism (CEDM) extension shafts to verify CEA reactivity control of the core. This measurement was made by observing 'a reactivity change associated with individual, CEA motion.

5.f.2 Test Results The measured reactivity differences of symmetric CEA's were small with the average and worst case by symmetric inter-groups displayed in Table 5.f-l. All CEA's, including the center CEA, were verified coupled to their CEDM extension shafts.

5.f.3 Conclusions Results indicate that the relative .reactivity differences of symmetric CEA's were within the acceptance criteria value of 1 /2 $ and all CEA's were coupled .

• Regulating center CEA 2-1 by design has no symmetric equivalent and as, a result had no symmetry test performed; CEA 2-1, as with all other CEA's, was verified individually coupled to its CEDM extension shaft.

Page 57 TABLE 5.f-l CEA SYMMETRY SUGARY Number of Average Worst CEA Symmetric CEA's Symme tric Symme tric CEA Symmetry ifeasured and Reactivi ty React ivity Group Sub roup Verified Coupled Difference ( ) Difference ( )

6 -0. 61 -1.08 A 12,13 -0.74 -1.10 22 -0.32 -0.59 23 -1.10 -1.26 3,4 -0. 28 -0.66 9,10 -0. 68 -1.08 20,21 -0.45 -0.77 1 -0.28 -0.53 18 -0.09 +0.24 17,19 -0.42 -0. 90 15, 16 -0.33 -0. 93 2 -0.67 -0.89 14 -0.53 -0.91

-0.52 -0.84

-0.03 -0. 16

Page 58 5.g

~ SOURCE AND INTEIQKDIATE RANGE NEUTRON INSTRUMENTATION OVERLAP VERIFICATION 5.g.

~ ~ 1 ~0b'ective Demonstration of adequate overlap of the source and intermediate neutron instrumentation.

5.g.2 Test Results The overlap between the soruce range and intermediate range detectors was recorded during power ascension.

5.g.3 Conclusion The data recorded in this test demonstrates this system exceeds the design limit of one decade overlap.

Page 59 5.h

~ CEA SEQUENCING 7 INHIBIT TEST 5.h.l

~ ~ ~Pur ose:

The objectives of this test were as follows:

1) To demonstrate that the CEA withdrawal sequence while operating in sequential mode was as specificed in the Technical Specifications, Section 3/4.1.3.

2) To demonstrate the operation of the CEA Motion Inhibits initiated by the Analog Display System (ADS).

5.h.2 Test Results:

The CEA's operated in the sequence specified by the Technical Specifications Section 3/4.1.3 while operating in Sequential Mode.

Regulating Group Position at which Group next roup be ins motion It 99 97.5" 97.5" 97.5" 97.5" N/A CEA Motion is inhibited by the ADS signals resulting from the following:

1) A CEA in any group out of group position by 6, +1 -2.5 inches.

2) Adjacent Regulating Group positions within 82 inches of each other.

Groups Overlap 1&2 86 inches 2 & 3 87 inches 3&4 86 inches 4&5 86 inches 5&6 86 inches

3) Groups 3, 4, 5 or 6 exceeding its Power Dependent Insertion Limit Regulating Group withdrawal is inhibited when all Shutdown Group CEA's are not at their UEL Shutdown Group insertion is inhibited when all Regulating Group CEA's are not at their LEL. Power Depent Insertion Linits meet the requirements of Technical Specification 3.1;3.6.

5.h.3

Conclusions:

Regulating CEA's withdraw in the specified sequence. CEA motion is inhibited by the limiting CEA position configuration as detected by the ADS.

4>>

Page 60 POWER ASCENSION TESTING The purpose of the Power Ascension program was to provide a safe and efficient frame work for the performance of initial plant startup tests and routine plant startup tests. Power Ascension officially began on June 11, 1983 and was completed on August 9, 1983, a total of 60 days.

Included in this 60 days was a 21 day outage which was caused, in the most part, by failed 2A2 Reactor Coolant pump seals and secondary chemistry cation high conductivity .

Power Ascension testing can be broken down into three major categories.

Firstly is "Reactor Physics" FSAR Chapter 14 testing such as Nuclear, and Delta T Power Calibration, Moderator Temperature and Power Coefficient test, Peaking Factor and Flux Tilt Verification, etc. Secondly 'is the completion of Chapter 14 "System Testing" such as Generator Trip with Shutdown Outside the Control Room, Loss of Offsite Power, Turbine Overspeed, etc. The final category could be labeled "Miscellaneous",

which would include Chemical and Radiochemical Analysis, Radiation Shielding Evaluation, Digital Data Processor Instrument Correlation, etc.

Power Ascension immediately followed Low Power Physics Testing. The first Power Ascension milestone was on,.June 13, 1983 when the main generator was synchronized to the grid at 8:55 a.m. Testing continued until June 22, 1983 when it was decided to cooldown and partially drain the RCS for 2A2 reactor coolant pump, seal changeout in coincidence with a.

complete secondary flush, 2A steam generator loose parts internal inspection and condensate pump strainer cleanout. RCS heatup and pressurization commenced on July 3, 1983 and again the 2A2 reactor coolant .pump seal exhibited problems. Cooldown and subsequent 2A2 reactor coolant pump changeout began on July 4, 1983. This time the entire seal cartridge was replaced. Heatup and pressurization began on July 12, 1983 and the 2A2 pump seal functioned properly. Fifty percent plateau testing started on July 15, 1983 and was completed on July 19.

Power increase to the eighty percent plateau immediately followed completion of the fifty percent plateau and eighty percent testing began at 10:35 a.m. on July 20, 1983.

RCS flow measureme'nt "delta T technique", results did not agree well with steam generator or pump power methods. Reactor power was maintained at the 80% plateau until this,situation was resolved. The vendor recommends determining,RCS flow"based on stem generator delta P. Measurements using this technique yielded expected results. As a backup, reactor coolant pump motor input power-readings were taken and,the RCS flow calculated, using this method agreed with the steam generator delta P method. After close scrutiny it was noted that T cold RTD's used to calculate RCS delta T were reading higher than two other RTD's located nearby. It was determined that an increased temperature statification factor was needed for RCS T cold RTD's. The RTD's were compensated and acceptable RCS flow using the delta T method was obtained.

Condensate pump strainers forced a power decrease to fifty percent at the end of the eighty percent plateau on July 24, 1983.

Page 61

6. POWER ASCENSION TESTING (Cont.)

The Power Ascension Test Sequence was modified in an effort to shorten the time to continous 100% power operation. The one hundred percent generator trip test was moved from being the last one hundred percent test to the first. Physics tests were shuffled and dove tailed with vendor approval and yielded good results.

Power was increased to one hundred percent at 11:10 a.m. on July 24, 1983 followed by the generator trip test at 2:45 a.m. July 25, 1983. An immediate, return to twenty percent power in preparation. for Loss of Offsite Power (LOOP) test'took place. The twenty percent power LOOP test was performed after an inadvertant trip on high steam generator level while controlling manually, on July 27, 1983.

Load swing testing was performed on July 29, 1983, after returning to fifty percent power and immediately followed with the Turbine Runback test. Power was decreased to thirty percent for secondary high cation conductivity (maximum blowdown and secondary feed and bleed).

One hundred percent power was again acheived at 7:10 p.m. on July 31, 1983. While plateau testing was in progress, oil level in the 2B2 reactor coolant pump motor was noticed to be decreasing. Immediately prior to coming off-line for repair of the 2B2 reactor coolant pump, the hot full power moderator temperature coefficient test was performed. The unit came off the line at 11:43 p.m. on August 3, 1983.

Repairs to 2B2 reactor coolant pump (cracked oil system oil pipe fitting) were completed and startup began at 10:46 a.m. on August 4, 1983. Axial shape index forced a power reduction to 10 X. The one hundred percent power moderator temperature coefficient test was performed. Immediately prior to shutdown, an attempt to restart during peak Xenon conditions combined with tight ASI LCO's caused the axial shape index problem.

On August 5, 1983 at 2:40 a'.m., the plant was again at one hundred percent power and testing continued. Unit commercialization was declared on August 7, 1983 (midnight) with the initial testing program and Power Ascension program concluded at the completion of the NSSS and Turbine Generator Acceptance Run on August 9, 1983, 11:10 a.m.

0 Page 62 6.a AUTOMATIC CONTROL SYSTEM AND LOAD SWING TEST Purpose This test verified that system automatic controls were capable of maintaining plant parameters with allowable tolerances during steady state and design load change conditions. Data was also obtained via the Transient Data Acquisition System (TDAS) to verify Combustion Engineering System Excursion Code (CESEC) used in the safety analysis.

Test Results Initial testing at the 20% power plateau resulted in some adjustment to main feedwater controllers. This was expected since low flow throtlling of the main feedwater regulating valves inherently induces instability .

However, at subsequent plateaus no adjustments were necessary.

Load swings of 5%/min decrease, 10% step decrease, 10% step increase, and 10% ramp increase were performed on July 29, 1983. All automatic systems functioned properly and all Single Valve Acceptance Criteria (SVAC) were met for each test except for 10% step decrease. The turbine control system overshot approximately 3% on the 10% step decrease (i.e. 13% step decrease). After correcting for the overshoot, the SVAC were met.

Conclusions All acceptance criteria were met for this test. 'he TDAS allowed for immediate feedback thereby shortening post test analysis and the determination of acceptable results.

Page 63 6.b

~ L'OSS OF OFFSITE POWER TEST 6.b.l

~ ~ Purpose The objectives of this test were as follows:

1) Demonstrate the plant's response during a load rejection from 20% reactor power to station auxilliary load by opening thge oil circuit breakers to the distribution system.

2) Demonstrate the plant's response to a total loss of offsite power by inducing a turbine generator trip with the plant carrying station auxilliary load and automatic closure of brea'kers to provide offsite power disabled.

3) Verify that the diesel generators start and provide power to plant vital loads for at least 30 minutes following the turbine generator trip.

4) Collect data for use by Combustion Engineering for quallification of the CE System Excursion Code (CESEC) NSSS simulation.

6.b.2 Test Results All of the above were satisfactorily completed. The load reduction to station auxilliary load portion of the test was performed with no unexpected events. All plant equipment functioned to maintain pressurizer pressure, pressurizer water, level, reactor coolant temperature and steam generator pressure within prescribed limits and no plant technical specificaiton parameters were violated. When the turbine generator trip was initiated to perform the loss of offsite power portion of the test

'both diesel enerators started, however, the B diesel generator breaker failed to remain closed. The test, was continued with the A diesel generator only. Pressurizer pressure, water level, reactor coolant temperature and steam generator pressure were maintained within prescribed linits for a 30 minute period without offsite power. The B diesel generator breaker failure was found to be caused by a broken terminal lug on the bus differential current relay. The broken terminal lug'was repaired and a loss of offsite: power test for the B train only was performed. The B diesel generator started and. its breaker closed satisfactorily .

6.b.3 Conclusions Items 1, 2 and 3 of the test objections listed above were acceptance criteria of the Preoperational Test Procedure and were satisfactorily met. Item 4 was for use by Combustion Engineering. The desired data was obtained and provided to CE.

Cli Page 64 I I 6.c 10% LOAD REDUCTION - TURBINE RUNBACK 6.c.l Purpose The objectives of this test were:

1) Verify operation of the turbine DEH controller runback circuit.

2) Record the turbine generator response to an automatic load reduction of approximately 10%.

6.c.2 Test Results A turbine runback was initiated by simulating loss of a single main reedwater pump. Runback occurred without incident. Turbine generator response in shown in Figures 6.c-l and 6.c-2. Due to the fast ramp rate of the runback circuit (200% load per minute),

some overshoot in turbine first stage prssure and generator gross megawatts resulted as a was anticipated. In addition, first stage pressure before, during, and after the transient did not agree with the theoretical calibration curve (Figure 6.c-3). This disagreement is due to actual secondary plant efficiency at the time of the test being different from that which is assumed for the theoretical calibration curve.

6.c.3 Conclusions The DEH runback circuit functioned as required upon initiation of a runback signal. Turbine first stage pressure at the end of the transient was lower than predicted. However, when corrected for overshoot and plant conditions as described above, the test was successful.

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Page 68 I

6.d GENERATOR TRIP WITH SHUTDOWN OUTSIDE CONTROL ROOM 6.d.l

Purpose:

The objectives of this test were as follows:

a) Verify the reactor could be tripped from outside the control room.

b) Establish stable hot shutdown conditions with minimum shift crew.

c) Maintain Reactor Coolent System (RCS) temperature and pressure at 523 F + 5 F and 2100 psi'a + 100 psia respectively.

d) Maintain steam generator levels at 65% + 15%.

e) Verify RCS boron concentration can be increased by at least 10 ppm from outside the control room.

6.d.2 Test Results A brush recorder was connected to monitor some of the above parameters in addition to the permanent strip chart recorders in the Control Room. All the above were satisfactorily completed from outside the Control Room, either via the Hot Shutdown Panel or locally.

Boration was performed by a manual operation of the boric acid gravity feed valves. Backup personnel were stationed in the Control Room to ensure the plant was under control at all times.

No intervention by the Control Room personnel was necessary 6.d.3 Conclusions Controlling the plant from outside the Control Room requires good coordination and communciation between operational personnel.

This was present during the test as evidenced in the overall performance and expedious completion (less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) of the test. Performing this type of test also identifies key areas of design improvement or the need for modification/classification of procedures.

Page 69 6.e GENERATOR TRIP AT 100% POWER 6.e.l ~Pur ose The objective of this test was to verify that the dynamic response of plant systems and controls for a generator trip transient were in accordance with design requirements and as predicted by the CE System Excursion Code NSSS simulation (CESEC).

6.e.2 Test Results The required initial plant conditions were satisfactorly achieved prior to the generator trip. All Single Value Acceptance Criteria (SVAC) parameters were satisfactorily recorded on the Transient Data Acquisition System Computor at 10 scans per second throughout the trip transient. No operator actions were required or taken during the first 60 second after the trip.

The following tables lists the SVAC parameters, the actual values observed during the transient and the acceptable SVAC values.

Parameter Observed Value SVAC Value 2A S/G Pressure 951. 74 psi a (max. ) < 990 psia 2B S/G Pressure 943.59 psia (max.) < 990 psia Pressurizer Pressure 2266.66 psia (max.) < 2340 psia Pressurizer Level 39.14% (min.) > 34%

2A Hot Leg Temperature 543.51 F (min.) '> 538 F 2B Hot Leg Temperature 542.38oF (min.) > 538 F 6.e.3 Conclusions The generator trip test was successfully completed and satisfactory results were achieved. All SVAC parameters remained well within their respective limits and plant conditions required no operator actions in the initial 60 seconds of the transient.

Plant systems and controls responded as predicted and recovery from the transient was without incident.

Page 70 6.f

~ EVALUATION OF CORE PERFORMANCE 6.f.l

~ ~ Purpose The objective of the core performance record is to verify steady state equilibrium xenon core power distributions and peaking factors are within acceptable limits at various power levels.

NOTE: Equilibrium xenon was established as per the guidelines of the Power Ascension Document. The specific acceptance criteria applied to the measured core power distributions are listed below:

1) CECOR calculates an axially integrated core radial power distribution and relative power density for each of the 217 fuel bundles in the core from incore detector signals. A core radial power distribution prediction for 50%, 80% and 100%

power has been supplied by Combustion Engineering. The Root Mean Square (RMS) difference between the actual calculated radial power and the predicted radial power distribution shall be less than 3.0%.

2) Similarly, CECOR calculates a 51 point core average axial power distribution. The RMS difference between the CECOR calculated and the CE predicted axial power distribution shall be less than 3.0%.

3) The CECOR code also has the capability of calculating peaking factors and azimuthal power tilt. The measured peaking factors and tilt shall be less than allowed by applicable Technical Specifications. For the peaking factors listed below, the CECOR calculated values shall be within 7.5% of the CE predicted values for the 50%, 80% and 100% power levels:

Core maximum unrodded planar radial peaking factor F Core maximum unrodded integrated radial peaking factor F ~

Core average axial power peaking factor Fq: Core 3-D power peaking factor 6.f.2 Test Results The power distribution summary for 50%, 80%, and 100% power is given in Table 6.f-l. Tables 6.f-2, 6.f-3, and 6.f-4 represent the radial power distribution comparison for the various power levels. Figure 6.f-l is provided for correlation of the information in Tables 6.f-2, 6.f-3 and 6.f-4. Table 6.f-5 represents the axial power distribution for the various power levels. Table 6.f-6 is the peaking factor and tilt summary with respect to applicable Technical Specifications for the 20%, 50%,

80% and 100% power levels.

Page 71 6.f EVALUATION OF CORE PERFORHANCE (Cont.)

6.f.3

Conclusions:

At steady state equilibrium xenon, the measured peaking factors and tilts determined from incore detector flux maps are less than allowed by the applicable Technical Specifications at the 20%,

50%, 80% and 100% power plateaus. The axial and radial core power distributions are in satisfactory agreement with the predictions. The measured peaking factors are in satisfactory agreement with'he predictions.

