NEPOOL Operating Procedure No. 19

 Transmission Operations

APPROVED:	July 22, 1998 by the NEPOOL Regional Market Operations Committee and the NEPOOL Regional Transmission Operations Committee to be implemented for the second Effective Date for Market Implementation.

REFERENCES:

1.	Reliability Standards for the New England Power Pool

2.	NPCC Basic Criteria for Design and Operation of Interconnected Power Systems

3.	NPCC Emergency Operation Criteria

4.	Capacity Rating Procedures - NEPOOL System Design Task Force

5.	Master/Satellite Procedure No. 2 - Abnormal Conditions Alert (M/S 2)

6.	NEPOOL Operating Procedure No. 4 - Action During a Capacity Deficiency (OP 4)

7.	NEPOOL Operating Procedure No. 7 - Action In an Emergency (OP 7)

8.	NEPOOL Operating Procedure No. 8 - Operating Reserve and Automatic Generation Control (OP 8)

9.	ISO New England Transmission Operating Guides

	TABLE OF CONTENTS

I.	INTRODUCTION	3

II.	RELIABILITY CRITERIA FOR TRANSMISSION OPERATIONS	3
A.	Normal Conditions	4
1.	Normal Criteria	4
2.	Normal Contingencies	5
3.	Normal Actions	6
B.	Emergency Conditions	8
1.	Emergency Criteria	8
2.	Emergency Contingencies	9
3.	Emergency Actions	9
C.	Post-Contingency  Operation	11

III.	TRANSMISSION SYSTEM ANALYSIS	11
A.	Scope of Analysis	11
B.	Classifying System Responses to Contingencies	12
1.	Contingencies Critical to Areas External to New England	12
2.	Contingencies Critical to Large Areas of New England or Bulk Power Transfers
	within New England	12
3.	Contingencies that Affect Small/Local Areas within New England	12
C.	Extreme Contingencies	13

APPENDICES:

A.	Methods and Criteria Overview
B.	Thermal Capacity Ratings for Transmission Facilities
C.	345 KV Stuck Breaker Contingencies That Can Have Unacceptable Inter-Area Impacts
D.	New England 345 KV Double Circuit Tower Lines
E.	Extreme Contingencies
F.	Summary of OP 19 - Transmission Operations
G.	Screening Method for Determining If a Stuck Breaker Contingency Has Unacceptable Inter-Area Impact
H.	General List of Dispatch Actions to Minimize Cost of Stuck Breaker Protection

I.	INTRODUCTION

This Operating Procedure describes reliability criteria for the analysis and operation of the New England bulk power transmission system.  The provisions contained herein are intended to be in accordance with the various Northeast Power Coordinating Council (NPCC) and New England Power Pool (NEPOOL) Operating Procedures listed as references for this document.  Prescribed operator actions are further detailed in several ISO New England Transmission Operating Guides.

The rules in this document are used to determine data, methods and limits for operation of the New England transmission system (69 KV and above).  The ISO and Satellites use these data, methods and limits to operate the transmission system in accordance with this procedure.

Appendix F contains a summary of OP 19 Transmission Operations Procedure.

II.	RELIABILITY CRITERIA FOR TRANSMISSION OPERATIONS

The New England transmission system is operated so that the most severe single contingency can be sustained without causing:

-  equipment damage due to thermal overload,
-  cascading thermal overloads,
-  excessively high or low voltage or voltage collapse,
-  unit or area instability,
-  undamped oscillations.

Any single contingency should not cause the loss of other critical facilities or portions of the bulk power system.  Single contingencies within New England should not result in violation of neighboring Areas' operating reliability criteria.

Two levels of transmission reliability are prescribed and define the condition of the bulk power system.  During NORMAL (non-stressed) Conditions, the higher level of prescribed reliability is maintained.  During stressed or EMERGENCY Conditions, a lower level of reliability is permitted to allow for increased operating flexibility and to minimize the impact on customers during power system emergencies.

Actions should be taken to establish and maintain NORMAL Conditions.  Regular cycling between NORMAL and EMERGENCY Conditions should be avoided.  Operations and Operations Planning should not intentionally position daily operations into EMERGENCY Conditions.  Capacity deficiencies or the occurrences of multiple contingencies are some reasons why EMERGENCY Conditions might exist.

This Operating Procedure includes specific definitions and criteria for the two levels of reliability.  Appendix A contains a flow chart that summarizes the methods and criterion contained in this document and provides an overview of its structure.  Appendix B provides definitions of thermal capacity ratings for transmission facilities [NORMAL, Long Time Emergency (LTE), Short Time Emergency (STE) and Drastic Action Limit (DAL)].

