MPC Planning Criteria
Version 2.00
Effective Date: July 1, 2016
Supporting Policy: n/a
MPC Planning Criteria
Purpose:
This document outlines the specific Minnkota Power Cooperative (MPC) Bulk Electric System (BES)
transmission reliability criteria, which are to be used for MPC planning and operational planning studies. It
also describes their relationship to the North American Electric Reliability Corporation (NERC) and Midwest
Reliability Organization (MRO) Reliability Standards.
This document provides deterministic criteria for use in MPC system studies so that a sound basis of
comparison exists between MPC system performance studies. It also provides a set of evaluation criteria
from which MPC study scopes, procedures, and reports can be produced.
This document sets forth the specific BES reliability criteria established by MPC. These specific reliability
criteria are in addition to the general criteria outlined in the NERC and MRO Reliability Standards.
Referenced Documents: The following are referenced within this document.
•
MPC Open Access Transmission Tariff
•
MPC Facility Ratings Methodology
Applicability: These criteria are applicable to MPC BES Facilities, but may be applied to MPC non-BES
facilities if deemed appropriate.
NERC Standard(s) of Reference:
NERC Standard #
TPL-001-4 – Transmission System Planning Performance Requirements
Requirement #
R3.5, R4.5, R5
Table 1 – Steady State & Stability
Performance Planning Events;
Table 1 – Steady State & Stability
Performance Extreme Events
Definitions:
Capitalization indicates a MPC or NERC defined term. Capitalized terms and acronyms that are not otherwise
defined in this document shall have the respective meanings set forth in the MPC Open Access Transmission
Tariff, the NERC Glossary of Terms, or the meaning commonly understood within the electric utility industry.
The NERC Glossary of Terms is located at www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
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MPC Planning Criteria
Version 2.00
Effective Date: July 1, 2016
TABLE OF CONTENTS
1. Transmission Reliability Criteria.................................................................................................................... 3
1.1 Voltage Criteria ..................................................................................................................................... 3
1.1.1 Pre-Contingency Voltage Limitations........................................................................................ 3
1.1.2 Post-Contingency Period Voltage Limitations........................................................................... 3
1.1.3 Transient Stability Period Voltage Limitations .......................................................................... 3
1.1.4 Instantaneous Voltage Change ................................................................................................. 4
1.2 Facility Loading Limits ........................................................................................................................... 4
1.3 Short Circuit .......................................................................................................................................... 4
1.4 Fault Ride-Through ............................................................................................................................... 4
1.5 Transient Period Damping Criteria ....................................................................................................... 4
1.6 Relay Encroachment and Out-of-Step (OOS) Margins.......................................................................... 5
1.6.1 OOS Relay Margin Security Parameters .................................................................................... 5
1.6.1 Distance Relaying – Apparent Impedance Transient Criteria ................................................... 5
1.7 Voltage Stability Criteria ....................................................................................................................... 6
1.8 Cascading .............................................................................................................................................. 7
Appendix A: Revision Record ............................................................................................................................... 8
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MPC Planning Criteria
Version 2.00
Effective Date: July 1, 2016
1. TRANSMISSION RELIABILITY CRITERIA
MPC transmission reliability criteria are established in order to ensure safety, avoid equipment damage, and
maintain reliable operation of the overall grid.
1.1 Voltage Criteria
The criteria parameters monitored in the planning and operational study work shall be rounded to the
nearest one-hundredth per unit (0.01 p.u.), to ensure consistent application of the criteria and to allow
for small modeling variances. The “transient stability period” refers to the first ten (10) seconds after
the contingency. The “post-contingency period” refers to the period ten (10) seconds to thirty (30)
minutes after the contingency. Additionally, MPC has criteria for maximum allowable instantaneous
voltage change, or delta-V. These voltage criteria can be utilized as guidelines for real-time operations;
however, depending upon operating conditions, the real-time voltages may vary outside of the
recommended ranges (see below), and MPC should be contacted for guidance on the application of
these voltage criteria during real-time operations.
1.1.1 Pre-Contingency Voltage Limitations
All steady state BES voltages in the study base case shall meet these criteria after all system
adjustments have been made. These criteria are intended to be consistent with the NERC and
MRO Reliability Standards, as applicable, and apply to the pre-contingency conditions.
Facility
All buses
Young 1 Generator Bus (22 kV)
Young 2 Generator Bus (20 kV)
Maximum
kV/p.u.
1.05 p.u.
0.991 p.u.
1.015 p.u.
Minimum
kV/p.u.
0.97 p.u.
0.936 p.u.
0.973 p.u.
1.1.2 Post-Contingency Period Voltage Limitations
All steady-state BES voltages following contingencies in the power flow simulations must meet
these criteria. These criteria are intended to be consistent with the NERC and MRO Reliability
Standards, as applicable, and apply to the post-contingency conditions prior to any operator
intervention. As long as mitigation occurs by automatic action, 0.88 p.u. voltages can be allowed
at buses using the default criteria for durations up to ten (10) minutes.
Facility
All buses
Young 1 Generator Bus (22 kV)
Young 2 Generator Bus (20 kV)
Maximum
kV/p.u.
1.10 p.u.
0.991 p.u.
1.015 p.u.
Minimum
kV/p.u.
0.92 p.u.
0.936 p.u.
0.973 p.u.
1.1.3 Transient Stability Period Voltage Limitations
MPC system voltage oscillations in transient analysis simulations shall meet these criteria:
Facility
All buses
Drayton 230 kV
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Maximum
kV/p.u.
