Text

Response to Request for Additional Information System Disturbance
	ML18227D827
Person / Time
Site:	Saint Lucie, Turkey Point
Issue date:	12/14/1977
From:	Robert E. Uhrig; Florida Power & Light Co
To:	Lear G; Office of Nuclear Reactor Regulation
References
	L-77-380
	Download: ML18227D827 (70)
	v • d • e

DISTRIBUTION AFTER ISSUANCE OF OP .XNG LXCENSE NFIC'4VRM 195 UA NUCLEAR REGULATORY COMMISSION -ACKET NU Ie 4) w> )

PII E NUMS R NRC DISTRIBUTION PQR PART 50 DOCKET MATERIAL FRQMI OATE QP OQCUMENT Mr. George Lear Miami, Fl. 33101 Robert E. gehrig OATE RECEIVEO i QLETTER 0 NOTO R I ZE 0 PROP INPUT PQRM NUMBER QP COPIES RECEIVEO I

6 QRIQINAI QUNCLASSIPIEO SCOPY ENCl OSURK QESCRIPTIQN Furnishing response to NRC's $ tr dtd 10/05/77, defining Power System Stability as that attribute of a system or part of a system which enables it ti develpr restoring forces equal to or greater than.. disturbing forces so a restore a state of equilibrium...

1 /4IT TURKEY POINT UNITS 3 Bc 4 STe LUCXE UNIT p- 1

) cm 12/16/77'OR

! SAFETY ACTIQN/INFORMATION..

BRANCH CHIEF: 7 INTERNAI DISTRIBUTION a

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CONTROL NUi'ABER 7~P3SOOaO9 i':CRS 3.6 CYS SRi~ CATEGDR'f

P. O. 8OX 013100, MIAMI, FL 33101 FlORIDA POWER 8c LIGHT COMPANY December 14, 1977 L-77-380

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)q)ii j'h of Nuclear Reactor Regulation 'ffice Attention: Mr. George Lear, Chief .g <<4 /~f';~:~)

p t g R Division of Operating Reactors'~ o.~. Sf'~

U. S. Nuclear Regulatory Commission ',~ ce>II~~

Washington, D. C. 20555

Dear Mr. Lear:

Re: Florida Power & Light Company Docket Nos. 50-250, 50-251, and 50-335 Re uest for Information The Florida Power 6 Light Company response to your letter of October 5, 1977 is attached. Clarifying information obtained at a November 18, 1977 meeting with members of the NRC staff has been used in preparing this response. At the meeting, a revised due date of December 15, 1977 was established.

In the context of the attached material we define Power System Stability as that attribute of a system or part of a system which enables it to develop restoring forces equal to or greater than disturbing forces. so as to restore a state of equilibrium.

Very truly yours, i~~ Robert E. Uhrig Vice President.

. REU/MAS/lah Attachment cc: Mr. James P. O'Reilly, Region II Robert Lowenstein, Esquire 77S5P Q 109 PEOPLE... SERVIIIG FOPLE

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ATTACHMENT FLORIDA POWER 6 LIGHT COMPANY DOCKET NOS. 50-250, 50-251, & 50-335 NRC REQUEST FOR INFORMATION SYSTEM DISTURBANCE (5/16/77)

QUESTION 1 So that we may better understand the causal relationships between the events that occurred on May 16, 1977, please provide the following information:

1.1 A time trace of the real power loading on the Ft. Myers-Ranch 240kV line for the time period 10:08-10:24 am; 1.2 The normal rating of this line (MW, MVA);

1.3 The long time and short time emergency ratings; 1.4 If the ratings are given in MW, indicate the power factor to which they apply; 1.5 The MVA load (or the power factor) on the line when relayed open; it 1.6 If the information in Items 1.4 and 1.5 is not available, provide power factor or equivalent information at points as close to this line as available; and 1.7 The line loading information (power, power. factor, etc. )

on this line for each occasion in the past when layed open.

it re-RESPONSE 1 This line is not equipped with instrumentation from which to obtain a time trace of real power loading.

1.2 The normal rating is 1010 amperes continuous, or 420 MVA at 240kV. The conductor is 954MCM ACSR.

1.3 The continuous rating of the line is 1010 amperes, based on a conductor temperature of 75'C with an ambient of 25 C and 1.3mph wind.

The emergency rating is 1260 amperes (524 MVA 9 240kV) based on a conductor temperature of 100'C with an ambient of 35'C and 2mph wind. The time limit is 10,000 hours0 days 0 hours 0 weeks 0 months over the life of the conductor to restrict the loss of tensile strength to 10%. With a 7mph wind and 35'C ambient, the conductor can carry 2000 amps without. exceeding the 100'C conductor limitation.

The sag for a 650'ypical span is 10.5 feet with a conductor temperature of 60'F, 16.5 feet with a conductor temperature of 185~F.

1.4 Ratings were given in amperes.

1.5 This information is not available.

1.6 The combined MW load on the Ft. Myers-Ranch 138kV and can be determined with reasonable accuracy by 240kV'ircuits adding the "instantaneous" change in tie line flow on the TEC ties, the change in generation on the west coast plants, FM1, FM2 and MTl, and the change in load. The change in transmission losses is included with the load. From these changes, the flow west to east on the Ranch-Ft. Myers cir-cuits is found to be 595 MW. From past history of the division of load, the MW load on the 240kV line is estimated at 420 MW.

The automatic logger of the West Palm Beach Supervisory recorded the following events:

10:08:29 Frequency declines 10:08:39 Ranch-Ft. Myers 240kV line exceeds amp limit of 959 amps 10:09:24 Ranch-Ft. Myers 240kV line exceeds MW limit of 418 MW 10:09:39 Ranch-Ft. Myers 240kV line exceeds Var limit of 147 10:09:54 Ranch-Ft. Myers 240kV line watts normal (less than 418 MW) 10:09:54 Ranch-Ft. Myers 240kV line Vars normal (less than 147 MVAR) 10:10:09 Ranch-Ft. Myers 240kV line exceeds watt limit 10:.10:39 Ranch-Ft. Myers 240kV line exceeds Var limit 10:10:49 Frequency normal 10:16:24 Ranch-Ft. Myers 240kV line Vars normal 10:24:01 Ranch-Ft. Myers 240kV line opens The oscillatory nature of the alarms tend to indicate that the loading was near the alarm set points. Xt can be con-cluded from the above that, at the time of tripping, the line load was in excess of 418 MW and less than 147 MVAR.

The Fort Myers-Ranch line tripped at both ends with a ground pilot target at Ranch and a Zone 1 and ground instantaneous targets at Fort Myers. Broward, Midway and Ringling oscillo-graphs recorded a phase-to-ground fault at this time. The Ringling oscillogram indicated a "B" phase-to-ground fault.