Page 72 TABLE 6.f-l POWER DISTRIBUTION

SUMMARY

50%, 80% AND 100% POWER Results at Acceptance Power Level P~TER Criteria 50% 80% 100%

7 17 83) (7 22 83) 8-9-83 RMS Difference Radial Power Distribution < 3.0% 1.665% 2.705% 2.75%

RMS Difference Axial Power Distribution <3.0% 1.850% 2.953% 1.61%

50% Power Date 7/7/83 Acceptance PAKQKTER Measured Predicted Difference Criteria Fxy Core Maximum Unrodded Peaking Factor Planar Rad ial  %

1.462 1.388 5.33% < + 7.5%

F Core Maximum Unrodded Integrated Radial Peaking Factor 1.398 1.352 3. 40% < + 7.5%

F Core Average Axial Power Peaking Factor 1.272 1.256 1.27% < + 7.5%

F Core 3-D Power Peaking Factor 1.769 1. 693 4 49% < + 7.5%

80% Power Date 7/22/83 Acceptance PARAMETER Measured Predicted  % Difference Criteria F y: Core Maximum Unrodded Planar Radial Peaking Factor 1.4203 1.386 2.47% < + 7.5%

Fr. Core Maximum Unrodded Integrated Radial Peaking Factor 1.3704 1.367 0.25% < + 7.5%

Fz. Core Average Axial Power Peaking Factor 1.2644 1. 280 -1.22% < + 7.5%

Fq Core 3-D Power Peaking Fact'or 1.7299 1.745 -0.87% < + 7.5%

Page 73 TABLE 6.f-l POWER DISTRIBUTION

SUMMARY

50%, 80% AND 100% POWER

-continued-100% Power Date 8/2/83 AccePtance xy'ARAMETER Core Maximum Unrodded Planar Radial Measured Predicted  % Difference Criteria Peaking Factor 1.447 1.415 2.26% < + 7.5%

F : Core Maximum Unrodded Integrated Radial Peaking Factor '1.372 1.397 -1. 79% < + 7.5%

F : Core Average Axial Power Peaking Factor 1. 289 1. 290 -0.08% < + 7.5%

F : Core 3-D Power Peaking Factor 1.798 1.796 < + 7.5%

q

4

~ ~

Page 75 TABLE 6.f-2 RADIAL POWER DISTRIBUTION COMPARISON 50% POWER Date 7/17/83 OCTANT OCTANT OCTANT OCTANT BOX NO. MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN

.725 .681 .680 .681 .679 .681 .7 .681

.950 .912 .917 .912 .917 .912 .933 .912

.638 .629 .659 .629 .656 .629 .617 .629

.879 .863 .881 .863 .880 .863 .854 .863 1.013 .985 .992 .985 .991 .985 .987 .985 1.183 1.146 1.156 1.146 1.155 1.146 1.159 1.146 1.077 1.053 1.043 1.053

.758 .686 .705 .686 .697 .686 .711 .686 1.022 .986 1.007 .986 1.004 .986 .987 .986 10 1.012 .999 1.016 .999 1.015 .999 .981 .999 1.010 1.005 1.004 1.005 1.004 1.005 .988 1.005 12 1.078 1.089 1.101 1.089 1.101 1.089 1.063 1.089 13 1.033 1.039 1.041 1.039 14 .860 .831 .842 .831 15 1.025 .992 1.002 .992 1.003 .992 1.007 .992 16 1.002 .997 .995 .997 .996 .997 .998 .997 17 1.117 1. 096 1.085 1.096 1.09 1. 096 1. 099 1. 096 18 1.047 1.05 1.05 1.05 1.051 1.05 1.028 1.05 19 1. 130 1.116 1.139 1.116 20 .994 .989 .991 .989 21 1.088 1.092 1.112 1.092 1.107 1.092 1.095 1.092 22 1.049 1.051 1.052 1.051 1.046 1.051 1.039 1.051 23 1. 132 1.124 1.145 1.124 1.141 1.124 1.109 1.124 24 1.065 1.064 1.070 1.064 25 1.052 1.051 1.044 1.051 26 1.142 1.127 1.151 1.127 1.127 1.127 1.131 1.127 27 1.066 1.071 1.075 1.071 1.067 1.071 1.053 1.071 28 1.149 1.138 1.147 1.138 29 1.072 1.073 1.06 1.073 30 1.137 1.144 1. 158 1.144 1.152 1.144 1.130 1.144 31 1.07 1.081 1.078 1.081 32 1.074 1.084 1.071 1.084 33 1. 153 1. 151 1. 151 1. 151 34 1.071 1.087

Page 76 TABLE 6.f-2 RADIAL POWER DISTRIBUTION COMPARISON 50% POWER

-continued- Date 7/17/83 OCTANT OCTANT OCTANT OCTANT BOX NO. MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN lKASUPiED DESIGN

.713 .681 .663 .681 .668 .681 .703 .681

.936 . 912 .879 . 912 .899 .912 .942 . 912

.616 .629 .632 .629 .655 .629 .622 .629

.853 .863 .855 .963 .873 .863 .859 .863

.989 .985 .964 .985 .977 .985 .993 .985 1.161 1.146 1.128 1.146 1.134 1.146 1. 168 1.146 1.063 1.053 1.021 1.053

.718 .686 .682 .686 .699 .686 .725 .686

. 984 .986 .976 .986 1.003 .986 .995 .986 10 .977 .999 .991 .999 1.010 .999 .986 .999

.982 1.005 .983 1.005 .994 1.005 .993 1.005 12 1.051 1.089 1.076 1.089 1.081 1.089 1.065 1.089 13 1. 018 1.039 1.015 1.039 14 . 830 . 831 .846 .831 15 .993 .992 .975 .992 1.005 .992 1.008 .992 16 .974 .997 .976 .997 .992 .997 .986 .997 17 1.088 1.096 1.079 1.096 1.087 1.096 1.105 1.096 18 1.021 1.05 1.028 1.05 1.032 1.05 1.043 1.05 19 20 1.109 1.116 1.098 l. 116

.969 .989 .985 .989 21 1.065 1.092 1.087 1.092 1.099 1.092 1.077 1.092 22 1.02 1.051 1.03 1.051 1.035 1.051 1.042 1.051 23 1.099 1.124 1.121 1.124 1.124 1.124 1.138 1.124 1.043 1.064 1.049 1.064 25 1.026 1.051 1.034 1.051 26 27 1.122 1.054 1.127 1.071 1.110 1.127 1.111 1.127 l. 131 1 . 127 1.055 1.071 1.0SS 1.071 1.064 1.071 28 1.137 1.138 1.138 1.138 29 1.058 1.073 1.056 1.073 30 31

1. 153 1.07 1.144 1.145 1.144 1.143 l. 144 1.135 1.144 1.081 1.066 1.081 32 1.07 1.084 1.065 1.084 1.1 1 1.13 1.151 34

Page 77 TABLE 6.f-3 RADIAL POWER DISTRIBUTION COMPARISON 80% POWER Date 7/22/83 OCTANT OCTANT OCTANT OCTANT BOX NO. MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN

.6975 .644 .6648 .644 .6636 .644 .6745 .644

.9273 .857 .8967 .857 .8962 .857 .9098 .857

.6287 .6 .6426 .6 .6386 .6 .6087 .6

.8656 .825 .865 .825 .8618 .825 .8402 .825

.9935 .951 .9692 .951 .9656 .951 .9679 .951 1.1601 1. 103 1.1324 1.103 1.131 1.103 1. 1354 1.103 1.0578 1.017 1.0165 1.017

.7423 .66 .689 .66 .6896 .66 .6975

'66 1.0092 .952 .9954 .952 .9913 .952 .9746 .952 10 .9988 .977 1.0066 .977 1.0046 .977 .9676 .977 1.0013 .993 .9951 .993 .9946 .993 .9788 .993 12 1.074 1.079 1.0914 1.079 1.0911 1.079 1.0556 1.079 13 1.0263 1.032 1.032 1.032 14 .8518 .813 .834 .813 15 1.0202 .981 .9973 .981 .9986 .981 1.0014 .981 16 1.001 .997 .9948 .997 .9947 .997 .9857 .997 17 1. 1182 1.103 1.0914 1.103 1. 0952 1.103 1.0994 1.103 18 1.0514 1.062 1.0541 1.062 1.0545 1.062 1.0317 1.062 19 1.1336 1.13 1.1478 1.13 20 .9964 .994 .9924 .994 21 1.1013 1.108 1.1171 1.108 1.1135 1.108 1.1052 1.108 22 1.06 1. 075 1.0597 1.075 1.0562 1.075 1.0485 1.075 23 24 1.1488 1.0788 1 . 154 1 ~ 1554 1. 154 1.1533 l. 154 1.1248 1.15 1.094 1.0831 1.094 25 1.0624 1.078 1.057 1.078 26 1.1581 l. 164 1.161 1.164 1.1479 1.164 1.1475 1.164 27 1.0848 1.111 1.0905 1.111 1.0859 1.111 1.0715 1.111

1. 1704 l. 182 1.1704 1.182 29 1.09 1.116 1.0812 1. 116 30 1.1666 1. 194 1.1812 l. 194 1.1767 1.194 1.157 1.194 31 1.0949 1.13 1.102 1.13 32 1.1005 1.136 1.0973 1. 136 33 1. 1824 1.207 1.1839 1.207 34 1.1006 1.142

Page 78 TABLE 6.f-3 RADIAL POWER DISTRIBUTION COMPARISON 80% POWER

-contlnued-Date 7/22/83 OCTANT OCTANT OCTANT OCTANT BOX NO. MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN

.6862 .644 .649 .644 .6532 .644 .6801 .644

.9132 .857 .8783 .857 .8801 .857 .9212 .857

.6078 .6 . 615 .6 . 639 .6 .6135 .6

.84 .825 .8385 .825 .8565 .825 .8461 .825

.9695 .951 . 9418 .951 .9535 .951 .9751 .951 1.1358 1.103 1.1068 1.103 1.1124 1. 103 1.1456 1.103 1.04 18 1.017 .9973 1.017

.7033 .66 .6755 .66 .6915 .66 .7125 .66

.9722 .952 .9653 .952 .9615 .952 .9831 .952 10 .9664 .977 .9817 .977 .9999 .977 .9736 .977

.9727 .993 .9752 .993 .9855 .993 .9839 .993 12 ~I.O 09 1.079 1.0677 1.079 1.0727 1.079 1.0573 1.079 13 1.0088 1.032 1.0075 1.032 14 .8224 .813 .8392 .813 15 .9888 .981 .9781 .981 1.0002 .981 1.0034 .981 16 .9729 .997 .9759 .997 .9916 .997 .9849 .997 17 1.0881 1.103 1.0841 1.103 1.0925 1.103 1.1058 1.103 18 1.023 1.062 1.0323 1.062 1.036 1.062 1.0462 1.062 19 1.1109 1.13 1.1059 1.13 20 .9781 .994 .9874 .994 21 1.0763 1.108 1.0945 1.108 1.1062 1.108 1.0876 1.108 22 1.0346 1.075 1.0418 1.075 1.0466 1.075 1.0533 1.075 23 1.1136 1.154 1.1358 l. 154 1.1379 1.154 1.1556 1.154 24 1.055 1.094 1.064 1.094 25 1.0 08 1.078 1.0477 1.07 1.1397 1.164 1.1344 1.16 1.1324 1.164 1.1484 1.164 27 1.0729 1.111 1.0763 1.111 1.0758 1.111 1.0832 1.111 28 1.1575 1.182 1.1657 1.182 1.0809 l. 116 1.0773 1. 116 30 l. 182 1 . 194 1.1717 l. 194 1.1691 1.194 1.1624 1.194 31 1.0943 1.13 1.0927 1.13 32 33 1.1828 1.207 1.097 1.13 1.0925 l. 136

1. 166 1.207

Page 79 TABLE 6.f-4 RADIAL POWER DISTRIBUTION COMPARISON 100% POWER Date 8/2/83 OCTANT OCTANT OCTANT OCTANT BOX NO. MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN

.674 .625 .65 .625 .648 .625 .654 .625

.902 .828 .874 .828 .873 .828 .888 .828

.615 .584 .622 .584 .617 .584 .596 .584

.848 .805 .844 .805 .84 . 805 .825 .805

.98 . 936 .952 . 936 .948 .936 .957 .936 1.147 1.085 1.119 1.085 1. 118 1.085 1.125 1.085 1.046 1.002 1.001 1.002

.72 .645 .683 .645 .675 .645 .679 .645

.993 .936 .98 . 936 .977 .936 .961 .936 10 .988 .968 .996 .968 .995 .968 .958 .968

.995 .987 .988 .987 .989 .987 .975 .987 12 1.074 1.076 1.089 1.076 1.089 1.076 1.058 1.076 13 1.024 1.029 1.029 1.029 14 .838 .803 .823 .803 15 1.013 .976 .991 .976 .994 .976 .996 .976 16 .999 .997 .993 .997 .994 .997 .985 .997 17 1.121 1. 108 1. 096 1. 108 1.103 1.108 1.104 1.108 18 1.056 1.068 1.059 1.068 1.06 1.068 1.038 1.068 19 1.14 1.138 1.158 1.138 20 .996 .996 .993 .996 21 1.117 1.123 1.117 1.12 1.117 1.116 1. 117 22 1.069 1.086 1.069 1.086 1.066 1.086 1.059 1.086 23 1. 164 1. 169 1. 169 l. 169 1. 167 1. 169 1.14 1.169 1.092 1. 108 1.096 1. 108 25 1.073 1.091 1.069 1.091 26 l. 175 1. 182 1.18 l. 182 l. 166 1. 182 1. 165 l. 182 27 1. 103 1.13 1.108 1.13 1.103 1.13 1.089 1.13

l. 191 1.204 1.192 1.204 1.136 1.136 30 1. 194 1. 219 1.205 1.219 1.2 1.219 1.183 1.219 31 1.118 1. 153 1.124 1.153 32 1.125 1.16 1.121 1.16 33 1.21 1.235 1.212 1.235 34 1. 126 1.168

Page 80 TABLE 6.f-4 RADIAL POWER DISTRIBUTION COMPARISON 100% POWER

-continued-Date 8/2/83 OCTANT OCTANT OCTANT OCTANT BOX NO. MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN MEASURED DESIGN

.665 .625 .633 .625 .637 .625 .66 .625

.89 .828 .854 .828 .856 .828 .897 .828

.596 .584 .596 .584 .62 .584 .599 .584

.825 .805 .818 .805 .836 .805 .829 .805

.958 . 936 .923 .936 .935 .936 .962 .936 1.125 1.085 1.092 1.085 1.097 1.085 1.133 1.085 1.032 1.002 .98 1.002

.683 .645 .661 .645 .677 .645 .691 .645

.959 . 936 .951 .936 .976 .936 .967 .936 10 .958 .968 .972 .968 .989 .968 .962 .968

.968 .987 .968 .987 .978 .987 .977 .987 12 1.041 1.076 1.064 1.076 1.069 1.076 1.055 1.076 13 1.009 1.029 1.003 1.029 14 .81 .803 .826 .803 15 .983 .976 .966 .976 .993 .976 .995 .976 16 .972 .997 .975 .997 .989 .997 .982 .997 17 1.092 1.108 1.091 1.108 1.098 1.108 1.108 1.108 18 1. 029 1.068 1.037 1.068 1.04 1.068 1.051 1.068 19 1.119 1.138 1.114 1.138 20 .972 .996 .986 .996 21 22 1.086 1.045 1.117 1.086

1. 101 1. 117 1.112 1.117 1.095 l. 117 1.053 1.086 1.056 1.086 1.063 1.086 23 24 1.13 1.068

1. 169 1.149 1. 169 1.151 1.169 l. 172 1.169 1.108 1.076 1.108 1.053 1.091 1.059 1.091 1.157 1. 182 1. 15 l. 182 1. 153 1. 182 1.166 1.182 27 1.091 1.13 1.095 1.13 1.094 1.13 1. 101 1.13

1. 178 1.204 1. 187 1. 204 29 1. 101 l. 136 1.097 1.136 30 1. 208 l. 219 l. 196 1. 219 1. 193 l. 219 1. 189 1.219 31 1.117 l. 153 1.115 1. 153 1.16 33 1.21 1. 235 l. 196 1.235

Page 81 TABLE 6.f-5 AXIAL POWER DISTRIBUTION COi4PPARISON PERCENT 50% POWER 80% POWER 100 o POWER CORE (7/17/83) (7/22/83) (8/9/83)

• HEIGHT MEASURED PREDICTED MEASURED PREDICTED MEASURED PREDICTED

. 370 .379 .373 .383 .371 .385

.463 .482 .457 .486 .46 .490

.534 .573 .538 .578 .545 .583

.611 .654 .616 .660 .627 .667

.685 ~ 727 .690 .734 .705 .743 10 .755 .792 .760 .801 .779 .812 12 . 820 .851 .825 .862 .847 .874 14 .881 .904 .886 .918 .911 .932 16 .937 .953 .941 .969 .970 .984 18 .989 .997 .992 1.015 1.024 1.031 20 1.035 1.037 1.038 1.057 1.072 1.074 22 1.077 1.072 1.079 1.095 1.115 1.112 24 1.105 1.115 1.129 1. 153 1.1 7 26 1.146 1.133 1.147 1.159 1. 186 1.177 28 1. 175 1.158 1. 174 1.186 1.214 1.203 30 1. 198 1. 180 1. 197 1.208 1.238 1.225 32 1.218 1. 199 1.216 1.228 1.257 1.244 1.235 1.215 1.231 1.244 1.272 1.259 36 1.248 1.228 1.243 1.256 1. 284 1.271 38 1.258 1.238 1.252 1.266 1. 292 1.280 40 1. 265 1.246 1.259 1. 273 l. 297 1. 286 42 1.269 1.251 1.263 1.278 1. 299 1.289 44 1.272 1.255 1.264 1.280 1. 298 1.290 46 1.272 1.256 1.264 1.280 l. 296 1.289

l. 271 1.256 1.263 1. 278 1.291 1.285 50 1.267 1.254 1.259 1.273 1.284 1.279 52 1. 263 1 ~ 251 1. 255 1. 267 1. 275 1. 271 54 1.256 1.2 6 1.249 1.259 1.2 5 ~ 1.262 56 1.248 1. 239 1.241 1.249 1.252 1.250 58 1.239 1.231 1.232 1.237 1.238 1.236 60 1.227 1.221 1.222 1.223 1.222 1.220 62 1.214 1. 208 1. 209 1.206 1.205 1.202 64 1. 199 1. 194 1. 195 1. 188 1. 185 1. 182 66 1.182 1. 177 l. 179 1.167 1. 162 1.159 68 1.162 1.157 1. 160 1.143 1.138 1.133 70 1. 139 1.134 1.139 1.116 1.111 1. 104 72 1.114 1.108 1.114 1.086 1.081 1.073 74 1.085 1.079 1.086 1.053 1.048 1.038 76 1.052 1.047 1.055 1.017 1.012 1.001 78 1.016 1.011 1.019 .978 .972 .961 80 .976 .972 .980 .936 .929 . 917 82 .931 .929 .936 .891 .883 .871

.883 .883 .888 .8 3 .833 .82 86 .830 .833 .836 .792 .779 .770 88 .773 .779 .779 .737 .722 .715 90 .711 .721 .718 .679 .661 .657 92 .646 .657 .652 .617 .597 .594 94 .577 .586 . 583 .548 .530 .527 96 .50 .505 .509 .471 .459 .452 98 .428 .411 .433 .383 .387 .367 100 .349 . 296 .353 . 279 .312 .268

0 Page 82 TABLE 6.F-6 PEAKING FACTOR AND TILT COMPLIANCE WITH TECHNICAL SPECIFICATIONS FOR 20%, 50%, 80% AND 100% POWER LEVELS F T: Total Planar Radial Peaking Factor F T: Total Integrated Radial Peaking Factor Tq + Azimuthal Power Tilt PNU4%TER 20% POWER 50%" POWER 80% POWER 100% POWER TECHNXCIAL SPECIFICATION.

MEASURED MEASURED MEASURED MEASURED LIMIT Date 6-15-83 7-.17-83 7-22-83 8-2-83 N A 1.581 1.444 1.409 1'. 418 1.60 F T 1.485 1.416 1.388 1.390 Tq 0.021 0.015 0.01 0.016 0.0

Page 83 6.g AT'POWER MODERATOR TEMPERATURE COEFFICIENT AVD POWER COEFFICIENT TEST 6.g.l PURPOSE The purpose of this test was to measure the Power Coefficient and the Isothermal Temperature Coefficient (ITC) and derive the Moderator Temperature Coefficient at 50%, 80%, and 100% reactor power. The measured coefficients shall be in satisfactory agreement with the predictions and are conservative with respect to the Technical Specifications.