A.	Normal Conditions

The highest level of transmission reliability is achieved during non-stressed or NORMAL Conditions on the bulk power system.  In general, this level of reliability is accomplished by satisfying NORMAL Criteria for a wide range of contingencies (NORMAL Contingencies) using a limited set of operator actions (NORMAL Actions).  More specifically, for all stability related and Inter-Area thermal and voltage/reactive operations, all seven NORMAL Contingencies (in Section II.A.2.a-g) are applicable.  For thermal and voltage/reactive operations within New England that do not jeopardize the reliability of Areas outside New England, only five of the seven NORMAL Contingencies are considered.  Not considered are the NORMAL Contingencies in Section II.A.2.f-g (loss of two circuits on a multiple circuit tower and loss of a single element with delayed clearing).  This approach is consistent with the NPCC criteria philosophy that the basic criteria are not necessarily applicable in the portions of a member system where instability or overloads will not jeopardize the reliability of the bulk power system.  The following sections describe these NORMAL Criteria, NORMAL Contingencies and NORMAL Actions.

1.	Normal Criteria

a)	Generation and transmission service is scheduled to provide New England load and operating reserve as prescribed in OP 8 while covering NORMAL Contingencies.

b)	Pre-contingency loadings of transmission facilities should not exceed NORMAL ratings.

c)	NORMAL Contingencies should not cause, or result in, loadings beyond STE ratings.  Flows between LTE and STE must be reduced to or below LTE as soon as possible and definitely within 15 minutes.  If studies show that operators would not be able to reduce flows to or below LTE within 15 minutes, action should be taken (if possible) such that NORMAL Contingencies would not cause, or result in, loadings above LTE ratings.

Previously established/provided DAL ratings may be used but only if authorized by the Transmission Provider whose transmission facilities would be effected and flows between STE and DAL can be reduced to or below LTE immediately and definitely within 5 minutes.  

d)	Without prior approval to operate to STE ratings, NORMAL Contingencies should not cause, or result in, loadings on New York Power Pool (NYPP) transmission facilities, including NYPP-NEPOOL tie lines, beyond LTE ratings.   

	Underground cable circuits may be post contingency loaded to STE ratings provided generation and/or phase angle regulation are available to reduce the loadings to LTE ratings within 15 minutes and provided no other NYPP facility is loaded beyond its LTE rating.  The 1385 Norwalk Harbor-Northport 138 KV cable and the CONED-PSE&G tie lines, which are cable circuits, are not included in this exception.

e)	NORMAL Contingencies should not cause instability, unacceptably high or low voltage or voltage collapse.

f)	Any automatic reclosing and subsequent manual reclosing before adjusting generation should not cause instability of the transmission system.

2.	Normal Contingencies

For all stability related and inter-Area operations, protection should be provided for ALL of the NORMAL Contingencies listed in a-g below.

For thermal and voltage/reactive operations within New England, protection should be provided for the NORMAL Contingencies listed in a-e below.

During typical conditions with all major transmission facilities in-service, NORMAL Contingencies f and g should be covered in thermal and voltage/reactive operations if the occurrence of these contingencies could jeopardize the reliability of Areas outside of New England.  (Appendix C lists stuck breaker contingencies and Appendix D lists double circuit tower line contingencies.  Appendix G documents the procedure to be followed in determining if a stuck breaker contingency would have unacceptable Inter-Area impact.  Appendix H provides a list of actions that may be utilized to reduce the cost of providing stuck breaker protection.)

During less frequent conditions when a major transmission facility is out-of-service, NORMAL contingencies (f) and (g) need not be covered if the outage substantially reduces transfer limits based on NORMAL Contingencies f and g.
 
a)	A permanent three-phase fault on any generator, transmission circuit, transformer or bus section with normal fault clearing.

b)	Loss of any element without a fault.

c)	A permanent phase to ground fault on a circuit breaker with normal fault clearing.  (Normal fault clearing time for this condition may not always be high speed.)

d)	Simultaneous permanent loss of both poles of a direct current bipolar facility without an AC fault. 

e)	The failure of a circuit breaker associated with an SPS to operate when required following: loss of any element without a fault; or a permanent phase to ground fault, with normal fault clearing, on any transmission circuit, transformer or bus section.

f)	Simultaneous permanent phase to ground faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with normal fault clearing.  If multiple circuit towers are used only for station entrance and exit purposes, and if they do not exceed five towers at each station, then this condition is an acceptable risk and, therefore, can be excluded.  Other similar situations can be excluded on the basis of acceptable risk following appropriate Northeast Power Coordinating Council acceptance of each specific exclusion (Appendix D lists 345 KV multiple circuit towers in New England).

g)	A permanent phase to ground fault on any transmission circuit, transformer, or bus section with delayed fault clearing.  (Delayed fault clearing is consistent with correct operation of a breaker failure scheme and its associated breakers, or of a backup relay scheme with an intentional time delay.)