The attached oscillogram from Ringling shows a discrete step

change in current, indicating a fault rather than an over-current. The oscillograph is a 32 channel machine, but due to play back limitations, the output is printed on three separate pages.

The following attachments are included to document the data and conclusions:

Charts of tie flows Charts of generation of FMl, FM2, MTl Charts of frequency at Ft. Myers (to show high frequency following'he tripping and explain the load rejection of the plants). Oscillogram from Ringling which shows that the system was not swinging wildly but relatively stable following the fault.

A simplified schematic of the central portion of the FPL system to facilitate following the events.

1.7 Not available.

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QUESTION 2 Please provide the following'nformation: 2.1 If the line Ranch, likelihood of a causal relation between the Ft. relaying and the Turkey Point, Unit 3 scram Myers-were conceded, would FPL continue to represent that the two events constituted a double rather than a single contingency? 2.2 Provide a discussion of the bases for your response to Item 2.1. RESPONSE 2 If line a hypothetical causal relation between the Ft. Myers-Ranch relaying and the Turkey Point Unit 3 trip were assumed, it would appear, by definition, that this would constitute a single contingency under Classification Type 1 of ANSI N41.2, Section 5.1. FPL, however, does not concede the likelihood of such a relation. There have been Turkey Point unit. trips in the past 'and they have never led to the loss of a transmission line. Similarly, the available data from the May 16, 1977 disturbance show that the Ft. Myers-Ranch line did not relay because of an overload condition caused by the Turkey Point Unit 3 trip. The fact that these two events occurred approximately 16 minutes apart is additional indication of their independence. We have concluded that the Turkey Point trip could not, by itself, have caused the line to relay. Numerous contingencies with respect to the condition of the power grid would have to be assumed. in order to "create" the hypothetical "worst case" situation in which a causal relation between the events would become at most a remote possibility. The fact remains that during the May 16 distur-bance, there were two distinct malfunctions; (1) the loss of Turkey Point Unit 3 caused by a defective auxiliary relay, and (2) the loss of the Ft. Myers-Ranch 240kV line caused by a fault to ground from an undetermined origin.
QUESTION 3 What studies were made to determine the condition of the system with the outage of Turkey Point Unit 4 and the 500kV'.line prior to the shutdown of these two facilities? Specifically, 3.1 What information did the studies provide relative to stability limits and other system limitations? 3.2 If the studies were not made, why not? 3.3 If they were made and did not show the vulnerability of the system to a failure, why did they not? 3.4 If they were made and did show the system vulnerable to a failure, what precautionary measures were adopted? RESPONSE 3 Florida Power & Light Company conducts transient stability studies I as part of the Florida Electric Power Coordinating Group (FCG) in order to assess the effects of the various contingencies listed in SERC Guideline Number 3, "Criteria for Reliability in System Planning." System Operations maintains and uses a current load flow model., System Planning has also just implemented an in-house stability program. However, these are batch programs run on corporate computer facilities and turn-around times of 24-48 hours are not uncommon. Therefore, while these are helpful for short-range contingency planning,'hey offer little or no benefit under emergency conditions. Installation of the System Control Center in 1978 will provide capability for real-time load flows, contingency planning and security analysis. A status report of the referenced 1973 report of FPL's consul-tant to the Public Service Commission is attached and will be referenced again in the response to paragraph 6. The latest FCG study, "Off-Peak Transient Stability Study for 1977," considered the loss of Turkey Point Unit 4 with a frag-mented system. This fragmented transmission system simulated the simultaneous removal of three major circuits: the 500kV Andytown Orange River circuit (FPL), the Midway Indiantown 230kV circuit (FPL), and the Central Florida Clermont East 230kV circuit (FPC) . System recovery was normal and no load shedding or relay action was observed. There was no reason to believe that the system. could not be operated satisfactorily under the May 16, 1977 conditions. In any such tests several key points are examined. These include: did any generator pull out of synchronism, did transmission lines relay, and was any customer load shed? Indeed, from the events of May 16, 1977, we know that at 10:08 a.m.
following the sudden loss of Turkey Point Unit 3, no generator pulled out of synchronism, no transmission lines relayed, and no customer load was shed. The stability tests made did not show the system vulnerable to a failure. The sense of paragraph 3 appears to assume that long-term dynamic stability programs are available to allow simulation of the probable status of a system for l0, 15, or 20 minutes of real-time, following a disturbance. The fact is that no such program or programs are currently available. FPL, with others, is cooperating with EPRI and General Electric in the development of such a program.
JY/7-1-77 1 of 4 REPORT A
'F STONE STATUS OF RECOMMENDATIONS & WEBSTER ENGINEERING CORPORATION ON FPL ELECTRIC POWER SYSTEM DISTURBANCES APRIL 3 AND 4, 1973 (FROM STONE & WEBSTER REPORT TO FPSC)
As a result of'ur findings, toe make the following recommendations: 2.'s long as the PEorida companies must trip units auto-maticaEly on underfrequency, ZPL should revise .the zeEay schemes so hat each set of relays trips onEy one unit unless the total amount of'eneration to be tripped by one set of reEays is Eess than 250 MV. Individual underfrequency relay schemes are .installed on each generating unit of 250 MR or more, except Putnam. At Putnam one relay scheme encompasses both Putnam Units 1 and 2.
~~2. Each scheme as a minimum should have tao reEays both set to pick up at '58 cycEes, neith their contacts in series so that both must operate to trip the uni t.~~
A FPL selected a scheme comprising parallel sets of two relays with their contacts in series to provide both security and reliability. All generators in peninsular Florida (or tie lines on some neighboring systems) are set to trip at 58 hertz after a 12 second time delay except for FPL's area east of Ft. Myers and south of Midway where settings are 57 hertz (this includes St.'ucie Unit 1) .
~~3. Consideration shouEd be given to adding out of st'ep reEays to 225 kY, 2'38 kV, and 240 kV circuits to block zeclosing on tzips due to stability svings.~~