6.ge2 TEST RESULTS Variable Tav tests were conducted at the 50%, 80% and 100% power plateaus witf the lead bank of CEAs, Group 6, at approximately 110 inches withdrawn and equilibrium xenon and boron conditions established as per the guidelines of the Power Ascension Document. The 50% test was conducted with the ITC and Power Coefficient as separate tests. During the ITC test, Delta T power was held constant and Reactor Coolant System (RCS) T ave was varied. Tavg was decreased aPProximately 5oF below the original temperature and CEA Group 6 was moved. to maintain constant power. Conditions were stabilized, data recorded and Tav inoreaaed to the original temperature. Condition were aNain stabilized and data recorded. This cycle was repeated.

The Power Coefficient Test was conducted by maintaining T constant and varying Delta T power. Delta T power was decreased approximately 5% and CEA Group 6 was moved to maintain constant temperature (Tav ). Conditions were stabilized, data recorded and power was increased to the original value. Conditions were again stabilized and data recorded. This cycle was repeated.

The final ITC and Power Coefficient values were the average value of the runs conducted. This test was performed similarly for the 80% and 100% plateaus. The Moderator Temperature Coefficient (MTC) is calculated by subtracting the Fuel Temperature Coefficient from the ITC. The Fuel Temperature Coefficient is pre-calculated by CE. The measured values and limits for the ITC, HTC and Power Coefficient for the 50%, 80% and 100% power plateaus are given in Table 6.g.l.

6.g.3 Conclusions The measured Isothermal Temperature Coefficients are in satisfactory agreement with CE predictions. The Moderator Temperature Coefficients determined at the 50%, 80% and 100% power plateau are conservative with respect to the Technical Specifications and are in satisfactory agreement with CE predictions. The measured Power Coefficients are in satisfactory agreement with CE predi.ctions.

TABL 6.g-l Page 84 MEASURED ISOTHERMAL TEMPERATURE COEFFICIENT (ITC), POWER COEFFICENTS (PC)

AND DERIVED &MODERATOR TEMPERATURE COEFFICIENT (MTC) AT 50%, 80%, AND 100% POWER LEVELS Parame ter DATE POWER LEVEL Measured Value Acceptance Criteria*

7-15-83 50%

ITC -0.720 x 10 4 4K/K/oF (-0.700 + 0.3) x 10 E K/K/ F PC -0.862 x 10 4 QK/K/% pwr (-0.888 + 0.2) z 10 4 4 K/K/% pwr HTC -0.576 x 10 DK/K/ F (-.556 + 0.3) x 10 4 D K/K/oF MTC ( + 0.5 X 10 " DK/K/ F 7-21-83 80%

ITC -0.752 x 10 " QK/K/ F (-0.848 + 0.3) x 10 " EK/K/ F PC -0.760 x 10 4 AK/K/% pwr (-.793 + 0.2) x 10 4 < K/K/% pwr MTC -0.6155 x 10 E K/K/ F (-.712 + 0.3) x 10 < K/K/ F MTC ( +0.0 X 10 < K/K/ F 8-3-83 100%

ITC -0.860 x 10 b.K/K/ F (-0.937 + 0.3) x 10 Q K/K/ F PC -0.764 x 10 4 Q K/K/% pwr (-0.736 + 0.2) x 10 " A K/K/% pwr MTC -0.728 x 10 4 hK/K/oF (-.805 + 0.3) x 10 " A K/K/'F MTC > 2 7 X 10-4 ~ K/K/oF

• Represents CE predictions with acceptance criteria applied (FSAR Table 14.2-3)

6.h NUCLEAR POWER ELTA T POWER CORRELATION Page 85 6.h.l Purpose The purpose of this test was to:

(1) Determine the core thermal power by a primary plant heat balance (20% power plateau) and by the Digital Data Processing System (DDPS) for the 50%, 80% and 100% power plateaus.

(2) Adjust the Power Range Safety Channels and Delta T Power reference calculators to agree with the primary plant heat balance at the 20% power plateau.

(3) Adjust the Power Range Safety Channels and Delta T Power reference calculators to agree with the primary thermal energy balance calculations as calculated by the DDPS at the 50%, 80%

-and 100% power plateaus.

6.h.2 Test Results At the 20% power plateau, Nuclear Power and Delta T Power were adjusted to agree with the primary manual calorimetric within 0.5 percent. These values are given in Table 6.h-l.

At the 50%, 80% and 100% power plateaus, Nuclear Power and Delta T Power were adjusted to agree with the DDPS thermal calorimetric within 0.5 percent. Th'ese values are given in Table 6.h-2.

6.h.3 Conclusions The Nuclear Power and Delta T Power calibrations were performed at the 20%, 50%, 80% and 100% power plateaus and all results were within acceptable limits.

t TABLE 6.h 1 NUCLEAR AND DELTA T POWER CALIBRATION t Page 86 20% Power Date 6/15/83 Primary Calorimetric Power = 19.195%

Channel a) Nuclear Power 19. 19 19. 19 19. 19 19. 19

(%)

b) Delta T Power 19. 17 19. 16 19.42 19.25

(%)

c) (Primary Calorimetric .005 .005 .005 .005 Power) minus (Nuclear Power) (%)

d) (Primary Calorimetric 0.025 0.035 -0225 .055 Power) minus (Delta T Power) (%)

TABLE 6.h-2 Page 87 NUCLEAR AND DELTA T PONER CALIBRATION 50% Power Date 7/15/83 DDPS Calorimetric Power (PID 31) = 50.43%

Channel a) Nuclear Power 51.20 51.53 51.55 50.36

(%)

b) Delta T Power 51.21 51.28 51.76 51.52

(%)

c) (Primary Calorimetric -0.10 -0.10 -0.12 +0.07 Power) minus (Nuclear Power) (%)

d) (DDPS Calorimetric +O. 23 +0. 15 -0. 33 -0. 09 Power) minus (Delta T Power) (%)

80% Power Date 7/20/83 DDPS Calorimetric Power (PID 31)~ -80.58%

Channel a) Nuclear Power 80.73 80.65 80.52 80.50

(%)

b) Delta T Power 80.63 80.72 80.71 80.42

(%)

c) (Primary Calorimetric .15 .07 +.06 +.08 Power) minus (Nuclear Power) (%)

d) (Primary Calorimetric .05 .14 .13 +. 16 Power) minus (Delta T Power) (%)

TABLE 6.h-2 Page 88

-continued-100% Power Date 8/3/83 DDPS Calorimetric Power (PXD 31) = 99.58%

Channel a) Nuclear Power 99. 57 99.57 99.61 99.68

(%)

b) Delta T Power 99.32 99.56 99.73 99.99

(%)

c) (DDPS Calorimetric +.01 +.01 -.03 .10 Power) minus (Nuclear Power) (%)

d) (DDPS Calorimetric +.26 +.02 .15 ..41 Power) minus (Delta T Power) (%)

6. i NATURAL CIRCULA Page 89 6.i. 1 ~Pur ose The purpose of this test was to:

a) Provide operator training for the natural circulation mode of cooling the Reactor Coolant System (RCS) and to b) Monitor key RCS and secondary parameters to better define and identify plant transition into the natural circulation totally utilized both steam generators. Depressurization and cooldown rates and subcooled margin were easily maintained at all times.

without any uncontrolled ocillation of primary or secondary temperatures, pressures or levels.

All available 11censed operators particapated in at least one of the natural circulation tests performed on two different shifts.

6.i.3 Conclusions Performing natural circulation training by this method provides meaningful operation training. However, it is not intended to verify that the basic RCS des1gn configuration is adequate to support natural circulation, which was verified earilier on an identical RCS (St. Lucie Unit 1)

All the acceptance criteria for this test were met. However, performing natural circulation training on a un1t in the Startup phase in unnecessory. Simulators available today offer equ1valent or even better training in the natural circulation mode.

6.). DIGITAL DATA PRASOR INSTRUNEN'I CORRELATION Page 90 6.).1 ~Pur ose The objective of this test was to demonstrate the operation of the Digital Data Processor.

6.j.2 Test Results At the test plateaus of 0, 20, 50, 80 and 100% power, the Digital Data Processor inputs were compared with related process instrumentation. The safety related channel correltion were within the loop accuracies specified by the NSSS Vendor. The objective- was= satisfactorily completed.

6. j .3 Conclusion The Digital Data Processor is capable of accumately- monitoring certain process parameters. as demonstrated by meeting the acceptance criteria.

6.k VENTILATION AND CONDITIONING SYSTEN CAPABIL S Page 91 6.k. 1 ~Pur ose To demonstrate that the heating, ventilating, and air conditioning (HVAC) systems for the containment, and areas housing Engineered Safety Features (ESF) maintain design temperatures, at 50% power, 100% power and during Shutdown Cooling in the ECCS pump and heat exchanger areas.

6.k.2 Test Results All of the above were satisfactorily completed. The temperature reading at the 50% power level were all within the acceptable limit as on Data Sheets NBo. 1, No. 2 and No. 3. Also, the reading at the 100% power level were within the acceptable limit as on Data Sheets No. 4, No . 5 and No . 6. All of the temperaturee reading taken while on Shutdown Cooling were within the 104 F acceptance limit as seen on Table 6.k.7.

6.k.3 Conclusions The temperature conditions within the Containment, the ESF areas, and the Fuel Handling Building were all maintained within the acceptable limits as indicated on Tables 6.k.l through 7. The above limits were not exceeded during the 50% or 100% power levels or during the periods Shutdown Cooling was in service.

TABLE 6.jc.1, NO. 1 Page 92 REMOTE..TEMPERATURE- READINGS AT APPROXIMATELY 50%

Page 2 of 2 LOCATION TEMP . READ ING ACCEPTABLE IN DEGREES F TEMP. LIMIT TE-07-3A Containment Temp. 105oF <120F TE-07-5A Cont. Sump. Temp. 90'F < 120 F TE-07-3A Containment 110 F < 120oF Temp.'E-07-5BA Containment Sump. Temp. S7'F < 120oF TE-25-14 CEDM Cooling 130 F < 150oF Coil Inlet

t TABLE 6.k.2 RAB LOCAL TEMPERATURE READING AT APPROXIMATELY 50% POWER Page 93 TEMP . READING ACCEPTABLE LOCATION IN DEGREES oF TEMP. LIMIT Between 2HVE 6A and 10 F 2HVE-6B SBVS Filter Trains 90oF < 104oF Iodine Removal System Hydrazine Tank and Pumps 88oF < 104oF 2A Shutdown Heat Exchanger 88 F 104 F 2B Shutdown Heat Exchanger 89 F < 104oF Refer to Figure /1 90 F 104 F

//1 for Sample fI2 91 F 104oF Location Points /f3 89oF 104 F 84 88oF < 104oF Refer to Figure f/5 87 F 104 F b2 for Sample /36 88oF 104 F Location Points f37 88oF 104oF 1!8 88oF < 104oF ik9 88oF < 104'F

//1 0 89 F 104 F Refer to Figure 3 For Samp. Loc. Points ll 89 F 104 F

>912 92 F 104oF

Page 94 RAB LOCAL TEMPERATURE READING AT APPROXIMATELY 50% POWER TEMP . READING ACCEPTABLE LOCATION IN DEGREES oF TEMP. LIMIT Between 2HVE 6A and 90 F 104 F 2HVE-6B SBVS Filter Trains 91oF < 104oF Iodine Removal System Hydrazine Tank and Pumps 90oF < 104oF 2A Shutdown Heat Exchanger 90 F 104 F 2B Shutdown Heat Exchanger 90oF < 104oF Refer to Figure /$ 1 90 F 104 F

//1 for Sample //2 90 F 104oF Location Points /l3 72oF < 104oF f34 88oF 104oF Refer to Figure 85 86 F 104 F 82 for Sample 88oF < 104 F Location Points f37 88oF 104oF f/8 85o 104oF f/9 86oF < 104oF f110 84'F < 104oF Refer to Figure 3 11 92 F < 104oF For Samp. Loc. Points 812 94oF 104oF Unit f32 Control Room 72 F 75F+5F

TABLE 6.k-3 Page 95 PUEL HANDLING BUILDING LOCAL TEMPERATURE READINGS AT APPROXIMATELY 50% POWER TEMP . READING ACCEPTABLE LOCATION IN DEGREES oF TEMP. LIMIT Spent Fuel Pool 92 F 104 F Fuel Handling 92oF 104oF Building Motor 92 F 104 F Operated Vent. 88 F 104oF Dampers 88oF 104oF H & V Equipment Room 89 F < 104 F

~ TABLE 6.k-4

~ Page 96 REMOTE TEMPERATURE READINGS AT APPROXIMATELY 100% POWER Page 1 of 2 INSTRUMENT LOCATION TEMP . READING ACCEPTABLE NOMENCLATURE IN DEGREES oF TEMP. LIMIT TE-25-1 Cont. Cooling Fan 95oF < 120oF 2HVS 1A Coolin Coil Inlet TE-25-3 Cont. Cooling Fan 100oF < 120oF 2HVS 1B Coolin Coil Inlet TE-25-17 Reactor Cavity 105oF < 140oF Coolin Sysem TE-25-11A Reactor Support 106oF < 150oF Coolin System TK-25-12A Reactor Support 108oF < 150oF Coolin System TE-25-13A Reactor Support 108oF < 150oF Coolin System TE-25-13A ESSC Pump Room A 94'F 104oF TE-25-5 Cont. Cooling Fan 106oF 120oF 2HVS 1C Coolin Coil Inlet TE-25-7 Cont. Cooling Fan 104oF < 120oF 2HVS 1D Coolin Coil Inlet TE-25-16 Reactor Cavity 104oF < 140oF TEMPERATURE Coolin System RECORDER TE-2 5-1 1B TR-25-1B Reactor Support 106oF < 150oF Cnolin System TE-25-12B Reactor Support 106oF 150oF Coolin TE-25-13B Reactor Cavity 107oF 1 50o Coolin System TE-25-23 ECCS Pump Room B 94'F < 104oF

t TABLE 6.k-5 REMOTE TEMPERATURE READINGS AT APPROXIMATELY 100%

Page 2 of 2 Page 97 LOCATION TEMP. READING ACCEPTABLE IN DEGREES oF TEMP. LIMIT TE-07-3A Containment Temp. 110oF < 120oF TE-07-5A Cont. Sump. Temp. 90oF < 120 F TE-07-3A Containment Temp. 110oF (120F TE-0 7-5BA Containment Sump. Temp. 67'F < 120 F TE-25-14 CEDM Cooling 132'F 150oF Coil Inlet

t TABLE 6.k-6 Page 98 FUEL HANDLING BUILDING LOCAL TEMPERATURE READINGS AT APPROXIMATELY 100% POWER ATMOSPHERIC TWP . READING ACCEPTABLE SAMPLE LOCATION IN DEGREES oF TEMP. LIMIT Spent Fuel Pool 8 oF < 104oF Fuel Handling D29, D30 85'F < 104oF Building Motor D31, D32 85oF < 104oF Operated Vent. D33, D34 85'F < 104 F Dampers D35, D36 85 F 104oF H & V Equipment Room 85 F < 104oF

TABLE 6.k-7 Page 99 TEMPERATURE READINGS DURING SHUTDOWN COOLING LOCATION TEMP . READING ACCEPTABLE IN DEGREES oF TEMP. LIMIT (+)

ECCS Pump Room A 89 F < 104 F ECCS Pump Room B 78 F < 104 F 2A Shutdown Heat Exchanger Room 78'F < 104oF 2B Shutdown Heat Exchanger Room 78'F 104oF

6.1 FORCED XENON OS LATION TEST Page 100 f

6.1.1 Purpose The purpose of this test was to obtain transient test data by inducing an axial xenon oscillation in the core at the 50% power plateau in order to determine the Shape Annealing Factors (SAF) for each Power Range Safety Channel and Power Range Control Channel.

6.1.2 Test Results During the 50% test plateau, an axial oscillation was induced in the core. This oscillation was monitored by the Combustion Engineering supplied incore analysis code CECOR and by the excore detectors; Power Range Safety Channels A, B,. C, and D and Power Range Control Channels 9 and 10. The SAF corrects the excore detector signal to account for the distance from the excore detector to the reactor core and corrects for the signal received by the upper detector from neutrons generated in the bottom of the core and the signal received by the lower detector from neutrons generated in the upper part of the core. Basically, the SAF is determined by plotting CECOR ASI versus the excore ASI as determined from the Power Range Safety and Control Channels during a xenon oscillation with all CEA's full out. The slope of the function depicted by this plot is the Shape Annealing Factor.

Axial Shape Index (ASI) is defined as a ratio of the difference in power generated in the lower and upper halves of the core to total core power. Table 6.1-1 summarizes the SAF measurements. Figure 6.1-1 illustrates CECOR ASI (incore) versus time for the test.

6.1.3 Conslusions The Shape Annealing Factor (SAF) values were measured, input and all in use by the Power Range Safety Channels and Power Range Control Channels as input for calculation of. the axial shape indices.

1 TABLE 6.1-1 t SHAPE ANNEALING FACTOR

SUMMARY

Page 101 Date 7/18/83 SHAPE ANNFALING FACTOR SAF Y-INTERCEPT CHANNEL (MEASURED) (MEASURED) 3.72434 -0.00310

~ 169 7 +0.00217 4.11225 -0.01083 3.52241 -0.01145 3.51525 -0.01565 10 4.19326 -0.01711

Gy 10 X 1o I<) IIII CINIIL1$ 1I lg l,l/Illiill I ' ~ (i FI 6. 1-1 ST. LUCIE UNIT 2 CYCLE 1

~r itin Page S.A.F. TEST 50% PLATEAU ASII VS TIME 1 Of l~ 00 00 20 0 00 ~ 00 )0 2 0 )0 ,80 7-17-83 7-18-83

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AB-623 FLORlDA POWER & LIGHT COMPANY ST. LUCIE UNIT 2 ANNUALENVIRONMENTAL OPERATING REPORT 1992 VOLUME 1 APRIL 1993 FLORIDA POWER 6 LIGHT COMPANY JUNO BEACH, FLORIDA APPLIED BIOLOGY, INC.