3.	Normal Actions

The ISO and Satellites will continuously assess system conditions and implement the NORMAL Actions described below to maintain or restore transmission reliability to NORMAL Conditions.

a)	Actions For Contingencies That Affect Small/Local Areas Within New England

If a contingency will impact only a small/local area within New England, the following NORMAL Actions should be implemented as required:

ISO initiated deviation from economic dispatch (notify appropriate Satellite)  

•	If the local area can be protected by deviation from economic dispatch, the ISO and Satellites will provide such protection.  

Transmission Provider waiver of contingency protection

•	If a local area cannot be protected by deviation from economic dispatch, Transmission Provider may elect to waive contingency protection for the local area.  When the local area involves two or more Transmission Providers, the appropriate Satellite will inform one of the involved Transmission Providers of the specific operating conditions.  All coordination required with other impacted Transmission Providers to waive contingency protection for the local area is the responsibility of the Transmission Provider first contacted by the Satellite.  All waivers granted under this provision must be communicated to the ISO in writing (fax) at the time that the waiver is granted.

When the local area involves more than one Satellite, one of the Satellites will be designated to contact an involved Transmission Provider who will then follow the process outlined above.

b)	Use of Special Protection Systems or the Preplanned Opening of Circuit Breakers.

(1)	Where Possible, Arm Special Protection Systems.

(2)	Manually set up generator or pump tripping.  This preplanned option of opening circuit breakers is limited to situations where previously documented studies have demonstrated that such breaker openings reliably mitigate the specific existing operating conditions and do not result in the loss of single contingency protection for other contingencies/facilities.

c)	Weather Sensitive Transmission Facility Ratings

There are times when actual ambient conditions (temperatures and wind) are significantly different from those used to establish standard seasonal ratings.  During those times, the use of temporary ratings based on actual ambient conditions may be warranted.  Depending on the ambient conditions, the temporary ratings may be higher or lower than the standard seasonal ratings.  When such weather conditions exist and a transmission facility is limiting, The ISO, the appropriate Satellite or appropriate Transmission Provider will identify the need for a temporary transmission facility rating based on actual weather conditions.  In cases where the Transmission Provider has supplied pre-defined weather sensitive ratings, such ratings will be used by the ISO and the Satellite after the Satellite and/or Transmission Provider has gathered/established the actual weather conditions.  If pre-defined weather sensitive ratings are not available, the involved Transmission Provider will be informed of the circumstances.  That Transmission Provider may elect to provide the appropriate Satellite with temporary ratings along with any pertinent qualifications for their use.  The Satellite will forward all temporary rating information in writing (fax) to the ISO.  Such temporary ratings will then be used in operations for the time period specified by the Transmission Provider or until rescinded by the Transmission Provider. 

d)	Deviation from Economic Dispatch

Deviate from economic dispatch and schedule generation to maintain NORMAL transmission reliability, including generation not counted as operating reserve.  This involves committing additional steam units included in the 10/30-minute reserve category.  Implement M/S 2 to declare an abnormal conditions alert.

e)	Switch Transmission Circuits

Open or close circuits to relieve transmission constraints.  This action can only be implemented when authorized by the ISO and when previously documented studies have demonstrated that such circuit openings reliably relieve the specific existing conditions and do not result in the loss of protection for other contingencies/facilities.

f)	OP 4 Actions 1 through 11

Implement selected actions from OP 4, Actions 1 through 11.  These Actions utilize generator maximum capabilities, Interruptible Loads, voluntary load curtailment of NEPOOL Participant's facilities, capacity/energy purchases, contracted customer generation and depletion of 30 minute reserve.

B.	Emergency Conditions

The system is in an EMERGENCY Condition if NORMAL Criteria is violated.  A lower level of reliability is permitted when operating under EMERGENCY Conditions provided that all appropriate NORMAL Actions have been initiated to restore NORMAL Criteria.  This level of reliability meets EMERGENCY Criteria for a less stringent set of contingencies (EMERGENCY Contingencies) using EMERGENCY Actions.  Exposure to reliability levels below EMERGENCY Conditions should not exist for more than 30 minutes.