As a result of studies by Stone & Webster and. FPL engineers, it was. decided to add equipment to sense out of step condi-tions and block reclosing following trip due to stability swings. Approximately forty 240 kV and 138 kV line terminals con-sidered to be most likely to be affected by stability swings have had this equipment added to them. As new terminals are added, consideration is given as to whether they should also have this type of protection included.
~~~ '~~
of 4 On the basis of further studies by Stone a Webster and FPL, the practice of blocking high-speed redlosing, following Zone 1 trip was adopted for all 240 kV lines south of Ranch Substation, and the 138 kV lines at the respective substations with 240 kV. This has been completed. A decision was reached recently to extend this blocking practice to the remainder of the trans-mission system. This would include all 240 kV line terminals, 138 kV line terminals at 240/138 kV substa-tions, and 115 kV line terminals at 240/115 kV substa-tions.
4. ZPS should thoroughZy review its relaying phiZosophy and protective schemes to ensure that this important pazt of its system design provides. the highest possibZe degree of zeliabiEity and security. I An e'xtensive review of FPL current practices was con-ducted by Stone & Webster and FPL engineers. Results were published February 22, 1974 and adopted. While there was'o wholesale retrofit, except as mentioned above, all new installations and the old ones rebuilt follow the new philosophy,.
Provisi'on shouZd be made to establish and maintain digital load floe and stabiZity modeEs of These 0he PZorida. systems repz esenting current conditions. models mould provide day-to-day information to the oper'ators on stabiZity limits and othez'ystem Eimitations impos'ed by construction deZays or equipment outages. 't System Operations maintains and uses a current load flow model. System Planning has also just implemented an in-house stability program. However, these are batch programs run on corporate computer facilities and turn around times of 24-'48 hours are not uncommon. Therefore, while these are helpful for short range contingency planning, they offer little or no benefit in emergency conditions. Installation of the System Control Center in 1978 will provide capability for real time load flows, contingency planning and security analysis.
~~6. StabiZity and load floe studies should be conducted for 2974 and 2975 conditions to check the effectiveness of corrective measures such as adaitionaE load shedding, f~~
b'locking of recEosing, and othez aspects o Zine relaying and system design. Stone G Webster was retained to conduct studies of 1974 and 1975. Analysis of these studies together with studies conducted by FPL provided operating guidelines for 1974 and.1975;
3 of 4
~~7. These studies shouEd incEude off-peak as veZZ as peak Eoad condi tions.~~
~~(See respon'se to number 6.)~~
8. ZPL should continue to put a high priority on transmission additions to strengthen ties between t'e southern area and the rest of.the PZorida systems. Construction of trans-mission lines in southern FZorida has been deZayed by environmental considerations and labor problems. Any further delays viZZ affect the,reEiability of the ZPL system.
FPL has continued to place a high priority on the expansion of its bulk transmission facilities with the major addi-tions from 1973 to date as follows: Placed In Service Durin 1973 Ft. Myers Ringling 52, 240 kV Ringling Tampa (TEC) g2, 240 kV Sanford North Longwood (FPC) 240 kV Placed In Service Durin 1974 Midway St. L'ucie 240 kV Broward Lauderdale 02, 240 kV Broward Ranch, g2, 240 kV Ft. Myers - Lauderdale 240'kV Bradford Normandy (JEA) 240 .kV
~~. Bradford Palatka .240 kV Placed In Service Durin 1975 Ringling Tampa 52, 240 kV* (th u Manatee)~~
Placed In Service Durin 1976. Dade Turkey Point 240 kV Dade Lauderdale 240 kV Davis Flagami 240 kV ~ Circuit rearrangement Flagami Lauderdale 240 kV Baldwin Duval 240 kV Ringling Manatee 52, 240 kV Bradford -'Duval 240 kV Plagami Miami 52, 240 kV h Placed In Service Durin 1977 to Date Pt. Myers - Orange River 51 & "2, 240 kV Andytown Orange River 500 kV (Converted from 240 kV) Andytown. Broward 240 kV Andytown Lauderdale 240 kV (2 circuits) Ranch Pratt & Whitney 51 & 52, 240 kV (Increase Capacity) Midway - Pratt & Whitney >1 & I2, 240 kV (Increase Capacity)
4'of 4
~
A strong 500 kV system with ties to Georgia, tuhich is nor in the pEanning stages shouZd be pursued uiCh'ue regard to development of proper systems within ZZorida and Georgia in conjunction iuith interstate ties.. A strong 500 kV system has been a part of FPL's plans for 10 years. A 500 kV system was reported in the 1968 National Power (1968 through 1990) by FPL. This included 500,kV 'urvey from Miami to Ft. Myers to Sarasota, plus 500 kV from Miami to Midway to Brevard to Bunnell. A joint study was made in 1972 by 'the Planning Subcommittee of the Florida Operating Committee. which confirmed a coordinated 500 kV statewide expansion program through 1990. I The statewide 500 kV system is being reported annually to the Federal Power Commission under Order 383-4 (SERC-TAC) . The 1971 filing indicated .a 500 kV system from'urkey Point to the Georgia line, tentatively by 1980. In 1975, an additional joint study by the FCG Planning Committee through 1995 was made to determine effects of changing load conditions and altered generation expansion plans. The 500 kV system completion need to the Georgia
~~- line from South Florida was shown to be 1986.~~
10. Discussions between Southern Company. and the ZZorida companies concerning additionaZ 240.kV interstate ties should be given 'urgent priority vith the objective of increasing the emergency interchange capabi,lity to ZZorida from Southern Company to at Zeast 800 MP by 2976. This would aEEov. loss of the largest unit without causing isolation of Peninsular Zlorida. The addition of these 240 kV Zines shouEd be. considered an interim measure and shouEd not aff'ect t'e Eonger range pEans for'00 kV ties.
Negotiations with Georgia Power Company are continuing for a 240 kV transmission tie to be in service in the summer, of 1980. Tentative agreement has been reached. FPL has authorized piojects for'he timely completion of this interconnection.