DECATUR, GEORGIA

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ENVIRONMENTALOPERATING REPORT TABLE OF CONTENTS TABLE OF CONVERSION FACTORS FOR METRIC UNITS EXECUTIVE

SUMMARY

Introduction ~..... Iil Turtle Nesting Survey ~ ~

Intake Canal Monitoring Other Related Activities INTRODUCTION

Background

Area Descriptlo'n .. -....................... ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

Plant Description TURTLES Introduction Materials and Methods 10 Nesting Survey 10 Intake Canal Monitoring Studies to Evaluate and/or Mitigate Intake Entrapment 15 Results and Discussion 15 Nesting Survey 15 Spathl Distribution of Loggerhead Turtle Nests 15 Long-Term Trends In Loggerhead Turtle Nesting 18 Seasonal Patterns of Loggerhead Turtle Nesting ~ < ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 19 Predation on Loggerhead Turtle Nests 20 Green and Leatherback Turtle Nesting 21 Intake Canal Monitoring 23 Relative Abundance and Temporal Distribution 23 Size-Class Distributions .. 26 Sex Ratios 28 Capture Efficiencies 30 Relative Condition 31 Mortalities Recapture Incklents 34 Summary 36 UTERATURE CITED FIGURES 48 TABLES

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TABLE OF CONVERSION FACTORS FOR METRIC UNITS T convert Multi I b T tin centigrade (degrees) ( C x 1.8) + 32 fahrenheit (degrees) centigrade (degrees) C + 273.18 kelvin (degrees) centimeters (cm) 3.937 x 10 inches centimeters (cm) 3.281 x 10 feet centimeters/second (cm/sec) 3.281 x 10 feet per second cubic centimeters, (cm ) 1.0 x10 liters grams (g) 2.205 x 10 pounds grams (g) 3.527 x 10 ounces (avoirdupois) hectares (ha) 2.471 acres kilograms (kg) 1.0 x 10 grams kilograms (kg) 2.2046 pounds kitograms (kg) 3.5274 x 10 ounces (avoirdupois) kilometers (km) 6.214 x 10 mites (statute) kilometers (km) 1.0 x 10 millimeters liters (I) 1.0 x 10 cubic centimeters (cms) liters (I) 2.642 x 10 gallons (US liquid) meters (m) 3.281 feet meters (m) 3.937 x 10 inches meters (m) 1.094 $ ards milligrams (mg) 1.0 x10 grams milligrams/liters (mg/I) 1.0 parts per million milliliters (ml) 1.0 x 10 liters (US liquid) millimeters (mm) 3.937 x 10 inches millimeters (mm) 3.281 x 10 feet square centimeters (cm ) 1.550 x 10 square inches square meters (m ) 1.076 x 10 square feet square millimeters (mm ) 1.55 x 10 square inches

EXECUTIVE

SUMMARY

INTRODUCTION The St. Lucie Plant is an electric generating station on Hutchinson Island in St.

Lucie County, Florida. The plant consists of two nuclear-fueled 850-MW units; Unit 1 was placed on-line in March 1976 and Unit 2 in May 1983. This document has been prepared to satisfy the requirements contained in the United States Nuclear Regulatory Commission's Appendix B Environmental Protection Plan (EPP) to St. Lucie Unit 2 Facility Operating License No. NPF-16. This report discusses environmental protection activities related to sea turtles as required by Subsection 4.2 of the EPP. Other routine annual reporting requirements are addressed in Volume 2, also entitled "St, Lucie Unit 2 Annual Environmental Operating Report".

TURTLE NESTING SURVEY Since monitoring began in 1971, there have been considerable year-to-year fluc-tuations in sea turtle nesting activity on Hutchinson Island. However, data collected through 1992 have shown no long-term reductions in nesting on the island. Relatively high nesting during recent years may actually reflect an increase in the number of nest-ing females in the study area. On a smaller scale, power plant operation has had no significant effect on nesting near the plant. Low nesting activity in 1975 and again in 1981 -1983 in the vicinity of the plant was attributed to nighttime construction activities associated with installation of plant intake and discharge structures. Nesting returned to normal or above normal levels following both periods of construction. During 1991,

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daytime construction activities associated with velocity cap repairs had no apparent ef-fect on nesting. Formal requirements to conduct nesting surveys expired in 1986 but this program was voluntarily continued through 1992 with agreement from federal and state agencies.

INTAKE CANALMONITORING

~ Since plant operation began in 1976, 2,501 sea turtles (including 124 recaptures) representing five different species have been removed from the intake canal. Eighty-two percent of these were loggerheads. Differences in the numbers of turtles found during different months and years have been attributed primarily to natural variation in the occurrences of turtles in the vicinity of the plant, rather than to operational influen-ces of the plant itself. The majority of turtles removed from the intake canal (about 93 percent) were captured alive and released back into the ocean: Ongoing evaluations and improvements to the canal capture program have substantially reduced mortalities of entrapped sea turtles during recent years. Turtles confined between the A1A barrier net and intake headwalls typically reside in the canal for a relatively short period prior to capture, and most are in good to excellent condition when caught.

OTHER RELATED ACTIVITIES Studies to evaluate various intake deterrent systems, as required by the NRC's Unit 2 Environmental Protection Plan, were conducted during 1982 and 1983. Results and evaluations of those studies were presented to regulatory agencies during 1984, and the requirement is now considered completed.

lNTRODUCTlON BACKGROUND This document has been prepared to satisfy the requirements contained in the United States Nuclear Regulatory Commission's (NRC) Appendix B Environmental Protection Plan to St. Lucie Unit 2 Facility Operating License No. NPF-16.

In 1970, Florida Power 8 Light Company (FPL) was issued Permit No. CPPR-74 by the United States Atomic Energy Commission, now the Nuclear Regulatory Com-mission, that allowed construction of Unit 1 of the St. Lucie Plant, an 850-MW nuclear-powered electric generating station on Hutchinson Island in.St. Lucie County, Florida.

St Lucie Plant Unit 1 wasylaced on-line in March 1976. In May 1977, FPL was issued Permit No. CPPR-144 by the NRC for the construction of a second 850-MW nuclear-powered unit. Unit 2 was placed on-line in May 1983 and began commercial operation in August of that year.

St. Lucie Plant Units 1 and 2 use the Atlantic Ocean as a source of water for once-through condenser cooling. Since 1971, the potential environmental effects resulting from the intake and discharge of this water have been the subject of FPL-sponsored biotic studies at the site.

Baseline environmental studies of the marine environment adjacent to the St. Lucie Plant were described in a series of reports published by the Florida Department of Natural Resources (Camp et al., 1977; Futch and Dwinell, 1977; Gallagher, 1977; Gal-lagher and Hollinger, 1977; Worth and Hollinger, 1977; MoNer and Van Breedveld,

1979; Tester and Steidinger, 1979; Walker, 1979; Walker et al., 1979; Walker and Steidinger, 1979; Lyons, 1989) The results of Unit 1 operational and Unit 2 preopera-

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tional biotic monitoring at the St. Lucie Plant were presented in six annual reports (ABI, 1977, 1978, 1979, 1980a, 1981b, 1982). In January 1982, a National Pollutant Discharge Elimination System (NPDES) permit was issued to FPL by the US Environmental Protec-tion Agency (EPA). The EPA guidelines for the St. Lucie site biological studies were based on the document entitled "Proposed St. Lucie Plant Preoperational and Opera-tional Biological Monitoring Program - August 1981" (ABI, 1981c). Findings from these studies were reported in three annual reports (ABI, 1983, 1984a, 1985a). The EPA biotic monitoring requirements were deleted from the NPDES permit in 1985.

Jurisdiction for sea turtle studies is with the NRC, which is considered to be the lead federal agency relative to consultation under the Endangered Species Act.

Previous results dealing exclusively with sea turtle studies are contained in nine annual environmental operating reports covering the period from 1983 through 1991 (ABI 1984b, 1985b, 1986, 1987, 1988, 1989, 1990, 1991, 1992). This report describes the 1992 environmental protection activities related to sea turtles, as required by Subsec-tion 4.2 of the St. Lucie Plant Unit 2 Environmental Protection Plan.

AREA DESCRIPTION The St.:Lucie Plant is located on a 457-ha site on Hutchinson Island on Florida's east coast (Figures 1 and 2). The plant is approximately midway between the Ft. Pierce and St. Lucie Inlets. It is bounded on its east side by the Atlantic Ocean and on its west side by the Indian River Lagoon.

Hutchinson Island is a barrier island that extends 36 km between inlets and ob-tains its maximum width of 2 km at the plant site. Elevations approach 5 m atop dunes bordering the beach and decrease to sea level in the mangrove swamps that are com-mon on much of the western side. Island vegetation is typical of southeastern Florida coastal areas; dense stands of Australian pine, palmetto, sea grape and Spanish bayonet are present at the higher elevations, and mangroves abound at the lower eleva-tions. Large stands. of black mangroves, including some on the plant site, have been killed by fiooding for mosquito control over past decades.

The Atlantic shoreline of Hutchinson Island is composed of sand and shell hash with intermittent rocky promontories protruding through the beach face along the southern end of the island. Submerged coquinoid rock formations parallel much of the island off the ocean beaches. The ocean bottom immediately offshore from the plant site consists primarily of sand and shell sediments. The unstable substrate limits the establishment of rooted macrophytes.

The Florida Current, which flows parallel to the continental shelf margin, begins to diverge from the coastline at West Palm Beach. At Hutchinson Island, the current is approximately 33 km offshore. Oceanic water associated with the western boundary of the current periodically meanders over the inner shelf, especially during summer months.

PLANT DESCRIPTION The St. Lucie Plant consists of two 850-MW nuclear-fueled electric generating units that use nearshore ocean waters for the plant's once-through condenser cooling

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water system. Water for the plant enters through three submerged intake structures located about 365 m offshore (Figure 2). Each of the intake structures is equipped with a velocity cap to minimize fish entrainment. Horizontal intake velocities are less than 30 cm/sec. From the intake structures, the water passes through submerged pipes (two 3.7 m and one 4.9 m in diameter) under the beach and dunes that lead to a 1,500-m long intake canal. This canal transports the water to the plant. After passing through the plant, the heated water is discharged into a 670-m long canal that leads to two buried discharge pipelines. These pass underneath the dunes and beach and along the ocean floor to the submerged discharges, the first of which is approximately 365 m offshore and 730 m north of the intake.

Heated water leaves the first discharge line from a Y-shaped nozzle (diffuser) at a design velocity of 396 cm/sec. This high-momentum jet entrains ambient water, result-ing in rapid heat dissipation. The ocean depth in the area of the first discharge is about 6 m. Heated water leaves the second discharge line through a series of 48 equally spaced high velocity jets along a 323-m manifold (multiport diffuser). This diffuser starts 168 m beyond the first discharge and terminates 856 m from shore. The ocean depth at discharge along this diffuser is from about 10 to 12 m. As with the first diffuser, the purpose of the second diffuser is to entrain ambient water and rapidly dissipate heat.

From the points of discharge at both diffusers, the warmer water rises to the surface and forms a surface plume of heated water. The plume then spreads out on the sur-face of the ocean under the influence of wind and currents and the heat dissipates to the atmosphere.

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TURTLES 1

The NRC's St. Lucie Unit 2 Appendix B Environmental Protection Plan issued April 1983 contains the following technical specifications:

4.2 Terrestrial A vatic Issues Issues on endangered or threatened sea turtles raised in the Unit 2 FES-OL [NRC, 1982] and in the Endangered Species Biological As-sessment (March 1982) [Bellmund et al., 1982] will be addressed by programs as follows:

4.2.1 Beach nesting surveys for all species of sea turtles willbe conducted on a yearly basis for the period of 1982 through 1986. These sur-veys will be conducted during the nesting season from ap-proximately mid-April through August.

The Hutchinson Island beach will be divided into 36 one-km-long survey areas. In addition, the nine 1.25-km-long survey areas used in previous studies (1971-1979) will be maintained for comparison purposes. Survey areas will be marked with numbered wooden pla-ques and/or existing landmarks.

The entire beach will be surveyed seven days a week. All new nests and false crawls will be counted and recorded in each area. After counting, all crawl tracks will be obliterated to avoid recounting.

Predation on nests by raccoons or other predators will be recorded as it occurs. Records will be kept of any seasonal changes in beach topography that may affect the suitability of the beach for nesting.

4.2.2 A program that employs light and/or sound to deter turtles from the intake structure will be conducted. The study will determine with laboratory and field experiments if sound and/or light will result in a reduction of total turtle entrapment rate.

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The study shall be implemented no later than after the final removal from the ocean of equipment and structures associated with con-struction of the third intake structure and the experiments shall ter-minate 18 months later. Four months after the conclusion of the experimental period, a report on the results of the study will be sub-mitted to NRC, EPA, National Marine Fisheries Service (NMFS), and the US Fish and Wildlife Service (USFWS) for their evaluation. If a statistically significant reduction in annual total turtle entrapment rate of 80 percent or greater can be demonstrated, using the developed technology and upon FPL receiving written concurrence by NRC, EPA, NMFS, and USFWS then permanent installation of the deterrent system shall be completed and functioning no later than 18 months after the agencies'oncurrence. The design of this study needs to take into account the significant annual variation in turtle entrapment observed in the past.

If an 80 percent reduction of turtle entrapment cannot be projected to all three intake structures, then an interagency task force com-posed of NRC, EPA, NMFS, USFWS, and FPL shall convene 18 months after completion of the third intake and determine if other courses of action to mitigate and/or reduce turtle entrapment are warranted (such as physical barrier, emergence of new technology or methods to deter turtles).

4.2.3 Alternative methods or procedures for the capture of sea turtles entrapped in the intake canal will be evaluated. If a method or pro-cedure is considered feasible and cost effective and may reduce capture mortality rates, it will be field tested in the intake canal.

4.2.5 Ca ture and Release Pro ram Sea turtle removal from the intake canal will be conducted on a con-tinuing basis. The turtles will be captured with large mesh nets, or other suitable nondestructive device(s), if deemed appropriate. A formalized daily inspection, from the shoreline, of the capture device(s) will be made by a qualified individual when the device(s) are deployed. The turtles will be identified to species, measured, weighed (if appropriate), tagged and released back into the ocean.

Records of wounds, fresh or old, and a subjective judgement on the condition of the turtle (e.g., barnacle coverage, underweight) will be maintained. Methods of obtaining additional biological/physiologi-cal data, such as blood analyses and parasite loads, from captured

sea turtles will be pursued. Dead sea turtles will be subjected to a gross necropsy, if found in fresh condition.

INTRODUCTION Hutchinson island, Florida, is an important rookery for the loggerhead turtle, Caret-

~tgaretta and also supports some nesting of the green turtle, ~Ch loni ~m~a and th 9 Rt ~ II,~Oh I ~i(d Id II t 1.,1959;9 9,11169;I! I-lagher et al., 1972; Worth and Smith, 1976; Williams-Walls et al., 1983). AIIthree species are protected by state and federal statutes. The federal government class Tiied the log-gerhead turtle as a threatened species. The leatherback turtle and the Florida nesting population of the green turtle are listed by the federal government as endangered species. Because of reductions in world populations of marine turtles resulting from coastal development and fishing pressure (NMFS, 1978), maintaining the vitality of the Hutchinson Island rookery is important.

9 It has been a prime concern of FPL that the construction and subsequent opera-tion of the St. Lucie Plant would not adversely affect the Hutchinson Island rookery.

Because of this concern, FPL has sponsored monitoring of marine turtle nesting ac-tivity on the island since 1971.

Daytime surveys to quantify nesting, as well as nighttime turtle tagging programs, were conducted in odd numbered years from 1971 through 1979. During daytime nest-ing surveys, nine 1.25-km-long survey areas were monitored five days per week (Figure 3). The St. Lucie Plant began operation in 1976; therefore, the first three survey years (1971, 1973 and 1975) were preoperational. Though the power plant was not operat-ing during 1975, St. Lucie Plant Unit No. 1 ocean intake and discharge structures were

installed during that year. Installation of these structures included nighttime construo.

tion activities conducted offshore from and perpendicular to the beach. Construction had been completed and the plant was in full operation during the 1977 and 1979 sur-veys.

A modified daytime nesting survey was conducted in 1980 during the preliminary construction of the ocean discharge structure for St. Lucie Plant Unit 2. During this study, four of the previously established 1.25-km-long survey areas were monitored.

Additionally, eggs from turtle nests potentially endangered by construction activities were relocated.

Every year from 1981 through 1992, 36 1-km-long survey areas comprising the entire island were monitored seven days a week during the nesting season (Figure 3).

The St. Lucie Plant Unit 2 discharge structure was installed during the 1981 nesting season. Offshore and beach construction of the Unit 2 intake structure proceeded throughout the 1982 nesting season and was completed near the end of the 1983 season. Construction activities associated with installation of both structures were similar to those conducted when Unit 1 intake and discharge structures were installed.

Eggs from turtle nests potentially endangered by construction activities were relocated during all three years.

During 1991, another major offshore construction project was undertaken to replace damaged velocity caps on the three intake structures. A large elevated plat-form, from which repair activities were conducted, was erected around the three struc-tures. Construction occurred throughout the nesting season. However, in contrast to

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previous offshore projects, work was restricted almost entirely to daylight hours, nighttime lighting of the work area was minimal, and no equipment or materials were used on the beach. A sea turtle protection plan implemented in support of the project included caging of nests along a 1,500 m section of beach west of the platform and release of hatchlings to unaffected areas to the north and south. This plan was intended to mitigate any negative effects potentially resulting from required safety and naviga-tional lighting on and near the platform.

Requirement 4.2.1 of the NRC's St. Lucie Unit 2 Appendix 8 Environmental Protec-tion Plan was completed with submission of the 1986 nesting survey data (ABI, 1987).

The nesting survey was continued voluntarily through 1992 with agreement from federal and state agencies. Results are presented in this report and discussed in relation to previous findings.

In addition to monitoring sea turtle nesting activities and relocating nests away from plant construction areas, removal of turtles from the intake canal has been an in-tegral part of the St. Lucie Plant environmental monitoring program. Turtles entering the ocean intake structures are entrained with cooling water and rapidly transported through the intake pipes into an enclosed canal system where they must be manually captured and returned to the ocean. Since the plant became operational in 1976, turtles entrapped in the intake canal have been systematically captured, measured, weighed, tagged and released.

Previous publications and technical reports have presented findings of the nest-ing surveys, nest relocation activities and canal capture program (Gallagher et al., 1972;

Worth and Smith, 1976; ABI, 1978, 1980a, 1981a, 1982, 1983, 1984b, 1985b, 1986, 1987, 1988, 1989, 1990, 1991; Williams-Walls et al., 1983; Proffitt et al., 1986; Ernest et al., 1988, 1989; Martin et al., 1989a, 1989b; Wibbels et al., 1991). Results of studies to assess the effects of thermal discharges on hatchling swimming speed have also been reported (ABI, 1978; O'ara, 1980). The purpose of this report is to 1) present 1992 sea turtle nesting survey data and summarize observed spatial and temporal nesting patterns since 1971, 2) document and summarize predation on turtle nests since 1971, and 3) present 1992 canal capture data and summarize comparable data collected since 1976.