1.	Emergency Criteria

a)	Generation and transmission facilities are adequate to supply New England load and at least minimum reserve requirements (10 minute requirements) as prescribed in OP 8 while covering only EMERGENCY Contingencies.

b)	Pre-contingency facility loadings may be between NORMAL and LTE if EMERGENCY Contingencies would not cause loadings beyond LTE ratings.  Loadings should be returned to or below the NORMAL rating after the daily load cycle.

c)	EMERGENCY Contingencies should not cause loadings beyond STE ratings.  Flows between LTE and STE must be reduced to or below LTE as soon as possible and definitely within 15 minutes.  Automatic devices (SPS), switching to set up a facility to trip upon occurrence of a specific contingency or, preplanned post-contingency operator responses are required if DAL ratings are used.

d)	EMERGENCY Contingencies should not cause instability, unacceptably high or low voltage or voltage collapse.

e)	Any automatic reclosing should not cause instability of the transmission system.

2.	Emergency Contingencies

a)	A permanent three-phase fault on any generator, transmission circuit, transformer or bus section, with normal fault clearing.

b)	The loss of any element without a fault.

3.	Emergency Actions

EMERGENCY Actions should be taken to maintain or restore power system conditions to at least those prescribed for operations under EMERGENCY Conditions.  In general, all appropriate and timely NORMAL Actions should be exhausted before taking EMERGENCY Actions.  EMERGENCY Actions should be taken before NORMAL Actions if the NORMAL Actions cannot be completed in time to relieve a thermal overload above LTE, prevent voltage collapse, or restore protection for EMERGENCY Contingencies within 30 minutes.  Any unused long term NORMAL Actions should be taken to allow for the cancellation of EMERGENCY Actions.
  
a)	Transmission Circuit Switching

In very well defined situations where it is clear that opening a transmission facility will alleviate a problem existing for a specific emergency situation, consideration will be given to opening such facility.  This action, without pre-determined studies, documentation, and authority will only be initiated to prevent more severe EMERGENCY Action and must be reported immediately to the Transmission Provider.

b)	OP 4 and OP 7

OP 4 and OP 7 EMERGENCY Actions include:

OP 4 - Action 12 and 13; 5% voltage reduction, requiring more/less than 10 minutes.

(1)	OP 4 - Action 14 and 15; customer generation not contractually available to NEPOOL.  Voluntary load curtailment by large industrial and commercial customers.  Radio and TV appeals for voluntary load curtailment.   Voluntary load curtailment by customers.

(2)	OP 7; Load shedding.

The following sections provide more detail on when it would be appropriate to take EMERGENCY Actions.

c)	Pre-Contingency Emergency Actions

EMERGENCY Actions may be needed to meet EMERGENCY Criteria even though a contingency has not occurred.  Such pre-contingency EMERGENCY Actions will be taken when NORMAL Actions are exhausted or can not be completed in a timely manner and there would be insufficient time after an EMERGENCY Contingency to contain the impact to a small/local area.  Pre-contingency EMERGENCY Actions are to be initiated when a potential EMERGENCY Contingency threatens large portions of New England load or could possibly cause a split of the bulk power system due to post-contingency voltage collapse, rapid cascading thermal overloads or, system instability.  Pre-contingency EMERGENCY Actions should also be taken when a potential EMERGENCY Contingency poses the same threats to Areas outside of New England or jeopardizes the reliability of the Northeast Interconnection.  

Shift operators are responsible to keep appropriate Supervisors at the ISO and Satellites advised as to conditions that might necessitate management review of the need to implement EMERGENCY Actions on a pre-contingency basis.

Management at the ISO and at the Satellites, to the extent that time permits, should consult with affected Transmission Providers s when developing pre-contingency strategies.

d)	Planned Immediate Post-Contingency Emergency Actions

If an EMERGENCY Contingency does not risk system stability but would result in low or gradually declining voltages or thermal loadings between STE and DAL, specific voltage reduction or load shedding plans should be established before the contingency for implementation immediately after the contingency.  Post-contingency EMERGENCY Action should be established and coordinated with the Satellites before the need for implementation arises.  If automatic devices are being used, their actions should be completed in a matter of cycles or seconds after the contingency.  Manual actions should be completed as soon as possible after the contingency (seconds if possible) but definitely within the one-two minutes required to prevent voltage collapse or cascading thermal overloads.  Post-contingent circuit loadings between STE and DAL must be reduced below LTE immediately and definitely within five (5) minutes.