QUESTION 4 Please provide the following information: 4.1 The frequency versus time information at the Turkey Point bus and at the St. Lucie bus at least to tenth of a second accuracy for the ten second period following the scram of each reactor; and 4.2 The same information requested in (4.1) including MW pro-duction versus time and MVAR production versus time at the Turkey Point bus and the St. Lucie bus for the time period 10:08 to 10:24, and shortly before 10:08. This information may be provided on a coarser scale. RESPONSE 4 The continuous high speed recorder installed at Turkey Point records bus frequency. Since other parameters are related to generator output, only bus frequency can be provided. No equivalent recording equipment is installed at the St. Lucie Plant. The following tabulation indicates frequency on the Turkey Point bus to which the nuclear units are connected. The time is in seconds after the reactor trip. Frequency i:s in Hertz. Time Fre uenc Time Fre uenc 60.00 6 59.60 59.78 7 59.54 59.72 8 59.70 59.78 9 59.72 59.66 10 59.72 59.60 The following tabulation indicates frequency on the Turkey Point bus to which the nuclear units are connected. The time is in minutes after the reactor trip. Frequency is in Hertz. Time Frecruenc Time 60.00 8 59.96 59.94 9 60.00 59.76 10 59.99 59.82 11 59.98 59.81 12 59.97 59.83 13 59.96 60.00 14 60.00 59.98 15 60.00
Charts of switchyard voltage vs. time for Turkey Point and St. Lucie are attached.
I U I
~~,I 4 g~~
E. Qt r+ l J
1)0
,30@I 30 30 300 pp~ ~:t 0~ O.g. 250
~~~ rff fuff IW ~ A Ol I T~~
~~l d. ~, ~ '~~
]
~~1 I 2 0-igt>l-I 0 'I ' l lI0 T~~
~~~ ~ ~fr ~~~
I I. KX- l I I' "P ~ ' 0 7 I.O 0
~~- ~ . ~ .I r... ~~~
~~t= ~' I 'I~~
~
~~C' I~~
~~.'l 0> ~-100 m~~ ~~~
~~IORIWSW I g$ tlat" ": .Rial'II>!iot 60~ I\' ~ JlEC-885 r~~
.....Ilif::i.'.~. "Qgg@~ l ~ 1 ~
~~Cc"t- Jr 0 RPI51 " IIIIIIlip feIIfl+vtlt 'I~~
~~~ I jdlqa agCil I ~~~
~~0 . 212hOOG Cl OFAPIIIC CONTACT COI!IIOOWIOII 'OIIfBOO, IItV/YOIIII r!f!II!CO III II. S.A l~~
~,
~~I f, ~ I~~
* ~
l QUESTION 5 Provide the following information: 5.1 A clear definition of FPL's system requirements on spinning reserves, distinguishing between tie-line imports and spinning reserves; and 5.2 A copy of the guidelines established by the Operating Committee of the Florida Electric Power Coordinating Group relating to practices and procedures on spinning reserves, load shedding, and emergency operating procedures. RESPONSE 5 FPL's system requirements on spinning reserves are defined by Section III reserve of the FCG Operating Committee Handbook. The requirements established by this section are spinning conservative with respect to NAPSIC Operating Guide No. 10 for Integrated Systems. One copy each of Section are III and VII of the FCG Operating attached. These'sections cover spinning Committee Handbook reserves, load shedding and emergency operating procedures.
FCG OPERATING CONNITTEE HANDBOOK
III-1 10/14/76 DAILY OPERATING. RESERVE Daily Operating Reserve is that amount of generating capa-bility and/or equivalent load relief in excess of fore-casted daily peak. load which is avail'able to provide. for . load variation and forecast errorI frequency regulation, area protection and contingencies such as loss of genera-ting capability. It consists of the following components: A. S innin Reserve The term "Spinning Reserve" . when used herein means the',reserve generating capability connected to the bus; ready to pick up load immediately, and capable of becoming fully applicable with a frequency decline to 59.5 Hz. (Xt is recognized that this definition of Spinning Reserve differs from that of the' Z.E E.E. ) (1) Steam Unit Due to special operating conditions in.. Florida, no more than 16;2/3% 'eninsular of the Continuous Capability of a steam unit mey 'be counted in computing tEe system Spinning Reserve. (2) Combustion Turbine Unit (a ) A portion, generally 30%,'f the base rating of combustion turbine genera-ting units may.be counted as Spinning
~ .Reserve, provided, 1) the units are operating in'-their automatic control mode, 2) the units are equipped with solid-state underfrequency relays in their ramp rate control circuits to change their response rate to emer-gency, 3) tests have been made to demonstrate that such amount counted will respond and become fully applicable with a frequency decline to 59.5 Hz, and. 4) unit response is equal to, or faster than, the same amount of steam unit capacity as defined above.
~~III-2 10/14/76 I~~
'oad capacity (b) The between base and peak of combustion turbine units may be counted as Spinning Reserve pro-vided, 1) the units are equipped with solid-state underfrequency relays which will automatically change the operating mode from "base" to "peak" when the frequency declines to 59.g.
Hz, and 2) unit response is equal to or faster than the same amount oz ' steam capacity as defined above ." Since contractually interruptible load, when is interrupted, releases generating. capacity it that is instantly available, a participant may place such load on underfrequency relay control and count the amount of. this load so placed as Spinning'eserve up to 75%,'of his allocation. Solid-state relays will.be employed for this application in order'to minimize time deIay. They will be set .to disconnect the interrupt-ible load at 59.7'z. Use of this provision by
~~a. participant in no way changeshis responsi-bility to provide his share of Spinning Reserve in an emergency. Interruptible loads which are utilized as part of the Operating Reserve cannot .~~
~~be counted as, part of the load shedding obliga-~~
=
tion.'. Su lemental Reserve The term Supplemental Reserve when used herein means any generating capability and/or load relief measure which can be made fully applicable within 30 minutes or less. It includes, but is not limited to diesel units, combustion turbines, interruptible loads, load relief measures, and any increase in gen-eration that may be obtained from a generating unit.
2. In normal operation the Daily Operating Reserve should be main~minM by the'combined systems. at.a value equal to, or greater than, the sum of the Peak Capability ratings of the two'largest generating units. in service.
Spinning Reserve should be maintained equal to, or greater than, the Peak Capability rating af the largest generating unit in service to allow the combined systems to recover in an orcrerly manner from the instantaneous loss of such largest unit; - The balance of the Daily
III-3 10/14/76 Operating Reserve will be Supplemental Reserve. Follow-ing the loss of a generating unit, Supplemental Reserve should be converted to Spinning Reserve, if required to restore the recommended level of Spinning Reserve. 3 ~ The Daily Operating Reserve and the Spinning Reserve.. requirements, (the minimum values specified in Para-:
~
graph 2), should be allocated'mong .the participants in proportion to each participant's maximum demand for the preceding year and the Peak Capability of his largest-- unit.. Fifty percent. should be allocated on the basis of demand and 50% on the basis of the Peak Capability the largest unit..'See current calculation"on
-'f 5 in this section.) 'age 4 The Daily Operating Reserve 'requirement and an equitable allocation among the participants will be a continuing interest-of the FCG Operating Committee. A new allo'ca-.
~~tion will be calculated and used when a participant's single largest unit is off line.~~
5. The effect on a'participant's ability to maintain his Spinning Reserve allocation should be fully considered before agreeing .to sell power to another participant.