MATERIALSAND METHODS Nestin Surve Methodologies used during previous turtle nesting surveys on Hutchinson Island were described by Gallagher et al. (1972), Worth and Smith (1976) and ABI (1978, 1981a, 1982, 1987, 1988, 1989). Methods used during the 1992 survey were designed to allow comparisons with these previous studies.

On 13 April 1992, a preliminary nest survey was conducted along Hutchinson Is-land from the Ft. Pierce Inlet south to the St. Lucie Inlet. From 15 April through 4 Sep-tember, nest surveys were conducted on a daily basis. To confirm that nesting had ceased, additional surveys were conducted on 8, 9, 10, 11 and 14 September.

Biologists used small off-road motorcycles to survey the island each morning. New nests, non-nesting emergences (false crawls), and nests destroyed by predators were recorded for each of the 36 1-km-Iong survey areas comprising the entire island (Figure 10

3). The nine 1.25-km-long survey areas established by Gallagher et al. (1972) also were monitored so comparisons could be made with previous studies.

During the daily nest monitoring, any major changes in topography that may have affected the beach's suitability for nesting were recorded. In addition, each of the 36 1-km-long survey areas has been systematically analyzed and categorized based on beach slope (steep, moderate, etc.), width from high tide line to the dune, presence of benches (areas of abrupt vertical relief) and miscellaneous characteristics (packed sand, scattered rock, vegetation on the beach, exposed roots on the primary dune, etc.).

In a cooperative effort, data from stranded turtles found during beach surveys were routinely provided to the National Marine Fisheries Service (NMFS) through the Sea Turtle Stranding and Salvage Network.

Int ke Canal Monitorin Most turtles entrapped in the St. Lucie Plant intake canal were removed by means of large-mesh tangle nets fished between the intake headwalls and a barrier net located at the Highway A1A bridge (Figure 2). Nets used during 1992 were from 30 to 40 m in length, 3 to 4 m deep and composed of 40 cm stretch mesh nylon twine. Large floats were attached to the surface, and unweighted lines used along the bottom. Turtles en-tangled in the nets generally remained at the water's surface until removed.

Since its inception in 1976, ABI's canal capture program has been under continual review and refinement in an attempt to minimize both entrapment times and in-11

juries/mortalities to entrapped sea turtles. Prior to April 1990, turtle nets were usually deployed on Monday mornings and retrieved on Friday afternoons. During periods of deployment, the nets were inspected for captures by ABI personnel at least twice each day (mornings and afternoons). Additionally, St. Lucie Plant personnel checked the nets periodically, and ABI was notified immediately if a capture was observed. ABI's sea turtle specialists were on call 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day to retrieve captured turtles from the plant.

Beginning April 1990, after consultation with NMFS, net deployment was scaled back to daylight hours only. Concurrently, surveillance of the intake canal was in-creased and ABI personnel remained on site for the duration of each day's netting ac-tivities. This measure decreased response time for removal of entangled turtles from nets and provided an opportunity to improve daily assessments of turtle levels within the canal. Records of daily canal observations wer'e compared with capture data to as-sess capture efficiencies.

The A1A barrier net is used to confine turtles to the easternmost section of the in-take canal, where capture techniques have been most effective. This net is constructed of large diameter polypropylene rope and has a mesh size of 20.3 cm x 20.3 cm. A cable and series of large floats are used to keep the top of the net above the water' surface, and the bottom is anchored by a series of heavy blocks. The net is inclined at a slope of 3:1, with the bottom positioned upstream of the surface cable. This reduces bowing in the center and minimizes the risk of a weak or injured turtle being pinned un-derwater by strong currents.

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tn the past, the integrity of the barrier net was occasionally compromised, and turtles were able to move west of A1A. These turtles were further constrained downstream by an underwater intrusion detection system (UIDS) consisting, in part, of a large barrier positioned perpendicular to the north-south arm of the canal (Figure 2). The UIDS security barrier also consists of 20.3 cm x 20.3 cm mesh.

Prior to completion of the UIDS in December 1986, turtles uncontained by the A1A barrier net were usually removed from the canal at the intake wells of Units 1 and 2 (Figure 2). Thel'e they were retrieved by means of large mechanical rakes or specially designed nets. Following construction of the UIDS barrier, all but the smallest in-dividuals were unable to reach the intake wells. Thus, as required, tangle nets were also deployed west of A1A. Improvements made to the A1A barrier net during 1990 have effectively confined all turtles larger than 32.5 cm to the eastern end of the canal.

Formal daily inspections of the intake canal were made to determine the numbers, locations and species of turtles present. Surface observations were augmented with periodic underwater inspections using SCUBA, particularly in and around the A1A bar-rier net. Because of the reduction in total netting hours since April 1990, increased ef-fort has been directed toward hand capture of turtles. This effort, accomplished by diving and use of dip nets, has proved very effective during periods of good water I

clarity.

Regardless of capture method, all turtles removed from the canal were identified to species, measured, weighed, tagged, and examined for overall condition (wounds, abnormalities, parasites, etc.). Healthy turtles were released into the ocean the same 13

day of capture. Sick or injured turtles were treated and occasionally held for observa-tion prior to release. When treatment was warranted, injections of antibiotics and vitamins were administered by permitted veterinarians. Resuscitation techniques were used if a turtle was found that appeared to have died recently. Beginning in 1982,

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necropsies were conducted on dead turtles found in fresh condition; one necropsy was performed during 1992.

Since 1982, blood samples have been collected and analyzed to determine the sex of immature turtles. Blood was removed from the paired dorsal cervical sinuses of subject turtles using the technique described by Owens and Ruiz (1980). The samples were maintained on ice and later centrifuged for 15 minutes to separate cells and serum.

Sex determinations were subsequently made by researchers at Texas A & M Univer-sity using radioimmunoassay for serum testosterone (Owens et al., 1978).

Florida Power & Light Company and Applied Biology, Inc. continued to assist other sea turtle researchers in 1992. Since the program began, data, specimens and/or assistance have been given to the Florida Department of Natural Resources, National Marine Fisheries Service, US Fish and Wildlife Service, US Army Corps of Engineers, Smithsonian Institution, South Carolina Wildlife and Marine Resources Division, Center for Sea Turtle Research (University of Florida), Florida Atlantic University, University of Central Florida, Texas A & M University, University of Rhode Island, University of South Carolina, University of Illinois, University of Georgia, Virginia Institute of Marine Science and the Western Atlantic Turtle Symposium.

Studies t Evaluat and or Miti te Int k Entr m nt A program that assessed the feasibility of using light and/or sound to deter turtles from entering the St. Lucie Plant intake structures was conducted in 1982 and 1983 4

and completed in January 1984. As required, test results and evaluations were written up and a presentation was made to the NRC, National Marine Fisheries Service and the Florida Department of Natural Resources on 11 April 1984. Requirement 4.2.2 of the NRC's St. Lucie Unit 2 Appendix B Environmental Protection Plan is considered completed with submission of deterrent study findings.

RESULTS AND DISCUSSION Nestin Surve S atial Distribution of Lo erhead Turtle Nests Since 1981, 36 1-km-long segments comprising the island's coastline have been surveyed. The distribution of nests among these 36 survey areas has shown an in-crease in nesting from north to south along the northern half of the island (Figure 4; ABI, 1987, 1992). Along the southern half of the island there has either been no gradient or a gradient of decreasing nesting from north to south.

Though beach dynamics may sometimes affect the selection of nesting sites by loggerhead turtles (Worth and Smith, 1976; Williams-Walls et al., 1983), no consistent relationship was apparent when field observations of beach widths were compared to the spatial distribution of nests along the island (ABI, 1987). Therefore other factors must also contribute to the selection process. Offshore bottom contours, spatial dis-

tribution of nearshore reefs, type and extent of dune vegetation, and degree of human activity on the beach at night have been identified as some of the factors affecting nest-ing (Caldwell, 1962; Hendrickson and Balasingam, 1966; Bustard, 1968; Bustard and Greenham, 1968; Hughes, 1974; Davis and Whiting, 1977; Mortimer, 1982). Relation-ships between spatial nesting patterns and specific environmental conditions are often difficultto establish because of the interrelationship of the factors involved.

4 Not all ventures onto the beach by a female turtle culminate in successful nests.

These "false crawls" (non-nesting emergences) may occur for many reasons and are commonly encountered at other rookeries (Baldwin and Lofton, 1959; Schulz, 1975; Davis and Whiting, 1977; Talbert et al., 1980; Raymond, 1984). Davis and Whiting (1977) suggested that relatively high percentages of false crawls may reflect disturban-ces or unsatisfactory nesting beach characteristics. Therefore, certain factors may af-fect a turtle's preference to emerge on a beach, while other factors may affect a turtle' tendency to nest after it has emerged. An index which relates the number of nests to the number of false crawls in an area is useful in estimating the post-emergence suitability of a beach for nesting. In the present study this index is termed "nesting suc-cess" and is defined as the percentage of total emergences that result in nests.

Historically, the pattern of loggerhead emergences on the island has generally paralleled the distribution of nests (ABI, 1987, 1992), and this same trend was apparent in 1992 (Figure 5). In contrast, nesting success by loggerheads along the island has typically lacked gradients (Figure 6; ABI, 1987, 1992). Thus, the relatively high num-bers of loggerhead nests observed in certain areas are usually a result of more turtles

coming ashore in those areas rather than of more preferable nesting conditions being encountered by the turtles after they emerged.

Any of the factors previously Identified (!.e., offshore bottom contours, distribution of reefs, type and extent of dune vegetation, and human activity on the beach at night) may affect loggerhead turtle emergence patterns and several have been reported to affect emergence patterns on Hutchinson Island (ABI, 1988, 1989; Martin et al., 1989).

Undoubtedly a combination of factors account for the overall distribution of emergen-ces and therefore the overall nesting pattern on the island.

Nesting surveys on Hutchinson Island were initiated in response to concerns that the operation of the St. Lucie Plant might negatively impact the local sea turtle rookery.

Previous analysis, using log-likelihood tests of independence (G-test; Sokal and Rohlf, 1981) demonstrated that the construction of the plant's offshore intake and discharge structures significantly reduced nesting at the plant site during construction years 1975, 1981, 1982 and 1983 (Proffitt et al., 1986; ABI, 1987). However, nesting at the plant consistently returned to levels similar to or greater than those at a control site in years following construction (Figure 7). During 1991 when offshore construction was restricted almost entirely to daylight hours, nests were more abundant at the plant site than at the control site. Data collected through 1992 have shown that power plant operation exclusive of nighttime intake/discharge construction has had no apparent ef-feet on nesting.

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Lon -T rm Tr nd in L rh ad T rtl Ne tin Various methods were used during surveys prior to 1981 to estimate the total number of loggerhead nests on Hutchinson Island based on the number of nests found in the nine 1.25-km-long survey areas (Gallagher et al., 1972; Worth and Smith, 1976; ABI, 1980a). Each of these methods were subsequently found to consistently overes-timate island totals (ABI, 1987). Since whole-island sur veys began in 1981, it has been possible to determine the actual proportion of total nests deposited in the nine areas.

This has then allowed extrapolation from the nine survey areas to the entire island for years prior to 1981.

From 1981 through 1992 the total number of nests in the nine areas varied from 32.5 to 35.6 percent of the total number of nests on the island (Table 1). This is slight-ly higher than the 31.3 percent which would be expected based strictly on the propor-tion of linear coastline comprised by the nine areas. Using the twelve-year mean of 33.91 percent, estimates of the total number of nests on Hutchinson Island can be cal-culated by multiplying the number of nests in the nine areas by 2.949. This technique, when applied to the nine survey areas during the twelve years in which the entire is-land was surveyed, produced whole-island estimates within 5.0 percent of the actual number of nests counted. Because the proportion of nests recorded in the nine sur-vey areas remained relatively constant over the last twelve years, this extrapolation pro-cedure should provide a fairly accurate estimate of total loggerhead nesting for years prior to 1981.

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It is clear that loggerhead nesting activity on Hutchinson Island fluctuates con-siderably from year to year (Table 1; Figure 8). Annual variations in nest densities also are common at other rookeries (Hughes, 1976; Davis and Whiting, 1977; Ehrhart, 1980) and may result from non-annual reproductive behavior (Frazer, 1989). Nonetheless, data collected through 1992 suggest an overall increase in nesting on Hutchinson Is-land since surveys began in 1971. Total nesting activity was greatest during 1991 when 6,812 loggerhead nests were recorded. No relationships between total nesting activity and power plant operation or intake/discharge construction were indicated by year-to-year variations in total nesting on Hutchinson Island.

Seasonal Pattern of Lo erhead Turtle Nestin The loggerhead turtle nesting season usually begins between mid-April and early May, attains a maximum during June or July, and ends by late August or early Sep-tember (ABI, 1987). Nesting activity during 1992 followed this same pattern (Figure 9).

Cool water intrusions frequently occur over the continental shelf of southeast Florida during the summer (Taylor and Stewart, 1958; Smith, 1982). Worth and Smith (1976), Williams-Walls et al. (1983) and ABI (1992) suggested that these intrusions may have been responsible for the temporary declines in loggerhead turtle nesting activity previously observed on Mutchinson Island. Similarly, an intrusion of cool water from late June through early July 1992 may have contributed to the substantial decrease in nesting during that period (Figure 9).

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Though natural fluctuations in temperature have been shown to affect temporal nesting patterns on Hutchinson Island, there has been no indication that power plant operation has affected these temporal patterns (ABI, 1988).

Predati n nLo rh dT rtl N t Since nest surveys began in 1971, raccoon predation has been a major cause of turtle nest destruction on Hutchinson Island. Researchers at other locations have reported raccoon predation levels as high as 70 to nearly 100 percent (Davis and Whit-ing, 1977; Ehrhart, 1979; Hopkins et al., 1979; Talbert et al., 1980). Raccoon predation of loggerhead turtle nests on Hutchinson Island has not approached this level during any study year, though levels for individual 1.25-km-long areas have been as high as 80 percent. Overall predation rates for survey years 1971 through 1977 were between 21 and 44 percent, with a high of 44 percent recorded in 1973. A pronounced decrease in raccoon predation occurred after 1977, and overall predation rates for the nine areas have not exceeded 10 percent since 1979. A decline in predation rates on Hutchinson Island has been variously attributed to trapping programs, construction activities, habitat loss and disease (Williams-Walls et al., 1983; ABI, 1987).

During 1992, four percent (255) of the loggerhead nests (n =6,459) on the island were depredated by raccoons. As in previous years (ABI, 1992), predation of turtle nests was primarily restricted to the most undeveloped portion of the island (i.e., Areas E through S; Figure 10).

Ghost crabs have been reported by numerous researchers as important predators of sea turtle nests (Baldwin and Lofton, 1959; Schulz, 1975; Diamond, 1976; Fowler, 20

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1979; Hopkins et al., 1979; Stancyk, 1982). Though turtle nests on Hutchinson Island probably have been depredated by ghost crabs since nesting surveys began in 1971, this source of nest destruction did not become apparent until 1983. Quantification of ghost crab predation was initiated the same year.

Overall predation rates by ghost crabs have varied from 0.1 to 2.1 percent from 1983 - 1991 (ABI, 1992). During 1992, 0.1 percent (7) of the loggerhead nests (n =6,459) on the island were depredated by ghost crabs (Figure 10). Nests destroyed by a combination of raccoon and ghost crab predation have been included as raccoon predations in previous discussions. When'these combination predations are included as crab predations, the overall predation rates by ghost crabs range from 0.4 to 3.2 percent. During 1992, 0.9 percent (57 nests) were destroyed by either ghost crabs or a combination of ghost crabs and raccoons.

Green and Leatherback Turtle Nestin Green and leatherback turtles also nest on Hutchinson Island, but in fewer num-bers than loggerhead turtles. Prior to 1981, both sur vey (nine 1.25-km-long sections) and inter-survey areas were monitored for the presence of green and leatherback nests. Thirty-one kilometers of beach from Area 1 south to the St. Lucie Inlet were in-cluded in that effort. During whole-island surveys from 1981 through 1992, 'only seven of 256 leatherback nests and only twelve of 794 green nests were recorded on the five kilometers of beach north of Area 1. Therefore, previous counts of green and leather-back nests within the 31 kilometers surveyed probably were not appreciably different from total densities for the entire island. Based on this assumption, green and leather-21

back nest densities may be compared among all survey years, except 1980, when less than 15 kilometers of beach were surveyed.

Prior to 1992, the number of nests observed on the island ranged from 5 to 132 for green turtles and from 1 to 44 for leatherbacks (Figure 11). During the 1992 survey, 146 green turtle and 30 leatherback turtle nests were recorded on Hutchinson Island.

Temporal nesting patterns for these species differ from the pattern for loggerhead turtles. Green turtles typically nest on Hutchinson Island from mid-June through the first or second week of September. During 1992, green turtles nested from 29 May through 9 September. Leatherback turtles usually nest on the island from mid-April through early to mid-July. During 1992 this species nested from 26 March through 8 June.

Considerable fluctuations in green turtle nesting on the island have occurred among survey years (Figure 11) This is not unusual since there are drastic year-to-

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year fluctuations in the numbers of green turtles nesting at other breeding grounds (Carr et al., 1982). Despite these fluctuations, data collected through 1992 suggest an overall increase in nesting since 1971 and may reflect an increase in the number of nesting females in the Hutchinson Island area. During 1992, green turtles nested most frequently along the southern half of the island. This is consistent with results of pre-vious surveys.

Leatherback turtle nest densities have remained low on Hutchinson Island; however, increased nesting during recent years (Figure 11) may reflect an overall in-22

crease in the number of nesting females in the Hutchinson Island area. During 1992, leatherback turtles primarily nested on the southern half of the island.

Intake nal M nitorin Entrainment of sea turtles at the St. Lucie Plant has been attributed to the presumed physical attractiveness of the offshore structures housing the intake pipes rather than to plant operating characteristics (ABI, 1980b and 1986). The velocity caps supported above the openings to each intake pipe eliminate vertical water entrainment and substantially reduce current velocities near the structures by spreading horizontal draw over an arc of 360 . Even when both units are operating at full capacity, turtles must actively swim into the mouth of one of the intake pipes before they encounter cur-rent velocities sufficiently strong to effect entrainment. Consequently, a turtle's entrap-ment relates primarily to the probability that it will detect and subsequently enter one of the intake structures.

Relative Abund n e nd Tem oral Di tri uti n During 1992, 187 sea turtles were captured in the intake canal of the St. Lucie Plant: 123 loggerheads, 61 green turtles, 1 leatherback and 2 hawksbills (Table 2). All but one of the five species of sea turtles inhabiting coastal waters of the southeastern United States were represented. Since intake canal monitoring began in May 1976, 2,083 loggerhead (including 121 recaptures), 379 green (including 3 recaptures), 10 leatherback, 11 hawksbill and 18 Kemp's ridley captures have taken place at the St.