C.	Post-Contingency Operation

If a contingency involves the loss of a transmission circuit(s), operators should attempt to reclose the circuit(s) within 5 minutes unless otherwise specified in specific policies and/or procedures.  If reclosure is successful, the system should be back to its original state and normal operation should resume.  If reclosure is unsuccessful or the contingency involved the loss of generation or load, operators should assess system conditions and perform appropriate NORMAL and EMERGENCY Actions to restore NORMAL and EMERGENCY Conditions.  When possible, coverage for NORMAL Contingencies should be restored using NORMAL Actions.

Post-contingency Actions should meet the following time requirements:

•	Rapidly declining critical transmission voltages should be stabilized as quickly as possible (within one-two minutes) using pre-determined EMERGENCY Actions, including voltage reduction and/or load shedding.  

•	Post-contingent transmission facility loadings between STE and DAL should be reduced below LTE immediately and definitely within 5 minutes using pre-defined EMERGENCY Actions including voltage reduction and/or load shedding plans.

•	Post-contingent transmission facility loadings between LTE and STE ratings should be reduced below LTE as soon as possible and definitely within 15 minutes using appropriate NORMAL and/or EMERGENCY Actions.

•	Coverage for EMERGENCY Contingencies should be restored within 30 minutes using appropriate NORMAL and/or EMERGENCY Actions.

III.	transmission system analysis

A.	Scope of Analysis

Transmission system analysis is required to:

•	Identify significant contingencies and system conditions during which contingencies can adversely impact system operation and;

•	Develop data, methods, operating guidelines and procedures which, when implemented, will provide reliable operation of the bulk power system per the criteria in this document.

Short term thermal analysis is performed on a continuous basis and coordinated with appropriate Satellites and adjoining NPCC Areas.  Long term thermal analysis is done on a seasonal, annual or as required basis and is coordinated with appropriate Transmission Providers, Satellites, adjoining NPCC Areas and NEPOOL Task Forces.

Long term stability studies are reviewed with the NEPOOL Stability Task Force and appropriate Inter-Area study groups.  Short-term stability analysis is coordinated with individual Transmission Provider representatives on the Stability Task Force.  

Short-term voltage/reactive analysis is reviewed with appropriate Satellites and NPCC Areas.  Longer-term voltage/reactive analysis is reviewed with the NEPOOL Voltage Task Force and other appropriate NEPOOL Task Forces or Inter-Area study groups.

B.	Classifying System Responses to Contingencies

Contingencies fall into one of the following categories depending on their impact on system reliability:

1.	Contingencies Critical to Areas External to New England

This type of contingency either involves the loss of an inter-Area transmission facility (thereby reducing inter-Area transfer capability) or has more severe consequences on an external Area than the most severe contingency in the external Area.    The possibility of thermal overloads, excessive voltage drops, or undamped oscillations on the interconnection should be considered when assessing the impact of these contingencies.  These contingencies are critical to interconnected system reliability.

2.	Contingencies Critical to Large Areas of New England or Bulk Power Transfers within New England

This type of contingency can threaten large areas within New England in two ways.  In one case, the contingency could split an area away from the bulk power transmission system due to cascading thermal overloads, voltage collapse or system instability.  Further breakup would likely occur in the islanded area.  The remaining bulk power system would be left with a substantial deficiency or excess of power.  In the other case, the contingency could cause the loss of another critical transmission facility, thereby significantly reducing transfer capability on the bulk power system and seriously impairing the ability to serve customer load.  These contingencies are critical to New England transmission reliability.

3.	Contingencies that Affect Small/Local Areas within New England

This type of contingency affects only a relatively small area within New England and does not impair reliability of the bulk power system.  The ISO will provide contingency protection, if possible, by deviating from economic dispatch.   Otherwise, the Transmission Provider(s) involved will be contacted through the appropriate Satellite.  The Transmission Provider(s) may elect to grant a waiver of contingency coverage. Multiple Transmission Provider waivers of first contingency protection require one of the affected Transmission Providers to communicate and coordinate waiver action with all other affected Transmission Providers.

C.	Extreme Contingencies

Recognizing that the bulk power system can be subject to events that are more severe than NORMAL or EMERGENCY Contingencies, EXTREME Contingencies will be assessed to determine their effect on system performance.  After due analysis and assessment of EXTREME Contingencies, Transmission Providers may utilize measures, where appropriate, to reduce the frequency of occurrence or to mitigate the circumstances that are indicated as a result of testing for such contingencies.

Appendix E lists the EXTREME Contingencies to be considered.

Document History

OP 19.rtf
8/31/98