6. Protection of a new unit during shakedown will be the responsibility of the owner'.

7. Each participant's Daily Operating Reserve allocation should be available to the other participants and not be restricted by transformer,'line or other limitations.

8. Each participant's Spinning Reserve allocation must be distributed on. enough generating units with proper governor characteristics, so that it will not take a frequency drop in excess of 0.5 Hz to realize the full benefits of each participant's Spinning Reserve. Assum-ing 5% governors, this means that the Spinning Reserve assigned tc any one unit should be no more than 16-2/3%
~~of the Continuous Capability of that unit.~~
9. Reliable operation of the combined systems requires that each participant's dispatcher know at all times the Con-tinuous Capability rating of his generating units. Par-tic'ularly du ing periods when forecasts indicate close operating reserves,'he Continuous Capability rating of all questionable. units should be verifiedbefore by having these units demonstrate this capability the time of the expected peak for. the day.
III-4 10/14/76 It shouldon betherecognized Resezve combined that a deficj.ency in Spinning systems subjects all partici-pants'..customers to a risk of interruption due to under-frequency relay operation. In abnormal situations where the Daily Operating Reserve and/or Spinning Reserve of a participant is less than his allocation, such participant will notify the full details of his operating condition, so that -. others,,'iving they may determine what assistance they can make avail-.. ~ be utilized. The deficient participant, should 'ble.to take such measures that are available to him to safeguard the reliability of the combined systems. This would include: 1) purchase from other systems, 2) interrup-ting some of his own load, or 3) installation of under-fzequency relays set to'trip at 59.7 Hz, an amount of load equal to the participant's shortage "in his Spinning Reserve allocation. Measure 3), known as Step Zero (Step 0), is to be used only in extreme emergencies where no'ther alternative is available'and solid-state .relays will be employedso to minimizeshould time delay. (If Step 0 is used, the load assigned not result in a reduc-tion in a system's proper share of the automatic load shedding obligation described in Section XI, Paragraph 1.) Deficiencies in Supplemental Reserve should be covered by purchase i.'f feasible. Administzation of the Daily Operating Reserve and Spinning Reserve formula is the responsibility of- the Florida Power'Corporation. To carry out this responsibility certain information is necessary from each of the par-ticipating systems. Th's information is: A. By January 15th the. previous year's peak. load and the Peak Capability of the largest 'unit.
~~'I B. Immediate- notification of a change in rated capability of a system's largest unit.~~
C .NotiQcation when a system's largest. unit is service. .'ut.'of Daily Operating and Spinning Reserve will be calcul-I'he ated at least yearly and re-calculated as necessitated by information received from a participating system. Hhen re-calculation is necessary, the new values will be placed on the teletype for the dispatchers'mmediate use and a copy of the calculation will be mailed to each of the systems. (See following page for current calcul-ation with largest unit in each system in service.)
I ~~ IZZ-5 10/14/76 DAILY OPERATING AND SPINNING RaSEHVE ALLdCATIUNS BOTH TURKEY POINT NUCLEAR UNITS ON LINE EFFECTIVE AS QFt 5- 3-76 CAPABI LITY PERCENT 'ERCENT OF LARGEST BASED 8ASEQ QN PEAK LOAD GHQSS 'f6 UNIT GIIQSS Ni ON PEAK LOAD
~~'N f LARGI=ST I~~
~~FLORIDA POI'(ER A LIGHT COMPANY 7400 0 722 0 ~~~
~~50. 19 e 27.96~ .~~
FLQR I DA PQr'IER COrrPQRA1 ION 3370. 0 527. 0 ', 22. 86~ 20 ~ 41.0 TAMPA ELECTII IC CQWPAc(Y 1660 0 350. 0 I I ~ 26~ 13'5o~ JAC<SUrIV I LLE ELFCTH IC AUTIIQRI TY I 136. 0 275 ~ 0 7 ~ 70~ 10.o5 QRL 4tI DO UT I LIT I ES CQ'< r> I SS I QN 41'3. 0 327. 0 2 ~ 80.o 12 ~ oo~ CI'TY UF TALLAPASSFE 223 0 75. 0 1.51.~ 93~+ CI fY. OF LAKELAt(0 218. 0 115.0 1.48~ 4 ~ 4i,~ CITY OF GAINESVILLE CITY UF FURT PIFRCF. CITY UF. LAKE e'lQA'ffl 155 0 59.0 54 .0 85.0 38 0 35.0 1.05~ 0 40.~
~~0. 37.~~
~~'.4ti3.29 I . 3o~~~
~~CITY JF YERQ BEACH 56-0" 33 0 0.'38 o I 2d~ ~ r~~
~
TOTAL I 4744 0 2582 ' I 00 ~ 00~ 197 ~ QU, RESERVE QPERATIWQ SPI Nr< ING SUPPLEIAEA CAL Al'LOCA1 IU.'< RESET VF RLSERYE RESERVE PE HCENTAGE <Ih JAA I'eA FLQR.IDA PPiEH 8 LIGHT CO~IPANY 39.08 564. 282 282 FLORIDA POI')EH CUhPQHATIQN 21.63 312 156 156 TAMPA ELECTRIC CU'.IPA)IY 12.~1 '179 90 90 JAL,KSrJNVI LLE ELECTRIC 4UTHOI)ITY 9. 18 I 33 66 . 6o URLRrIDO UTILITIFS Cu>>EMISSION 7 ~ 73 112 56 i6 CITY QF TALLAHASSEE 2 21 32 16 16.
~~'I ~~~
CITY rJF LAKFLAND 2.97 43- 21 21 CITY UF GAINESVILLE 2 31 16 16 CITY QF FiJRT PIFRCE 0 94 14 7 7 CITY OF LAKE nORTH 0. 86 12 ' 6 0 f C I Y QF VETO BEACH 0 F 83 12 ~ 6 TOTAI 'I CQ; GO I ~m 722 722 DATE CALCULATED~ 5- 2-76
VXX-1 10/14/76 EMERGENCY PROCEDURES eration Durin Declinin S stem Frecuenc The reliability of bulk power supply within peninsular Florida is a matter of vital concern to the electric utilities serving require the area. Conditions of declining a coordinated orogram of emergency system frequency procedures. This section outlines a coordinated program to which the members of the FCG Operating Committee volun-tarily subscribe. The individual utilities serving the peninsular Florida area are committed to the design and operation of an ,interconnected network within peninsular Florida which will not be subject to widespread systemover outages as a consequence of a major disturbance and the years have developed guidelines for its safe and reliable operation. Regardless of these objectives and practices, emergency procedures are required to meet conditions such as system separation and operation at subnormal'requency. Coordination of emergency procedures, which include load shedding and power plant isolation, is essential. Xn-the event of a sudden serious emergency, load shedding is used to:
~~~ ~~~
A.. Restore the balance between load and generation in the affected area i.n the shortest possible time and permit the subsequent return to 60 Hz operation, 'so as to minimiz'e adverse effects on customer service. B. Minimize the risk of damage to company and customer facilities and equipment. Xt is recognized that the ability to reduce firm customer load in an eztreme emergency is not a substitute for proper design and good'oper'ation. Xt is a measure,to be taken
~~.only after the system has suffered an erne gency condition which may otherwise lead to widespread system outages.,~~
VII-2 10/14/76 Emer encv Procedures Durin Declinin S stem Precuenc Emergency procedures will be implemented as follows: Phase 1: Prom 60.0 Hz to 59.2 Hz, all operating reserves and emergency measures should be. utilized to the fullest practicable extent. The manner of utilization of these reserves will depend greatly on the behavior of the system during the emergency. Zn cases where frequency declines rapidly, only that capacity on 1'ine"and automatically responsive to frequency (spinning reserve), and such items as interconnection assistance, and load reductions by automatic. means are of assistance in arresting the dec3:ine in frequency. Zf the'requency decline is gradual, the system dispatcher (s) of the system (s) in trouble should invoke non-automatic emergency procedures. This: would include the starting of gas turbines, interrupting load, puzchasing power, etc. These efforts'hould continue until the frequency decline is arrested. Generally speaking, it is the responsibility of the system(s) in trouble