Lucie Plant. Annual catches for all species combined ranged from a low of 33 in 1976 (partial year of plant operation and monitoring) to 220 in both 1984 and 1986.

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One of the potential uses of annual abundance data is to provide a gauge of'hange in the relative number of turtles occurring in the vicinity of the St. Lucie Plant.

Assuming that the probability of entrainment (an individual's chance of detecting and entering one of the pipes) does not vary appreciably over time and that, within a species, a constant proportion of turtles are equally attracted to the structures, cap-ture rates should vary in proportion to the size of the populations being sampled.

Since 1977, the first full year of plant operation, the number of loggerheads cap-tured each year has ranged from 62 in 1981 to 195 in 1986 (Figure 12). Annual green turtle captures over the same period ranged from 3 in 1979 to 69 in 1984. Numbers for both species have exhibited considerable year-to-year fluctuations with no persistent trends evident. However, this analysis may be confounded by changes in the physical characteristics of the intake structures that have occurred since the plant began operat-Ing.

Two offshore intake structures were in place prior to Unit 1 start-up in 1976. The third and largest structure was not installed until 1982-1983. Even though all three structures are in relatively close proximity, the addition of another pipe may have in-creased the probability of a turtle's entrainment. Because this change cannot be quan-tified, data collected prior to 1982 may not be comparable with data collected after 1983. Additionally, in 1989 holes developed in the center of two of the three velocity caps. This damage, which was repaired during 1991-1992, added a strong vertical component to water entrainment. The degree to which modified entrainment charac-teristics and subsequent repair operations affected sea turtle entrapment is also un-known. With these considerations in mind, neither a long-term increase nor decrease 24

I in the number of sea turtles inhabiting the nearshore environment adjacent to the St.

Lucie Plant can be inferred from the canal capture data.

During 1992, the monthly catch of loggerheads ranged from 1 (May) to 19 (January), with a monthly mean of 10.3 (+5.2; Table 3). The numbers of captures during March, May and June were considerably below average, while captures, in November and December were considerably higher than average. Over the entire monitoring period, monthly catches have ranged from 0 to 39, with the greatest num-ber of captures occurring during January 1983.

When data from all full years of monitoring (1977-1992) are combined, the highest mean number of loggerhead captures (15.7) occurred in January; fewest average cap-tures were recorded in November (5.8; Table 3). However, as evidenced by minimum and maximum values, monthly catches have shown considerable annual variability.

Months having relatively low catches one year often have had relatively high catches in another.

Green turtles have been caught during every month of the year, with average monthly catches for all years combined ranging from 0.5 in July to 6.4 in January (Table 4). Seasonal abundance patterns of green turtles have been much more pronounced than for loggerheads, with 42 percent of ail captures occurring between January and February. During 1992, the largest number of green turtles (18) were captured in Oc-tober. The number of green turtles captured between October and December was the highest on record. The most ever caught in one month was 37 in January 1984.

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, Catches of leatherbacks, hawksbills and Kemp's ridleys have been infrequent and scattered throughout the 17 year study period (Table 2). Each species has shown rather pronounced seasonal occurrences; all'but 2 of the 10 leatherbacks were col-lected between January and May, 9 of the 11 hawksbills were collected between June and October, and all but 2 of the 18 Kemp's ridleys were caught between November and April.

Size-Cla s Distributions Although several straight-line and curved measurements were recorded for turtles removed from the intake canal, only one straight-line measurement has been used in analyses presented here. Straight-line carapace length (SLCL) was measured from the precentral scute to the notch between the postcentral scutes (minimum carapace length of Pritchard et al., 1983). To date, loggerheads removed from the intake canal have ranged in length (SLCL) from 40.2 to 112.0 cm (x = 66.4 + 13.6 cm) and in weight from 10.7 kg to 169.6 kg (x = 48.2 + 30.6 kg).

A carapace length of 70 cm approximates the smallest size of nesting loggerhead females observed along the Atlantic east coast (Hirth, 1980). However, adults can only be reliably sexed on external morphological characteristics (i.e., relative tail length) after attaining a somewhat. larger size. Recent data suggest that some males may not ma-ture, and thus might not be distinguishable from females, until they are about 85.0 cm long. Based on these divisions, data were segregatedinto three groups: juveniles (< 70 cm), adults (>85 cm) and transitional (71-85 cm). The latter group probably includes both mature and immature individuals.

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Of the 2,050 loggerhead captures between 1977 and 1992 for which length data were recorded, 69.6 percent were juveniles, the majority of these measuring between 50 and 70 cm SLCL (Figure 13; Table 5). The remaining individuals were nearly equal-ly divided between adults and animals in the transitional size class. Similar size-frequen-cy distributions, indicating a preponderance of juveniles, have been reported for loggerheads inhabiting the Mosquito/Indian River Lagoon (Mendonca and Ehrhart, 1982), the Canaveral ship channel (Henwood, 1987), and Georgia and South Carolina (Hillestad et al., 1982). These data suggest that coastal waters of the southeastern United States constitute an important developmental habitat for loggerhead sea turtles.

Seasonal patterns of abundance for various size classes indicated that juvenile loggerheads were slightly more abundant during the winter than at other times of the year (Table 5) About 47 percent of the Juveniles were captured between January and

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April. Abundances decreased in spring and remained relatively constant during the summer and early fall before decreasing again to lowest levels in November and December. The seasonal distribution of adult loggerheads was much more pronounced, 75 percent of all captures occurring between May and August. This rep-resents the major portion of the nesting season on Hutchinson Island.

Green turtles removed from the intake canal over the entire study period ranged in size from 20.0 to 108.0 cm SLCL (x = 36.4 + 14.3 cm) and 0.9 kg to 177.8 kg (x =

9.9 + 20.0 kg). Nearly all (97 percent) were juveniles, with over 75 percent 40 cm or less in length (Figure 14). Although these immature turtles exhibited distinct winter pul-ses, some small individuals were captured throughout the year (Table 4). To date, only 27

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10 adult green turtles (SLCL >83 cm; Witherington and Ehrhart, 1989) have been removed from the canal; all were captured during or shortly after the nesting season.

The 11 hawksbills removed from the canal ranged in size from 34.0 to 83.4 cm SLCL(x = 49.3 + 15.7 cm) and in weight from 6.4 to 86.6 kg (x = 23.1 + 25.2 kg).

All but two were juveniles (SLCL (63 cm; Witzell, 1983). Similarly, all but one of the 18 Kemp's ridleys captured at the St. Lucie Plant were juveniles (SLCL (60.0 cm; Mirth, 1980). Carapace lengths for the ridleys ranged from 27.0 to 62.0 cm SLCL (x = 37.0

+ 10.1 cm) and weights from 3.1 to 31.8 kg (x = 8.6+ 8.2kg). The10 leatherbacks removed from the canal ranged in length from 112.5 to 150.0 cm, and at least 8 were adults (SLCL >121 cm; Mirth, 1980). The largest leatherback for which an accurate weight was obtained, a female with a curved carapace length of 158.5 cm, weighed 334.8 kg.

Sex Ratios Since intake canal monitoring began in 1976, 299 adult loggerheads (SLCL > 85.0 cm) have been sexed. Females predominated males by a ratio of 5,2:1.0, which sig-nificantly departs from a 1:1 ratio (X, P (0.05). Consequently, temporal patterns in the number of adult loggerhead captures were heavily influenced by the numbers of females present. When sexes were separated, it was evident that males were relative-ly evenly distributed among months, whereas 88 percent of the females were taken during the nesting season (May through September; Figure 15).

The number of adult female loggerheads captured at the St. Lucie Plant has in-creased noticeably since 1983. From 1977 (first full year of plant operation) through 28

I 1983, an average of 4.6 adult females (+ 3.2; range = 1-10) were entrapped each year, whereas since then, an average of 24.4 females per year were captured (+ 6.9; range = 35) This increase corresponds to a general rise in loggerhead nesting ac-

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tivity near the plant (Figure 16). Increased nearshore movement associated with nest-ing increases the probability of a turtle detecting one of the intake structures and hence the probability of entrainment. The decline in adult loggerhead captures during 1991 and 1992 may be r'elated to velocity cap repairs. Construction activities and/or the lack of biological fouling on the new caps may have reduced the attractiveness of the in-take structures as a resting or staging area between successive nesting forays.

Reduced association with the structures would decrease the likelihood of entrainment.

Since September 1982, 435 individual juvenile and sub-adult loggerhead turtles (SLCL (70.0 cm) captured in the canal were sexed by Texas A & M University re-searchers using a bioimmunoassay technique for blood serum testosterone. Females significantly (X; P (0.05) outnumbered males by a ratio of 2.2:1.0. This female bias is consistent with findings of Wibbels et al. (1987) for other coastal loggerhead popula-tions in the southeastern United States.

Of the 10 adult green turtles captured since monitoring began, six were males and four were females. Seventeen immature green turtles have been sexed through blood work: 11 females and 3 males. Of the six adult leatherback turtles for which sex was recorded, three were females and three were males. The two adult hawksbills and one Kemp's ridley were all females. No sex information exists for juveniles of any of these species.

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Ca tur Effi i nci Netting methodologies have been under continual review and refinement as net materials, configurations and placement have been varied in an effort to minimize sea turtle entrapment times. Additionally, alternative capture techniques have been evaluated and potential deterrent systems tested in the laboratory. Current capture procedures have proven to provide a safe, efficient and cost-effective program for removing entrapped turtles from the intake canal.

Formal daily inspections of the intake canal are conducted every day that capture nets are deployed (usually five days each week), and the number, location, and rela-tive size of entrapped turtles are recorded on field observation forms. During 1992, about 65 percent of the turtles entering the canal were caught within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of first sighting. Because of differences in mean size, loggerheads typically resided in the canal for shorter periods than the smaller green turtles.

Since April 1990 when the current daytime netting program was implemented, 90 percent of all loggerheads have been captured within one week of first sighting, with a mean entrapment period of only 2.9 (+ 4.5) days (Figure 17). Over that same period, green turtles, which are less easily entangledin the large mesh nets, had a mean entrap-ment time of 5.3 (+ 9.8) days. Ninety percent of all green turtles were captured within two weeks of first sighting. Better utilization of currents and eddies, adjustments to tethering lines, multi-net deployments and increased efforts to hand capture turtles have contributed to reduced entrapment times during recent years.

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Entrapment times may be extended for turtles swimming past the A1A barrier net (ABI, 1987). Prior to barrier net repairs in 1990, the top of the net was occasionally sub-merged or the anchor cable pulled free from the bottom, allowing turtles that would otherwise be restrained by the net to pass. Because capture efforts west of the A1A bridge were generally less effective than those near the intake headwalls, most turtles breaching the barrier net were not caught until they entered the intake wells of Units 1 and 2. Prior to installation of the UIDS barrier in 1986, about 15 percent of ail turtles entrapped in the canal were removed from the intake wells. Because of their relatively small sizes, a much larger proportion of greens (51.6 percent) reached the plant than loggerheads (10.1 percent). Since 1986, the percentage of greens caught at the intake wells has decreased to 26.3 percent, while ail loggerheads have been prevented from reaching the plant. During 1992, only 7 of the 61 green turtle captures (11.5 percent) occurred at the intake wells.

During 1992, 96 percent of all turtles entrapped in the canal were captured east of the A1A bridge, 137 by netting and 43 by hand. The effective confinement of turtles east of A1A has been a major contributor to the high capture efficiency achieved during recent years.

ReIative Condition Turtles captured alive in the intake canal of the St. Lucie Plant were assigned a relative condition based on weight, activity, parasite infestation, barnacle coverage, wounds, injuries and any other abnormalities which might have affected overall vitality.

During 1992, 90.2 percent (111) of all loggerheads found in the canal were alive and 31

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in good to excellent condition. Only 8.1 percent (10) of loggerhead captures involved:

individuals in fair or poor condition; two loggerheads were dead when removed from the canal; Of the 61 green turtles removed from the intake canal during 1992, 57 (93.4 percent) were in good to excellent condition, 2 (3.3 percent) were in fair condition, and 2 (3.3 percent) were dead.

Over the entire monitoring period, about 77 and 80 percent, respectively, of all loggerhead and green captures have involved turtles in good to excellent condition (Table 6). Captures of individuals in fair to poor condition have occurred about 15 per-cent of the time for loggerheads and 12 percent of the time for greens. All of the hawksbills and leatherbacks have been removed, from the canal in good to excellent condition, while half of the Kemp's ridleys have fallen into these categories.

Relative condition ratings can be influenced by a number of factors, some related and others unrelated to entrainment and/or entrapment in the intake canal. Ratings of good to excellent indicate that turtles have not been negatively impacted by their entrap-ment in the canal, at least as evidenced by physical appearance. Although ratings of fair or poor imply reduced vitality, the extent to which entrainment/entrapment is responsible is often indeterminable. In some instances, conditions responsible for lower ratings, such as injuries, obviously were sustained prior to entrainment.

During 1992, only 3 of the 123 loggerhead captures (2.4 percent) involved in-dividuals with noticeable injuries, such as missing appendages, broken or missing pieces of carapace and deep lacerations. Most of these were old, well-healed wounds, 32

and none were serious enough to require medical attention. None of the green turtles captured during 1992 had major injuries.

The majority of loggerheads rated as fair or poor during 1992 did not suffer from physical disabilities but rather appeared lethargic. Most were underweight and heavi-ly infested with barnacles and leeches. This condition, referred to as "diseased turtle syndrome" (Ehrhart, 1987) has been reported from several other locales and is unre-lated to a turtle's entrapment in the canal.

~Mortaliti a Sea turtle mortalities have been closely monitored throughout the life of the canal capture program in an attempt to assign probable causes and take appropriate remedial action to minimize future occurrences. Previous analyses of capture data iden-tified drowning in nets (A1A barrier net, UIDS barrier, and tangle nets), drowning in the intake pipes during periods of reduced intake flow, injuries sustained from dredging operations and injuries sustained from the mechanical rakes used in the intake wells as probable mortality factors (ABI, 1987). Although difficultto quantify, the entrapment and subsequent demise of injured or sick turtles has probably accounted for a portion of observed mortalities.

Over the entire 17 year monitoring period, 130 (6.2 percent) of the 2,083 logger-heads and 23 (6.1 percent) of the 379 green turtles entrapped in the canal were found dead (Table 6). Mortalities spanned the range of size classes for loggerheads (SLCL

= 47.5-103 cm), while all green turtle mortalities involved juveniles less than 42 cm in length. The four Kemp's ridley mortalities documented at the plant during 1987 and 33

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1988 were the only deaths for this species to date; no leatherback or hawksbill mor-talities have occurred at the St. Lucie Plant.

Modifications to capture procedures, improvements to the A1A barrier net and I,

4 virtual elimination of low flow conditions within the canal have resulted in a substantial reduction in sea turtle mortalities over the life of the canal capture program. Mortality rate, expressed as the percentage of total captures involving dead animals, declined from 9.2 percent during the period 1976-1983 to 4.6 percent since 1983 (Table 2).

During 1992, four mortalities (2.1 percent of all captures), two loggerheads and two green turtles, were documented.

Both dead loggerheads removed from the canal in 1992 were found east of the A1A barrier net. No apparent physical injuries were noted, and it is believed that these individuals may have been in poor health prior to their entrapment. The two green turtle mortalities occurred at the intake wells. Injuries to one suggested that it may have been impacted by the mechanical rakes used to remove debris from the wells. However, a necropsy failed to provide a definitive cause of death. The other green turtle was too decomposed to necropsy.

Reca ture Incidents Since the St. Lucie Plant capture program began, most turtles removed from the intake canal have been tagged and released into the ocean at various locations along Hutchinson Island. Consequently, individual turtles can be identified as long as they retain their tags. Over the 17 year history of turtle entrapment at the St. Lucie Plant, 73 individuals (70 loggerheads and 3 green turtles) have been removed from the canal

I more than once. Several other turtles with tag scars have also been recovered, indicat-ing that the actual number of recaptures may be higher.

Of the 70 individual loggerheads known to have been caught more than once, 46 were caught twice and 4 were caught three times. The remainder were captured on four or more separate occasions, with one individual being caught nine times. Release site did not appear to have any effect on a turtle's probability of being recaptured.

Turtles released both north and south of the plant returned. Recaptures also did not appear to be related to size, as both juveniles and adults were captured more than once (range of SLCL = 47-89 cm). As for overall captures, the majority of recapture incidents involved juveniles (SLCL < 70 cm).

Recapture intervals for loggerheads ranged from 1 to 858 days, with a mean of 151 days (+173 days). All three green turtles caught more than once were captured twice, with recapture intervals ranging from 38 to 75 days. About 58 percent of all log-gerhead recapture incidents occurred within 90 days of previous capture and 89 per-cent within one year (Figure 18). The average interval between first and last capture was 263 days (+334 days). The longest period between first and last capture was 5.3 years. These data suggest that residency times of loggerheads within the nearshore habitat adjacent to the St. Lucie Plant are relatively short. Similar findings have been reported for loggerheads inhabiting the Mosquito/Indian River Lagoons of east-central Florida (Mendonca and Ehrhart, 1982).

35

SUMMARY

A gradient of increasing loggerhead turtle nest densities from north to south along the northern half of Hutchinson Island has been shown during most survey years. This gradient may result from variations in beach topography, offshore depth contours, dis-tribution of nearshore reefs, onshore artificial lighting and human activity on the beach at night. Low nesting activity in the vicinity of the power plant during 1975 and from I

1981 through 1983 was attributed to nighttime construction activities associated with installation of power plant intake and discharge structures. Nesting returned to normal or above normal levels following both periods of construction. During 1991, daytime construction activities associated with velocity cap repairs had no apparent effect on nesting. Statistical analyses indicate that power plant operation, exclusive of nighttime construction, has had no significant effect on nest densities near the plant.

There have been considerable year-to-year fluctuations in loggerhead nesting ac-tivity on Hutchinson Island from 1971 through 1992. Fluctuations are common at other rookeries and may result from non-annual reproductive behavior. Despite these fluc-tuations, loggerhead nesting activity has remained high during recent years and may reflect an overall increase in the number of nesting females in the Hutchinson Island area. No relationship between total nesting on the island and power plant operation or intake/discharge construction was indicated.

Temporary declines in loggerhead nesting activity have been attributed to cool water intrusions that frequently occur over the continental shelf of southeast Florida.

Though temporal nesting patterns of the Hutchinson Island population may be in-36

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fluenced by natural fluctuations in water temperature, no significant effects due to power plant operation have been indicated.

Since nesting surveys began in 1971, raccoon predation was considered the major cause of turtle nest destruction on Hutchinson Island. From 1971 through 1977, overall predation rates in the nine survey areas were between 21 and 44 percent, However, a pronounced decrease in raccoon predation occurred after 1977, and over-all predation rates in the nine survey areas have not exceeded ten percent since 1979.