.. to take whatever action is necessary to restore the, frequency to 60 Hz, and the system dispatcher(s) =of such system(s) should take the lead'n. taking positive 'action, describing the trouble, asking for assistance, etc. .If his actions do not pzoduce results fast enough, the other system dispatchers may have to apply their judgements in assessing a given situation, -taking action,.
and/or rendering assistance, without being. requested. No hard and fast rules can be made except that all possible cooperation and communications between system dispatchers will be required. lf interruptible loads are counted as spinning reserves they should be capable of being disconnected from the system by underfrequency relays to assure their removal prior to Phase 2; Phase 2: Between 59.2 and 59.0 Hz inclusive, shed with II automatic load shedding relays not less than 10 percent of system load. No intentional time delay should be used beyond that absoiutely re-quired to avoid improper relay operation.
VXI-3 . 10/14/76 I 8 phase 3: Between 58.8 and 58.7 Hz inclusive, shed additiona3. load. with automatic load shedding relays in an
~~'mount not less than 10 percent of. system'oad sting prior to Phase 2.. This amount of load shpuld be shed 'in two nearly cpu'al, steps 'at'~~
~~. >l I l~~
~~... -,='." '.5Q..8 pnd 58.7 Hz.. No intentional time delay I ~~~
~~'.'s~uld'be used. beyond that,'-absolutely"raquuired tj avoid ~~~
~~,:'f improper rel'ay. operation. ',~~
~~~ . 'Phase' ~.- Be%can 58. G.mg'58.5 Hz 'inclusive',. shid.pdditipny,l~~
~~p,'.goad with automatic load she'dding"r'clays .in an~~
.."amount not less'han 10 percent of ':thy'ystem "'load existmg prior 'to Phase 2. This amount at: 58.6 and 58.5 H . 'o of.'oad should be shad in"two nearly equal steps intentional. time. delay should be used beyond'hat absolutely required:
~~to'void. ipproper'elay operation.~~
~~\ ~~~
r
~~." 'IMPORTANT NOTE l'~~
~~PHASE 2i 3 AND' RILL HAVE;BEEN ACCOMPLISHED AUTOMATICALLY. T~T~~
'T THIS POXNT-THE DXSPATCHERS MUST RECOGNIZE QXME XS RUING OUT AND THAR 7 MINUTES OR LESS TOTAL ELAPSED TIME . XS- ALLOWED FOR'PERATION AT FREQUENCIES BETWEEN 58.'5 HK AND 58,0 Hz EVERY 'EFFORT MUST BE MADE TO (1) ARREST THE.
~~FREQUENCY DECLINE TO PREVENT THE GENERATORS FROM BEING .~~
~ 'AUTOMATICALLYISOLATED AT 58.0 Hz, AND (2) TO RETURN THE FREQUENCY TQ ABOVE 58.5 Hz TO PREVENT THE GENERATORS PROM BEING TPZPPED A'T THE END QF 7 MINUTES ELAPSED TXME IF OPERATION CONTINUES ZN THE RANGE 58.5 Hz 58.0 Hz ~
I
~~, Phase 5:~~
~~gt 58. 5 Hz, if frequency is declining,, take any action which can be taken at this point to~~
.arrest. frequency decline. This ~ma include additional load shedding, manual or automatic, and coordinated network separation.-. This section shall be, completed before frequency declines 58.0 Hz.
4
~~'hase At 58.0 Hz, isolate generating units in accordance 6: 'ith Paragraph 2 Power 'Plants from System".~~
~~of this Section, "Isolation of In the event it becomes necessary for a syst m to isolate a generating unit at a frequency higher than 58.0~~
.Hz,'or in a time period shorter than stipulated in the schedule of Paragraph 2, page 5, of this Section, such system shall also simultaneously disconnect. an amount of load equal to,that. parti- 'ular generating unit's output. This amount sha13.
VXI-4 10/14/76 be an additional amount over any- load previously shed. Automatic isolation of generating units is to be .preferred over manual isolation, and employed should provide'2 seconds time delay if to permit temporary frequency excursions below this isolation frequency of 58.0 Hz. Phase 7: lf at any point in the above procedure, the in area frequency is arrested and it levels decline out between 58.0 Hz and 59.0 Hz, the systems in the low-frequency .area shall shed. an additional 10 percent of their remaining load and shall'-. maintain or increase, if possible, their generat-ing output to a value corresponding to the. full open .control valve position until frequency is restored to synchronizing range of the main network. Phase 8: Xf after three minutes the action taken in Phase 7 above has not returned area frequency '-to 59.0 Hz
.or above, the systems in the low frequency area shall. shed an additional 10 percent of their, remaining load, repeating on two-minute intervals until 59.0 Hz is reached. This step must be compl'eted within the time limits outlined in Paragraph 2 of this Section, "Xsolati'on of Power Plants from System"..
Phase 9: When area'fzequency has been established at 59.0 Hz or above, the system or systems in the low frequency area shall take any action necessary to permit re-synchronization of the isolated area to the main network. Phase 10: After frequency has returned to synchronizing range,.the isolated area shall be synchronized with the .interconnected systems. Phase 11: System dispatchers shall direct load restoration and. the resumption of normal intexconnected operation. ln taking the steps outlined the PCG Operating Committee . members will utilize all'eserves to the best of their abilities.'he application of all emergency measures during declining system frequency'ithin peninsular Florida should be re-viewed on a regular'.basis and updated.-as required to meet changing system'onditions.
VII-5 10/14/7 6
2. Isolation of Power Plants From S stem Serious damage to turbines can be caused by loaded opera-tion at subnormal speed. It is highly desiz'able to, maintain service continuity, but it would be mast imprudent to allow equipment to suffer major damage which would impede the restoration of service .after a major distuzbance.
To.minimize the possibility of damage to equipment and. still maintain reliable operation of generating plants, coordination of emergency. procedures during low frequency operation is essential. Pro ram'for Isolation of Generatin Units Durin Low S stem Generating units shall be isolated'rom the system when all of the 'procedures performed by the system dispatchers in accordance with Paragraph 1 of this'ection, ".Operation
~~'nDuring Declining System Frequency", have been unsuccessful returning system frequency to 59 Hz or above.~~
Isolation will be accomplished automatically or manually within the following time limits. The time periods and frequencies allowed are designed to .assure that all possible opportunity is given for the system to yet protect the generating units from damage. .Adjust-recover'nd ments. of the times and frequencies stated may be necessary for specific units due to the cumulative effect of:blade fatigue over the life of the turbine, or to conform with manuf act'mer' limitations. 60.0 to 59.0 Hz No isolation Below 59. O'z 30.0 minutes maximum time before unit isolation .. Below 58. 5 Hz 7.0 minutes maximum time before "unit. isolation" Below 58. 0 Hz 'Automatic isolation by underfre-quency.relay with 12 seconds time delay
*This 7 minutes is part. of the total time of 30 minutes allowed below 59. 0 Hz.
ivery effort should. be made by the operator to maintain unit auxiliaries and, if possible, a local load. This is to allow rapid re-synchronizing of the unit to the main network to aid in restoration of the. system.
VZZ-6 10/14/76
~~3. .Procedures for Orderl Recover After S stem Disturbance Condition Z Loss of Unit or Plant Without Separating From The Enterconnected Systems (No Frequency Drop)~~
S stem En Trouble After emergency is recognized and, immediate generation change has been made, request necessary power require-ments from other systems. Hake frequent checks to assure that'equests equal net power on all ties with other, systems. S stems Not Zn Trouble Fulfill requests made by the system in trouble. if Florida necessary, will Power Corporation system dispatcher, contact the other systems to be sure that the schedules are in balance. Condition ZZ - Loss of Unit With Resultant Separation From The Znterconnected Systems All S stems With frequency below 59.5 Hz, plants are to pick up load. without contacting their own system dispatcher until 59 5 Hz is reached, then return to control. (Systems using command or mandatory type control will remain on control). At this point all system dis-patchers will set schedules to the value of system net interchange. (All systems remain on tie line bias control ) Ef the frequency does not go below 59.5 Hz, all system dispatchers should set schedules equ'al to net interchange and remain on tie line bias control. S stem in Trouble Ef it is apparent that: there is insufficient generation available to restore the frequency to 60 Hz, it is the responsibility .of the system in trouble- to take whatever action is necessary to restore the frequency to 60 Hz After tying in 'with the interconnected
~~,systems, the system in trouble must contact the other systems to adjust schedules.~~
~
VII-7 10/14/76 Condition III - Loss Of Unit With Resultant Separation From The Interconnected Systems and Loss Of Load By Underfzequency'elay Action Generally load restoration should not be attempted until frequency has returned to normal and ties to the interconnected systems aze re-established. To prevent overloading of ties and a possible second separation from the interconnected systems, all load pickup should be coordinated with the .Florida Power Corporation system dispatcher. The system experiencing the generation lo'ss should not attempt to pick up load until the load of all other systems has been restored, unless-'otherwise instructed by Florida Power Corporation system dispatcher. As. in Condition II, if it is apparent that there is insufficient generation available to.restore the frequency to 60 Hz, it-is the responsibility of the system in trouble to take whatever action is necessary to restore the frequency to 60 Hz. Conditions I, II and III Following Any Major Disturbance
~ C To insure that schedules to the interconnected systems are held within limits, all system dispatchers should close communications with the Florida Power 'aintain Corporation system dispatcher until generation and tie fIows are stabilized.
~~4. '0 enin Ties After Statewide Loss of Generation Following a statewide total loss of generation (black-.~~
~~out), recovery will be expedited at prearranged points. if ties are.,opened In preparation for startup of individual systems,~~
~~. ties should be opened at the switching points listed on 'the following: page'.~~
~~For other situations where the blackout is not so extensive, opening of ties may be required to~~
~~,effect complete restoration.. Each situation .will have to be individually considered.~~
~~~ ~ i ~ 0 VIZ-8 10/14/76 Tie Lines FROM TO (Tie to be o enid at. this end)~~
~~. Pebbledale (TEC) West Lake Wales (FPC)~~
Ringling (FPL) Big Bend (TEC) Manatee (FPL) Big Bend (TEC) Lake Tarpon .(FPC) Sheldon Rd. (TEC) 2 Ckts. Double Branch (TEC) Higgins (FPC) Normally Open L'ake Wales (FPC) Orchid Springs (TEC) Ft. Meade (FPC) Pebbledale (TEC) 230 KV Pebbledale (TEC) Ft. Meade (FPC). 69 KV Arian a (TEC) Larsen (LAK) Sandhill (TEC) Highland. City (LAK) Florida Power Corp. (FPC) West (LAK) at 69 KV side breaker Brooksville (FPC) Dade City (TEC) Denham (FPC) Dade City (TEC) Sheldon Rd. (TEC) Denham (FPC)
~~. West..Lake Wales (FPC) Brevard (FPL)~~
Turner (F PC) l Sanford (FPL) North Longwood (FPC) S anf ord (FPL) Putnam (FPL) Greenland (JEA) Baldwi n (FPL) Normandy ( JEA) Bradford (FPL) Normandy ( JEA) Cage Canaveral (FPL) Indian River (OUC) Hartman (FPL) Substation 1 (FTP) South (VER) West (VER) by FPL Hypoluxo (FPL) Lake North Plant Sub (LWU) Rio Pinar (FPC) Substation 6 (OUC) Woodsmere (FPC) Substation 2 (OUC) Windermere (FPC) Substation 5 (OUC) Tallahassee Switch (FPC) Substation 3 (TAL) Crawfordville (FPC) Purdom (TAL) Bradfordville Nest (FPC) Substation 7 (TAL) Crawfordville (FPC) Hopkins (TAL) 230 KV. Archer (FPC) Parker Rd. (GVL) Gainesville (GVL) Idylwild (FPC)
QUESTION 6 Please provide the following information:
6. 1 What is the current status of the 500 kV system of inter-ties with Georgia which was in the planning stage according to the 1973 report' 6.2 Is there an emergency interchange capability of 800 NW from Georgia to Florida as projected for 1976?
6.3 Are the Georgia Florida interties emergency or economic in nature? 6.4 Are the ties set to open at such a (relatively) high fre-quency that they are of little use in a large disturbance (such as 1973, 1974, 1977) and that in a moderate distur-bance they might even make things worse by opening. when only a relatively small imbalance exists? 6.5 Furnish a description of the organization of Power Coordin-ators and Dispatchers which includes the following: a) The number of power coordinators and dispatchers for each shift; b) How they interact in emergency situations and with other utility power coordinators and dispatchers; and c) What telemetered data and what communications facilities are available to them--especially for communicating with quick-start facilities and with maintenance crews. RESPONSE 6
6. 1-6. 3 The growth of any dynamic system requires additions and changes. These changes involve transmission construc-tion, relaying practices and operating procedures and are designed to minimize the likelihood of an outage.
As a result of the April 3 and 4, 1973 outages, Florida Power a Light contracted with Stone 6 Webster Engineering Corporation to review the FPL power system reliability and to provide recommendations designed to improve it. Out of such recommendations and other internal studies, FPL has implemented numerous changes to our system since 1973. In brief, since 1973 transmission additions have strengthened the ties between the southern area and the rest of Florida. This includes an additional tie to Tampa Electric Company and new transmission lines down the west coast to Ft. Myers and across the Ever-glades to Lauderdale. The east coast transmission was strengthened by reinforcing old lines, adding new lines, and rearranging ci cuits from the Midway station sou he 'y