Decreased predation by raccoons probably reflects a decline in the raccoon popula-tion.

During 1992, 146 green turtle and 30 leatherback turtle nests were recorded on Hutchinson Island. Nesting activity by these two species exhibited considerable annual fluctuations, as has been recorded at other rookeries, but has remained relatively high during recent years. This may reflect an overall increase in the number of nesting green and leatherback turtles in the Hutchinson Island area.

During 1992, 187 loggerheads, 61 green turtles, 1 leatherback and 2 hawksbills were removed from the St. Lucie Plant intake canal. Since monitoring began in May 1976, 2,083 loggerhead, 379 green, 10 leatherback, 11 hawksbill and 18 Kemp's rid-ley turtles have been captured. Over the life of the monitoring program, annual catches for loggerhead turtles have ranged from 33 in 1976 (partial year of plant operation and monitoring) to a high of 195 in 1986. Yearly catches of green turtles have ranged from 0 in 1976 to 69 in 1984. Differences in the number of turtles entrapped during different years and months are attributed primarily to natural variation in the occurrence of turtles 37

in the vicinity of the offshore intake structures, rather than to plant operating charao-teristics.

Size-class distributions of loggerhead turtles removed each year from the canal have consistently been predominated by Juveniles between 50 and 70 cm in straight line carapace length. Over 75 percent of all green turtles entrapped in the canal were juveniles 40 cm or less in length. For both species, the largest number of captures for all years combined occurred during the winter, but these seasonal peaks were much more pronounced for green turtles. Sex ratios of both adult and immature loggerheads caught in the canal continued to be biased towards females.

During 1992, about 90 and 93 percent, respectively, of all loggerheads and green turtles removed from the canal were categorized by physical appearance as being in good to excellent condition. Over the entire 17 year monitoring period, 77 and 80 per-cent, respectively, of all loggerhead and green turtle captures have involved individuals in these categories; 15 percent of the loggerheads and 12 percent of the green turtles removed from the canal have been in fair or poor condition.

Only three turtles removed from the intake canal during 1992 had substantial in-juries, and most of those were apparently sustained prior to entrapment. Once in the canal, turtles confined east of A1A typically had very brief residency times. Thus the relative condition of most turtles was not affected by their entrapment.

During 1992, two loggerhead and two green turtle mortalities were recorded in the intake canal. Cause of death could not be positively determined for any, but poor health is suspected in the case of the loggerheads. Program modifications, including

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continual surveillance of tangle nets:during periods of deployment, improvements to the integrity of the A1A barrier net and greater effort to hand capture turtles have con-tributed to a substantial decline in sea turtle mortalities during recent years.

39

LITERATURE CITED ABI (Applied Biology, Inc). 1977. Ecological monitoring at the Florida Power & Light Co. St.

Lucie Plant, annual report 1976. Volumes I and II. AB-44. Prepared by Applied Biology, Inc. for Florida Power & Light Co., Miami.

. 1978. Ecological monitoring at the Florida Power & Light Co. St. Lucie Plant, annual report 1977. Volumes I and II. AB-101. Prepared by Applied Biology, Inc. for Florida Power & Light Co., Miami.

. 1979. Florida Power & Light Company, St. Lucie Plant annual non-radiologi-cal environmental monitoring report 1978. Volumes II and III, Biotic monitoring. AB-177. Prepared by Applied Biology, Inc. for Florida Power & Light Co., Miami.

. 1980a. Florida Power & Ught Company, St. Lucie Plant annual non-radiologi-cal environmental monitoring report 1979. Volumes II and III, Biotic monitoring. AB-244. Prepared by Applied Biology, lnc. for Florida Power & Light Co., Miami.

. 1980b. Turtle entrainment deterrent study. AB-290. Prepared by Applied Biology, Inc. for Florida Power & Light Co., Miami.

.,1981a. Successful relocation of sea turtle nests near the St. Lucie Plant, Hutchinson Island, Florida. AB-317. Prepared by Applied Biology, lnc. for Florida Power 8 Light Co., Miami.

. 1981b. Florida Power & Light Company, St. Lucie Plant annual non-radiologi-cal environmental monitoring report 1980. Volumes II and III, Biotic monitoring. AB-324. Prepared by Applied Biology, Inc. for Florida Power & Light Co., Miami.

. 1981c. Proposed St. Lucie Plant preoperational and operational biological monitoring program - August 1981. AB-358. Prepared by Applied Biology, Inc. for Florida Power 8 Light Co., Miami.

. 1982. Florida Power & Light Company, St. Lucie Plant annual non-radiologi-cal environmental monitoring report 1981 Volumes II and III, Biotic monitoring. AB-

~

379. Prepared by Applied Biology, Inc. for Florida Power & Light Co., Miami.

. 1983. Florida Power & Light Company, St. Lucie Plant annual non-radiologi-cal aquatic monitoring report 1982. Volumes I and II. AB-442. Prepared by Applied Biol-ogy, lnc. for Florida Power & Light Co., Miami.

40

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ABI (Applied Biology, Inc.). 1984a. Florida Power & Light Company, St. Lucie Plant annual non-radiological environmental monitoring report 1983. Volumes I and II. AB-530.

Prepared by Applied Biology, Inc. for Florida Power & Light Co., Miami.

. 1984b. Florida Power & Light Company, St. Lucie Unit 2 annual environ-mental operating report 1983. AB-533. Prepared by Applied Biology, Inc. for Florida Power & Light Co'., Miami.

. 1985a. Florida Power & Light Company, St. Lucie Plant annual non-radiologi-cal environmental monitoring report 1984. AB-553. Prepared by Applied Biology, Inc.

for Florida Power & Light Co., Juno Beach.

. 1985b. Florida Power & Light Company, St. Lucie Unit 2 annual environ-mental operating report 1984. AB-555. Prepared by Applied Biology, Inc. for Florida Power & Light Co., Juno Beach.

. 1986. Florida Power & Light Company, St. Lucie Unit 2 annual environmen-tal operating report 1985. AB-563. Prepared by Applied Biology, Inc. for Florida Power

& Light Co., Juno Beach.

. 1987. Florida Power & Light Company, St. Lucie Unit 2 annual environmen-tal operating report 1986. AB-579. Prepared by Applied Biology, Inc. for Florida Power

& Light Co., Juno Beach.

. 1988. Florida Power & Light Company, St. Lucie Unit 2 annual environmen-tal operating report 1987. AB-595. Prepared by Applied Biology, Inc. for Florida Power

& Light Co., Juno Beach.

. 1989. Florida Power & Light Company, St. Lucie Unit 2 annual environmen-tal operating report 1988. AB-596. Prepared by Applied Biology, Inc. for Florida Power

& Light Co., Juno Beach.

. 1990. Florida Power & Light Company, St. Lucie Unit 2 annual environmen-tal operating report 1989. AB-603. Prepared by Applied Biology, Inc. for Florida Power

& Light Co., Juno Beach.

~ 1991. Florida Power & Light Company, St. Lucie Unit 2 annual environmen-tal operating report 1990. AB-610. Prepared by Applied Biology, Inc. for Florida Power

& Light Co., Juno Beach.

. 1992. Florida Power &. Light Company, St. Lucie Unit 2 annual environmen-tal operating report 1991. AB-617. Prepared by Applied Biology, lnc. for Florida Power

& Light Co., Juno Beach.

Baldwin, W.P., Jr. and J.P. Lofton, Jr. 1959. The loggerhead turtles of Cape Romain, South Carolina. Previously unpublished manuscript abridged and annotated by D.K. Caldwell, without the authors. In D.K. Caldwell and A. Carr, coordinators, The Atlantic logger-head sea turtle, Caretta caretta caretta (L.), in America. Bulletin of the Florida State Museum,'iological Sciences, 4(10):319-348.

Bellmund, S., M.T. Masnik and G. LaRoche. 1982. Assessment of the impacts of the St. Lucie 2 Nuclear Station on threatened or endangered species. US Nuclear Regulatory Com-mission, Office of Nuclear Reactor Regulation.

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Bustard, H.R. and P. Greenham. 1968. Physical and chemical factors affecting hatching in the green sea turtle, Chelonla ~mdas (L.). Ecology 49(2):269-276.

'I Caldwell, D.K. 1962. Comments on the nesting behavior of Atlantic loggerhead sea turtles, based primarily on tagging returns. Quarterly Journal of the Florida Academy of Scien-ces 25(4):287-302.

Caldwell, D.K., A. Carr and L.H. Ogren. 1959. Nesting and migration of the Atlantic logger-head turtle. In D.K. Caldwell and A. Carr, coordinators, The Atlantic loggerhead sea turtle Caretta caretta caretta (L.), in America. Bulletin of the Florida State Museum, Biological Sciences, 4(10):295-308.

Camp, D.K., N.W. Whiting and R.E. Martin. 1977. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974. V. Arthropods. Florida Marine Research Publications 25:

1-63.

Carr, A., A. Meylan, J. Mortimer, K. Bjorndal and T. Carr. 1982. Surveys of sea turtle popula-tions and habitats in the Western Atlantic. NOAATechnical Memorandum NMFS-SEFC-91:1-82.

Davis, G.E., and M.C. Whiting. 1977. Loggerhead sea turtle nesting in Everglades National Park, Florida, U.S.A. Herpetologica 33:18-28.

gi dAW 1976 9 di gti gd d 1 i itl 9 till t,~WA imbricata L., on Cousin Island, Seychelles. Biological Conservation 9:199-215.

1 t Ehrhart, L.M. 1979. Reproductive characteristics and management potential of the sea turtle rookery at Canaveral National Seashore, Florida. Pages 397-399 in Linn, R.M., ed.

Proceedings of the First Conference on Scientific Research in the National Parks, 9-1 2 November, 1976, New Orleans, La. NPS Trans. and Proc. Ser. No. 5.

42

Ehrhart, L.M. 1980..Threatened and endangered species of the Kennedy Space Center:

marine turtle studies. In A continuation of baseline studies for environmentally monitor-ing space transportation systems (STS) at John F. Kennedy Space Center. Contract No. NAS-10-8986. Vol. IV, NASA Report 163122. September 1980.

. 1987. Marine turtle mortality in the vicinity of Port Canaveral, Florida, 1977-84. In W.N.

Witzell, editor, Ecology of East Florida Sea Turtles, pages 1-20. NOAATechnical Report NMFS 53.

Ernest, R.G., R.E. Martin, B.D. Peery, D.G. Strom, J.R. Wilcox and N.W. Walls. 1988. Sea turtle entrapment at a coastal power plant. Pages 270-301 in Mahadevan, K., R.K. Evans, P.

Behrens, T. Biffar and L. Olsen, eds. Proceedings, Southeastern Workshop on Aquatic Ecological Effects of Power Generation. Report No. 124, Mote Marine Laboratory, Sarasota, Florida.

Ernest, R.G., R.E. Martin, N.W. Walls and J.R. Wilcox. 1989. Population dynamics of sea turtles utilizing shallow coastal waters off Hutchinson Island, Florida. Pages 57-59 in Eckert, S.A., K.L. Eckert and T.H. Richardson, compilers. Proceedings of the Ninth Annual Workshop on Sea Turtle Conservation and Biology. NOAA Technical Memorandum NMFS-SEFC-232.

Fowler, L.E. 1979. Hatching success and nest predation in the green sea turtle, Chelonia

~mdas at Tortuguero, Costa Rica. Ecology 50(5):945-955.

Frazer, N.B. 1989. Nesting cycles in sea turtles: typical, but not cycles. Pages 61-64 in Eck-ert, S.A., K.L. Eckert and T.H. Richardson, compilers. Proceedings of the Ninth Annual Workshop on Sea Turtle Conservation and Biology. NOAA Technical Memorandum NMFS-SEFC-232.

Futch, C.R. and S.E. Dwinell. 1977. Nearshore marine ecology at Hutchinson Island, Florida:

1971-1974. IV. Lancelets and Fishes. Florida Marine Research Publications 24: 1-23.

Gallagher, R.M. 1977. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974.

II. Sediments. Florida Marine Research Publications 23: 6-24.

Gallagher, R.M. and M.L. Hollinger. 1977. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974. I. Introduction and rationale. Florida Marine Research Publications 23: 1-5.

t Gallagher, R.M., M.L. Hollinger, R.M. Ingle and C.R. Futch. 1972. Marine turtle nesting on Hutchinson Island, Florida in 1971. Florida Department of Natural Resources, Special Scientific Report 37:1-11.

43

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Hendrickson, J.R. and E. Balasingam. 1966. Nesting beach preferences of Malayan sea turtles. Bulletin of the National Museum Singapore 33(10):69-76.

Henwood, T.A. 1987. Movements and seasonal changes in loggerhead turtle, Q~rt~tt ggret-ta aggregations in the vicinity of Cape Canaveral, Florida (1978-84). Biological Con-servation 40:191-202.

Hillestad, H.O., J.l. Richardson, C. McVea, Jr. and J.M. Watson, Jr. 1982. Worldwide inciden-tal capture of sea turtles. Pages 489-496 in Bjorndal, K.A., ed. Biology and conserva-tion of sea turtles. Smithsonian Institution Press, Washington, D.C.

Hirth, H.F. 1980. Some aspects of the nesting behavior and reproductive biology of sea turtles.

American Zoologist 20:507-523.

Hopkins, S.R., T.M. Murphy, Jr., K.B. Stansell and P.M. Wilkinson. 1979. Biotic and abiotic factors affecting nest mortality in the Atlantic loggerhead turtle. Proceedings Annual Conference of Southeastern Fish and Wildlife Agencies 32:213-223.

Hughes, G.R. 1974. The sea turtles of southeast Africa, 1. Status, morphology and distribu-tions. South African Association for Marine Biological Research, Oceanographic Research Institute, Investigational Report No. 35:1-144.

. 1976. Irregular reproductive cycles in the Tongaland loggerhead sea turtle, Caretta caretta (L) (Cryptodira:Chelonidae). Zoologica Africana 11(2):285-291.

Lyons, W.G. 1989. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974. Part XI. Mollusks. Florida Marine Research Publication 47:1-131.

Martin, R.E., R,G. Ernest, N.W. Walls and J.R. Wilcox. 1989a. Size distribution and seasonal abundance of loggerhead and green turtles in nearshore waters off Hutchinson Island, Florida. Pages 334-335 in Ogren, L., F. Berry, K. Bjorndal, H. Kumpf, R. Mast, G.

Medina, H. Reichart and R. Witham, editors. Proceedings of the Second Western At-lantic Turtle Symposium. Mayaguez, Puerto Rico, 12-16 October 1987. NOAA Techni-cal Memorandum NMFS-SEFC-226.

. 1989b. Long-term trends in sea turtle nesting on Hutchin-son Island, Florida. Pages 111-113 in Eckert, S.A., K.L. Eckert and T.H. Richardson, compilers. Proceedings of the Ninth Annual Workshop on Sea Turtle Conservation and Biology. NOAA Technical Memorandum NMFS-SEFC-232.

I Mendonca, M.T. and LM. Ehrhart. 1982. Activity, population size and structure of the imma-tore ~Ch i nia~md~aand garetta oaretta in Moaquito Lagoon, Florida. Copeia 1982(1) 161-167.

Moffler, M.D. and J.F. Van Breedveld.=1979. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974.X. Benthic algae species list. Florida Marine Research Publications 34: 118-122.

Mortimer, J.A. 1982. Factors influencing beach selection by nesting sea turtles. Pages 45-51 in Bjorndal, K.A., ed. Biology and Conservation of Sea Turtles. Smithsonian Institution Press. Washington, D.C.

NMFS (National Marine Fisheries Service). 1978. Final EIS listing and protecting the green sea turtle (CGhlonia ~mdas, loggerhead sea turtle ((:ari~tt ~caretta and the Pacific Ridley

~id At ~li d tt Ed 9 dgp t At ttgtd.3tt al Marine Fisheries Service, Dept. of Commerce, Washington, D.C.

NRC (US Nuclear Regulatory Commission) 1982. Final environmental statement related to

~

the operation of St. Lucie Plant Unit 2. Docket No. 50-389.

O'ara, J. 1980. Thermal influences on the swimming speed of loggerhead turtle hatchlings.

Copeia 1980(4):773-780.

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Owens, D.W. and G.J. Ruiz. 1980. New methods of obtaining blood and cerebrospinal fluid from marine turtles. Herpetologica 36:17-20.

Pritchard, P.C., P.R. Bacon, F.H. Berry, A.F. Carr, J. Fletemeyer, R.M. Gallagher, S.R. Hop-kins, R.R. Lankford, R. Marques M., LH. Ogren, W.G. Pringle, Jr., H.A. Reichart and R. Witham: 1983. Manual of sea turtle research and conservation techniques. Prepared for the Western Atlantic Turtle Symposium, San Jose, Costa Rica, July 1983. 126 pp.

Proffitt, C.E., R.E. Martin, R.G. Ernest, B.J. Graunke, S.E. LeCroy, K.A. Muldoon, B.D. Peery, J.R. Wilcox and N. Williams-Walls. 1986. Effects of power plant construction and opera-tion on the nesting of the loggerhead sea turtle (Caretta ~caretta:197t-1994. Copeia 1986(3): 813-816.

Raymond, P.W. 1984. The effects of beach restoration on marine turtles nesting in south Brevard County, Florida. M.S. thesis, University of Central Florida.

Routa, R.A. 1968. Sea turtle nest survey of Hutchinson Island, Florida. Quarterly Journal Florida Academy of Sciences 30(4):287-294.

45

Schulz, J.P. 1975. Sea turtles nesting in Surinam. Zoologische Verhandelingen, uitgegeven door het Rijksmuseum van Natuurlijke Historic te Leiden, No. 143:1-144.

Smith, N.P. 1982. Upwelling in Atlantic shelf waters of south Rorida. Florida Scientist 45(2):125-138.

Sokal, R.R. and F.J. Rohlf. 1981. Biometry. The principles and practice of statistics in biologi-cal research. W.H. Freeman and Company, San Francisco. 859 pp.

Stancyk, S.E. 1982. Non-human predators of sea turtles and their control. Pages 139-152 in Bjorndal, K.A., ed: Biology and Conservation of Sea Turtles. Smithsonian Institution Press. Washington, D.C.

Talbert, O.R., S.E. Stancyk, J.M. Dean and J.M. Will. 1980. Nesting activity of the loggerhead turtle (Caretta~oaretta in South Carolina. I: A rookery in transition. Copeia t 980:(4)709-718.

Taylor, C.B., and H.B. Stewart. 1958. Summer upwelling along the east coast of Florida. Jour-nal of Geophysical Research 64(1):33-40.

Tester, LA. and K.A. -Steidinger. 1979. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974. Vll. Phytoplankton, 1971-1973. Florida Marine Research Publica-tions 34: 16-61 ~

Walker, LM. 1979. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974. IX.