through Lauderdale and into the Miami area.. Two major additional interconnections with adjoining utilities were also established at Sanford (Florida Power Corporation) and at Bradford (Jacksonville Electric Authority). During this same time frame, additional generation was added at both Manatee and Ft. Myers. (See the status report attached, Item 8 for specif ics. ) Transmission expansion now under way and scheduled for completion by 1980, includes a 230kV tie to Georgia (this will increase the transfer into Florida to about 800 MW) and 500kV lines from Levee in the Miami area northerly through Andytown and Martin (the site for two new fossil generators) to Midway. These 500kV lines will closely tie the entire South Florida area from our St. Lucie Plant to Dade County into a strong, tightly integrated network with further improvement in system reliability. This system is scheduled for completion during 1980. A 500kV system'f ties with Georgia is still in the planning stage. The latest FCG study, conducted in 1975 to determine the effects of changing load conditions and altered genera-tion expansion plans, showed the 500kV tie to Georgia to be needed around the middle 1980's. realistic to assume that the Today, required date it seems more will be around the middle 1990's. The statewide 500kV system is being reported annually to the Federal Energy Regulatory Commission (FERC) under Order 383-4 (SERC-TAC). The existing Georgia-Florida transmission tie lines serve both economic and emergency purposes. The present ties are between Florida Power Corporation and Georgia Power Company, and their operations conform to the operating practices of those two companies. At present their transfer capacity is approximately 400 MW. 6.4 Florida Power Corporation's ties with the systems to the north are not equipped with underfrequency relays. Separa-tion of peninsular Florida usually occurs internal to the FPCorp. system, between Suwannee and Archer, Ft. White and Inglis, etc., but is not the result of low frequency. These lines are equipped with phase distance relays for .'fault protection which respond to the apparent impedance looking into the line terminal. This apparent impedance is a function of the current in the line, the voltage at the terminal, and the angular difference between these two quantities. In situations where the power transfer results in the proper combination. of high current and low voltage, operation of these relays is expected. During recent years these lines have demonstrated their ability to withstand moderate overloads (loss of 400 MW units).
6.5 With respect to organization, Power Coordinators operate the system under the direction of an Assistant Manager of System Operations. They direct the activities of the, Division Dispatchers. There are two Power Coordinators on each shift; one coordinates generation and one coordinates transmission. The generation Power Coordinator works with other utilities for interchange. The transmission Power Coordinator works with Division Dispatchers. Division Dispatchers for each shift are as follows: 7-3 11-7 Miami 3 3 1 West Palm Beach ' 1 1 Sanford 2 1 1 Punta Gorda 2 1 1 Telemetered data includes: Generation from each plant Tie. line loading Southern Company net interchange to Florida Power Corporation System Load Total Generation Net Xnterchange Frequency Power (South of Lauderdale) Power {South of Ranch) Voltage (Dade) Voltage (Flagami) Frequency {Brevard) Major Load Area Xnformation (generat'on load, interchange,
~~& net flow between adjacent major load areas)~~
Communication facilities are leased telephone circuits to all Division Dispatchers, all plants, and all other utilities with which- FPL has tie lines. Gas turbines are available for "quick start" by the Power Coordinators through superv'sory equipment. On May 16, 1977, undetermined number of gas turbines at Port Everglades were ordered on by supervisory. They were ordered on too late and were unable to complete the programed start-up sequence before the blackout.. Three gas turbines were ordered on at Lauderdale. These three completed the start-up sequence but the auto-synchronizer could not match the voltage of the machine to that of the bus and therefore would not permit. the breaker to close. The minimum ezcita-
tion limit of the gas turbine control would not permit the machine voltage to come down low enough to match the low bus voltage. The excitation limits on all GT's at Lauderdale and Port Everglades have been reset to permit them to synchronize at abnormally low voltages. Additionaly, main step-up power transformer taps have been reset to permit a higher machine voltage.
C' QUESTION 7 Please provide the following information: 7.1 Describe how, to what extent, and when the past recommenda-tions on relays were implemented? 7.2 What effect did that implementation have on the May 16, 1977 disturbance'? 7.3 Discuss the significance of the Turkey Point Unit 4 and the 500kV Orange River-Andytown line equipment outages to this event and explain why it is not necessary to include discussion of them in the "Report on System Disturbance May 16, 1977."
~~RESPONSE~~
7.1 Following the disturbances in April, 1973, Stone & Webster Engineering Corporation was retained to conduct an indepen-dent investigation. of the event. A report of their findings was forwarded to the FPSC on May 18, 1973. As a result of their findings, they made specific recommenda-tions as to protective relay application. All of these recommendations were accepted by FPL and have been imple-mented. Specif ically, they include: a) Individual underfrequency relay schemes are now installed on each generating unit of 250 MW or more. For this application FPL uses a design comprising parallel sets of two underfrequency'elays with their contacts in series. This provides reliability and security as well as limiting the amount of generation subject,to a common failure. b) Protective circuits on critical transmission terminals have equipment added to sense out of step power swing conditions and block reclosing following a trip. Approximately forty 240kV and 138kV line terminals con-sidered the most likely to be affected by stability swings are so modified. As new line terminals are constructed, consideration is given on an individual basis as to whether this type of protection is required. By so doing, FPL has limited the possibility of equip-ment damage or extending the area affected by an outage. c) High speed reclosing is blocked for all but phase to ground faults. on all 240kV lines south of Ranch Sub-station. On the basis of operating experience, this practice will be extended to include all 240kV lines and any 138kV or
115 kV lines originating from 240kV substations. d) An extensive review of FPL protective practices was conducted by Stone 6 Webster and FPL engineers. Results of this study were adopted in early 1974 and form the basis of current system protection and control design. 7.2 The disturbance of May. 16 was initiated by a phase to ground fault on the Ft. Myers-Ranch 240kV line. Protec-tive devices operated properly preventing the disturbance from spreading outside of the immediate area affected and allowing the safe shutdown of generating units without major damage. 7.3 The purpose. of the'eport was to address the disturbance and provide an analysis of those events directly related to it.
l gP' J}}

L-77-380, Response to Request for Additional Information System Disturbance

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Dear Mr. Lear:

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L-77-380, Response to Request for Additional Information System Disturbance

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Dear Mr. Lear:

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