Diel plankton, 1973-1974. Florida Marine Research Publications 34: 99-117.

Walker, L.M., B.M. Glass and B.S. Roberts. 1979. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974. Vill. Zooplankton, 1971-1973. Florida Marine Research Publications 34: 62-98.

Walker, L.M. and K.A. Steidinger. 1979. Nearshore marine ecology at Hutchinson Island, Florida: 1971-1974. Vl. Plankton dynamics, 1971-1973. Florida Marine Research Publications 34: 1-1 5.

Wibbels, T., R.E. Martin, D.W. Owens, and M.S. Amoss, Jr. 1991. Female-biased sex ratio of immature loggerhead sea turtles inhabiting the Atlantic coastal waters of Florida.

Canadian Journal of Zoology. 69:2973-2977.

t Wibbels, T., D.W. Owens, Y. Morris, and M. Amoss. 1987. Sexing techniques and sex ratios for immature loggerhead sea turtles captured along the Atlantic coast of the United States. Pages 65-74 in W.N. Witzell, editor. Ecology of East Florida Sea Turtles. NOAA Technical Report NMFS-53.

Williams-Walls, N., J. O'ara, R.M. Gallagher, D.F. Worth, B.D. Peery and J.R. Wilcox, 1983.

Spatial and temporal trends of sea turtle nesting on Hutchinson island, Florida, 1971-1979. Bulletin of Marine Science 33(1):55-66.

Witherington, B.E. and LM. Ehrhart. 1989. Status and reproductive characteristics of green turtles ~Cheloni ~mdas nesting in Florida. Pages 351-352 in Ogren, L, F. Berry, K.

Bjorndal, H. Kumpf, R. Mast, G. Medina, H. Re!chart and R. Witham, editors. Proceed-ings of the Second Western Atlantic Turtle Symposium. Mayaguez, Puerto Rico, 12-16 October 1987. NOAATechnical Memorandum NMFS-SEFC-226.

W II WN1983Sy p i tlat t gi Id i th h k tillt nl.~Ehl (Linnaeus, 1766). FAO Fisheries Synopsis, 137:1-78.

Worth, D.F. and M.L. Hollinger. 1977. Nearshore marine ecology at Hutchinson tsland, Florida:

1971-1974. Ill. Physical and chemical envirorIment. Florida Marine Research Publica-tions 23: 25-85.

Worth, D.F., and J.B. Smith. 1976. Marine turtle nesting on Hutchinson island, Florida, in 1973.

Florida Marine Research Publications 18:1-17.

47

GULF OF MEXICO YAROS KILOMETERS SCALC V~

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0 St. Lucio Plant Figure 1. Location of the St. Lucie Plant.

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1 0 INTAKE'>.

INTAKE 0+ HEADWALL; WELLS INTAKE STRUCTURES UIDS A1A'.:.:.

BARRIER BARRIER.:

\~ ,.. NET .~:,

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rl'NTAKE 0 250,500 CANAL METERS Figure 2. St. Lucie Plant cooling water intake and discharge system.

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~~St. I.vcle Inlet Figure 3. Designation and location of nine 1.25-km segments and thirty-six 1-km segments surveyed for sea turtle nesting, Hutchinson Island, 1971-1992.

320 300 280 220 200

)

180

~

isO 140 100 80 0

ABCDEI-"GH JKLMNOPQRSTUVWXYZABCDEtGH I I J ABCDEFGH I

~~R ~ROTI' SCX3'I%i J'4CtR.'rH Figure 4. Number of loggerhead turtle nests in each of the thirty-six 1-km-long survey areas, Hutchinson Island, 1992.

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600 GOO 300 ma 100 ABCD EFGH l 4 KlMNOP QRSTUVNX YZABCD EI=QH

~ADITI'CKTZXi I

ABCDEFGH I J

~TXX Figure 5- Number of loggerhead turtle emergences in each of the thirty-six 1-km-long survey areas, Hutchinson Island, 1992.

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70 60 So 30 10 ABCDEFQH JKLMNOPQRSTUY'OXYZABCDEl=GH l PLsMFI'CX3'I'H I

AaCC EFGH1 J NORTH PC$ WKR Fig~re 6. Loggerhead turtle nesting success (percentage of emergences that resulted in nests) for each of the thirty-six 1-hn-long survey areas, Hutchinson Island, 1992.

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C3 AREA 4 (POSER PLANT SITE)

+ AREA 5 (CONTROL SITE) 7l 72 73 74 75 76 77 78 79 80 8't 82 83 84 85 86 87 88 89 90 Sl 92 Figure 7. Number of loggerhead turtle nests in Areas 4 and 5, 1971-1992-

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W W W W W W 7000 6000 3000 2000 KQQ 0

7l 72 73 74 78 76 77 78 79 80 81 82 83 84 88 86 87 88 89 90 91 92 Figure 8. Number of loggerhead turtle nests, Hutchinson Island, 1971-1992. Numbers for 1971-1979 are estimates; numbers for 1981-1992 are recorded values (see text).

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an frl CC f4 0

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aa 100 8O 70 I )

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15 38 5 15 38 5 15 38 5 15 38 5 15 38 5 Figure 9. Daily loggerhead turtle nesting activity and water temperature, Hutchinson Island, 1992.

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Destroyed by raccoons 8 ghost crabs Destroyed by ghost crabs Destroyed by raccoons 30 ABCDEFQH JKlMNOPQRSTUVWXY2ABCDEFQH I I J ABCD EFQH I J MAR TH PC$ WKR PLANT SCÃ3'1%%

Figure 18. Number of loggerhead turtle nests destroyed by raccoons and ghost crabs in each 1-km-long survey area, Hutchinson Island, 1992.

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150 140 Cl Green Tuft 1e 130 + Leatherback Turtle 120 110 E 100 So 80 0

70 60 60 40 30 1'0 0

71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 8S 90 91 82 Figure 11. Number of green and leatherback turtle nests, Hutchinson Island, 1971-1992.

200 Cl LOGGERHEAD (Caretta caretta) 190 GREEN (Gheleaia ~mdas) lao 170 160 1:60 T40 130 1,20 110 100 0 90 80 70 60 GO 40 30 20 10 0

76 77 78 79 aa 81 82 83 84 88 M 8? 88 89 80 Sl 92 YEKk OF STUDY Figure 12. Number of loggerhead and green turtles removed each year from the intake canal, St. Lucie Plant, 1976-1992.

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400 M 300 260 200 100 40 4H 46 86- 6l 71 8't 9I 101- 106- >T10 48 80 88 60 68 70 78 80 88 90 98 ]GO X)8 710 Figure 13. Length a~araxrr ~m anxmrwca ~~ (~)

distribution (SLCL) of loggerhead turtles (N=1,S79) removed for the first time from the intake canal, St. Lucie Plant, 1976-1992. No data collected for 83 individuals.

130 120 110 100 0 60 I so 10

<% 16 26 36 46 66 66 76 86 S6-101-106-ETIO 20 28 30 3S 40 46 80 SS 60 66 70 76 80 85 80 96 1OO 1OS TIO STEVhZGHT LEONE CB&2WACE LiEHG'Hi (~)

Figure 14. Length distribution (SLCQ of green turtles (N=366) removed for the first time from the intake canal, St. Lucie Plant, 1976-1992. No data collected for 19 individuals.

70 MALES FEMALES 60 80 O 30 10 DAN FEB MAR APR MAY JUN JVl AUG SEP OCT NOV DEC Figure 15. Numbers of adult loggerheads (SLCL>85.8 cm), including recaptures, removed, each month from the intake canal, St. Lucie Plant, 1976-1992 (N=299i sex not recorded for 5 individuals >85.0 cm).

I SO W

Q 4O ao 2O A

0 1O I O 19TT19T8 19T91QSO 1981 1982 1QSQ 1984 1QSS 1QSS 19ST 1966 1Q8Q 19QO 1991 1982 TOO gR SOO GOO Vl Ql U

4OO M

aOO R

0 2OO 1OO O

19TT 1QTS 19TQ 1QSO 1961 1Q62 lSRL3 1QS4 1966 1QSd 1QST 1966 1969 199O 1QQ1 IQQ2 Figure 16. Comparison of captures of adult female loggerheads (SLCL)85.0 cm) in the intake canal, St. Lucie Plant, 1977-1992, and numbers of loggerhead emergences in area 4 adjacent to the plant. Nesting activity was not monitored in 1978.

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100 90 7O sa 0

20 LOGGERHEAD (Caretta caretta) ia

+ GREEN (Cnelonia ~mdas) 10 ]5 2G 28 30 38 40 45 SO SS 60 Figure 17. Capture efficiency, expressed as days between first sighting and capture, for loggerhead (N=272) and green turtles (N=73) entrapped in the intake canal, St. Lucie Plant, April, 1998-December, 1992.

A

~l

[4 I

intervai between rirst anu iast capture interval between successive captures 755 1258 15M 1755 XNTKR~ (cia~)

Figure 18. Cumulative percentage of all loggerhead recaptures occurring within various time intervals between successive captures (N=119) and first and last capture (N=68), St. tucie Plant intake canal 1976-1992-

TABLE 1 ESTIMATES OF THE NUMBERS OF LOGGERHEAD TURTLE NESTS ON HUTCHINSON ISLAND BASED ON SURVEYS OF NINE 1.25-KM-LONG SURVEY AREAS, 1971 - 1992, COMPARED TO THE ACTUALNUMBER OF NESTS ON THE ISLAND, 1981 - 1992 Extrapolation from the Actual number Number of nests in the nine nine survey areas to the of nests on the 1971 1420 41 88 1973 1260 3716 1975 1493 4403 1977 2748 1979 1449 4273 1981 1031 3040 3115 1982 1634 4819 1983 1592 4743 1984 1439 4244 4277 1985 1623 4786 4877 1986 1839 5423 5483 1987 1645 4851 4623 1988 1701 5016 1989 1774 5232 2177 6420 6700 1991 2409 7104 6812 1992 2150 6340 6459

TABLE 2 TOTAL NUMBER OF SEA TURTLE CAPTURES AND (NUMBER OF DEAD) TURTLES REMOVED FROM THE INTAKE CANAL ST. LUCIE PLANT, 1976-1992 1976 ss(4) 33(4) 1977 80(5) 5(2) 86(7) 1978 138(19) 6(1) 148(20) 1979 172(13) s(1) 175(14) 1980 116(5) 10(3) 126(8) 1981 62(5) 32(2) 97P) 1982 101(16) 8 110(16) 1983 119(4) 23(4) 142(8) 1984 148(3) 69(2) 220(5) 1985 157(4) 14 172(4) 1986 195(27) 22(1) 1 220(28) 1987 175(11) 35 6(2) 218(13) 1988 134(6) 42(2) 5(2) 181 (10) 111(4) 17(1) 2 1ss(5) 112(1) 20(2) 132(3) 1991 107(1) 12 121 (1) 1992 123(2) 61(2) 1 2 187(4)

Total 2083(130) s79(2s) 10(0) 11(0) 18(4) 2501(157)

Annual Mean 128.1 23.7 0.6 0.7 1.1 154.3 Std. Deviation 35.2 19.7 0.9 0.8 1.9 43.3 Exoiudes 1976 (partial year of plant operation).

TABLE 3 TOTAL NUMBER OF LOGGERHEAD TURTLES REMOVED EACH MONTH FROM THE INTAKE CANAL ST. LUCIE PLANT,1977 -1992 1977 Through 1992 1992 Number of Percent of Standard January 251 12.2 39 15.7 - 8.5 19 February 202 99 12.6 5.8 12 March 175 8.5 27 10.9 7.0 April 9.2 24 11.8 7.3 13 May 176 8.6 28 11.0 8.8 June 10.9 30 14.0 9.2 July 187 9.1 27 11.7 9.1 16 August 9.1 34 11.6 9.2 September 138 6.7 19 8.6 5.5 October 129 6.3 17 8.1 5.3 November 4.5 15 5.8 4.2 December 100 4.9 13 6.3 4.1 13 Total 2050 39 123 Mean 170.8 10.7 10.3 Std. Deviation 47.7 7.6 5.2 First full year of plant operation. An additional 33 loggerheads were captured during 1976.

TABLE 4 TOTAL NUMBER OF GREEN TURTLES REMOVED EACH MONTH FROM THE INTAKE CANAL ST. LUCIE PLANT, 1977 -1992 1977 Through 1992 1992 Number of Percent of Standard January 102 26.9 37 6.4 " 9.7 February 58 15.3 3.6 3.4 March 35 9.2 2.2 2.1 April 22 5.8 1.4 1.0 May 10 2.6 0.6 0.9 June 18 4.7 1.6 July 2.1 0.5 0.7 August 12 3.2 0.8 1.0 September 12, 3.2 0.8 1.5 6 October 8.7 18 2.1 4.5 18 November 8.7 12 2.1 3.1 12 December 36 9.5 2.3 3.5 Total 379 37 61 Mean 31.6 2.0 5.1 Std. Deviation 26.6 3.9 7.8 First full year of plant operation.

TABLE 5 NUMBER OF MONTHLYCAPTURES BY SIZE CLASS FOR LOGGERHEAD TURTLES REMOVED FROM THE INTAKE CANAL ST. LUCIE PLANT, 1977-1992 Size classes SLCL in cm January 17 106 207 15.1 28 9.5 7 3 0 10 3.3 February 12 66 162 11.8 21 7.1 2 4 0 6 2.0 March 75 53 137 10.0 21 7.1 1 6 2 9 3.0 April 17 57 61 135 9.8 31 10.5 3 6 0 9 3.0 May 12 59 111 8.1 17 5.8 15 28 1 44 14.5 June

'6 13 52 109 8.0 29 9.8 44 29 3 76 25.0 July 47 35 86 6.3 33 11.2 28 34 4 21.7 August 45 51 103 7.5 36 12.2 21 20 42 13.8 September 55 42 101 7.4 16 5.4 9 2 17 5.6 October 37 87 6.3 28 9.5 2 1 3.0 November 27 24 57 4.2 21 7.1 4 5 1 10 3.3 December 28 76 5.5 14 4.7 2 4 0 2.0 Total 115 691 1371 295 139 150 15 304'

% of Total 69.6 15.0 15.4 Excludes 1976 (partial year of data).

"No data were collected for 80 individuals.

TABLE 6 RELATIVE CONDITION OF SEA TURTLES REMOVED FROM THE INTAKE CANAL ST. LUCIE PLANT, 1976- 1992 Relative 479 23.0 176 46.4 1 10.0 3 167 9 81.8 668 26.7 586 28.1 72 19.0 2 20.0 3 16.7 2 182 665 26.6 548 26.3 57 15.0 7 70.0 3 16.7 615 24.6 237 11.4 38 10.0 3 16.7 278 11.1 76 3.6 8 21 2 . 11.1 86 3.4 130 6.2 23 6.1 4 22.2 157 6.3 27 1.3 5 1.3 32 1.3 Total 2083 379 10 18 2501 1 Excellent: normal or above normal weight, active, very few or no barnacles or leeches, no wounds.

2 Very good: intermediate good to excellent.

3 Good: normal weight, active, light to medium coverage of barnacles and/or leeches, wounds absent, healed or do not appear to debilitate the animal.

4 Fair: intermediate poor to good.

5 Poor: emaciated, slow or inactive, heavy barnacle coverage and/or leech infestatlon, debilitating wounds or missing appendages.

6 Dead 7 Alive but otherwise condition not recorded.

FLORIDA POWER & LIGHT COMPANY ST. LUCIE UNIT 2 ANNUALENVIRONMENTALOPERATING REPORT (FPL-92)

APRIL 1993 VOLUME II

ANNUALENVIRONMENTALOPERATING REPORT Introduction The St. Lucie Unit 2 Environmental Protection Plan (EPP) requires the submittal of an annual report for various activities at the plant site including the reporting on sea turtle monitoring programs, and other matters related to Federal and State environmental permits and certifications.

This report and Volume I described below fulfillthese reporting requirements.

II. Sea Turtle Monitorin and Associated Activities A report on aquatic and terrestrial sea turtle monitoring programs as described. in EPP Sections 4.2.1 (Beach Nesting Surveys), 4.2.3 (Studies to Evaluate and/or Mitigate Intake Canal Mortality) and 4.25 (Capture and Release Program) is concurrently submitted in a separate report (AB-623 Vol. I) prepared by Applied Biology, Inc. of Jensen Beach, Florida and Atlanta, Georgia.

Studies to evaluate and/or mitigate intake entrapment required by Section 4.2.2 of the EPP have been previously performed. A final report was submitted to the Office of Nuclear Reactor Regulation on April 18, 1985. With submittal of that report, the EPP requirement was fulfilled and,will not be readdressed in this or future reports.

Surveillance and maintenance of the light screen to minimize sea turtle disorientation as required by Section 4.2.4 of the EPP is ongoing. The Australian Pine light screen or other vegetation located on the beach dune between the power plant and the ocean is routinely surveyed to determine its overall vitality. The vegetation line is surveyed for any gaps occurring from mortality, which would result in unacceptable light levels on the beach. Trees, vegetation or shade cloth are replaced as necessary to maintain the overall integrity of the light screen.

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III. Other Routine Re orts The following items for which reporting is required are listed by section number from the plant's Environmental Protection Plan (EPP):

5.4.1(a) EPP NONCOMPLIANCES AND CORRECTIVE ACTIONS TAKEN No noncompliances under EPP Section 5.4.1(a) were determined to have occurred during 1992.

5.4.1(b) CHANGES IN STATION DESIGN OR OPERATION TESTS AND EXPERIMENTS IN ACCORDANCE WITH EPP SUBSECI'ION 3.1 No plant site activities were determined to be reportable under Section 5.4.1(b) during 1992.

5.4.1(c) NONROUTINE REPORTS SUBMITTED TO THE NRC FOR THE YEAR 1992 IN ACCORDANCE WITH EPP SUBSECTION 5.4.2:

1. Report concerning a modification to the St. Lucie Plant site's NPDES Permit issued by the USEPA for the use of the biocide Clamtrol; reported to the NRC on March 18, 1992.

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2. Report concernin'g the application-for-renewal of the St. Lucie Plant site's NPDES Permit; reported to the NRC on May 7, 1992.

3. Report concerning an exceedance of the NPDES Permit minimum pH limitation for sewage treatment plant effluent; reported to the NRC on June 24, 1992.

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4. Report concerning the release of hydrazine in an amount over the CERCLA RQ to the onsite Stormwater Basin; reported to the NRC on June 5, 1992.

5. Report concerning the release of hydrazine in an amount over the CERCLA RQ to the onsite Stormwater Basin; reported to the NRC on July 17, 1992.

6. Report concerning the exceedance of the NPDES Permit maximum time allowed for chlorination of the Unit 1 condensers; reported to the NRC on September 22, 1992.

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