1.20 p.u.
1.15 p.u.
Minimum
kV/p.u.
0.70 p.u.
0.80 p.u.
MPC Planning Criteria
Version 2.00
Effective Date: July 1, 2016
The voltage must return within applicable post-contingency voltage limitations after ten (10)
seconds. The bus voltages on the MPC system are allowed to increase to 1.3 p.u. for a duration
up to two hundred milliseconds (200 msec), unless otherwise noted.
1.1.4 Instantaneous Voltage Change
In order to protect against voltage flicker, typically caused by switching of reactive devices or
motor starting, MPC allows a maximum instantaneous voltage change of 0.03 p.u. during system
intact and 0.05 p.u. during an outage.
1.2 Facility Loading Limits
Applicable facility loading limits must not be violated. Facility loading limits will be established by MPC
in the MPC Facility Ratings Methodology, and these limits reside in the Facilities Library within the MPC
NERC Document Management System. The normal rating is the continuous thermal rating unless noted
otherwise. The emergency rating is the thirty- (30-) minute thermal rating. The continuous (normal)
and emergency ratings are included in regional power flow models. Dynamic ratings can be both
continuous and emergency.
Some Facilities have specifically identified dynamic ratings for some facilities under certain conditions.
These are documented through applicable operating guides. These ratings may differ from the
continuous and emergency ratings that are included in regional power flow models.
1.3 Short Circuit
All MPC buses shall be modeled having the minimum maximum fault current interrupting capability,
which should not be violated. If it is violated, the actual equipment and contingency will be reviewed to
make sure the individual equipment maximum fault current interrupting capability is not violated.
1.4 Fault Ride-Through
All generators greater than twenty megawatts (20 MW) shall be able to ride through NERC Category P1
through P7 1 events.
1.5 Transient Period Damping Criteria
All machine rotor angle oscillations will be positively damped and must meet the criteria below. The
criterion does not apply to bus voltages. The Damping Factor will be calculated from the Successive
Positive Peak Ratio (SPPR) of the peak-to-peak amplitude of the rotor oscillation. SPPR and the
associated Damping Factor will be calculated as:
•
SPPR = Successive swing amplitude / previous swing amplitude, and
•
Damping Factor = (1 - SPPR) * 100 (in %)
The damping criteria are as follows (with increased damping required for higher probability events):
1
•
For disturbances (with faults): SPPR (maximum) = 0.95; Damping Factor (minimum) = 5%
•
For line trips: SPPR (maximum) = 0.90; Damping Factor (minimum) = 10%
TPL-001-4, Table 1 – Steady State & Stability Performance Planning Events
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MPC Planning Criteria
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Effective Date: July 1, 2016
As an alternative method to automatic damping calculations, such as DAMPCK and the Prony analysis,
the Damping Factor may be calculated manually by measuring the SPPR of the last two cycles (if they
are discernible) of a 20-second simulation. If the swing within the last two cycles is less than one
degree, the oscillations are sufficiently damped regardless of the SPPR calculation.
When measuring damping in all cases, simulations should be run out to twenty (20) seconds in order to
remove well-damped frequencies from the waveform.
1.6 Relay Encroachment and Out-of-Step (OOS) Margins
1.6.1 OOS Relay Margin Security Parameters
Relay
Steady State
Pre
Post
110% 50%
OOS relay
Dynamic
25%
The definitions of these specific relay margin calculations are shown in Figure 1, below.
MARGIN = (D1 / D2) * 100%
Operating Point
D1
D2
Steady State (pre-contingency)
.
Figure 1 – OOS Relay Margins
1.6.1 Distance Relaying – Apparent Impedance Transient Criteria
The transient apparent impedance swings on all lines shall be monitored, after fault clearing,
against a three-zone mho (or offset impedance) circle characteristic with the following zones:
Circle A = 1.00 x Line Impedance
Circle B = 1.25 x Line Impedance
Circle C = 1.50 x Line Impedance
Apparent impedance transient swings into the inner zones (Circles A or B) are considered
unacceptable, unless documentation is provided showing the actual relays will not trip for the
event.
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MPC Planning Criteria
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Effective Date: July 1, 2016
A PSS/E 2 dynamic user model, MRELY1, is maintained in the UIP (User Interface Package), which
performs the required global monitoring.
1.7 Voltage Stability Criteria
A voltage stability study may be necessary to demonstrate that there is sufficient margin between the
normal operating point and the collapse point. The study shall include voltage versus power transfer or
system demand (P-V curve) and voltage versus reactive power (Q-V).
For P-V, sufficient margin is maintained by operating at or below Plimit. The Plimit is determined by
developing P-V curves for those buses that have the largest contribution to voltage instability due to
the most limiting NERC Category P1 contingency, per NERC TPL standards. The Plimit is calculated as the
lesser of:
• (0.9) * Pcrit (shown below in Figure 2 as point “a”) where Pcrit is defined as the maximum
power transfer or system demand (nose of P-V curve), or
•
The maximum power transfer or system demand which does not result in a postcontingency voltage violation as defined in this document.
Figure 2 – P-V Curve
For Q-V, sufficient reactive power margin, Qmargin, must be maintained. Qmargin is determined by
developing Q-V curves for those buses that have the largest contribution to voltage instability due to
the most limiting NERC Category P1 contingency 3, per NERC TPL standards. Qmargin is calculated as
reactive power between the nose of the Q-V curve and the 0 MVAR injection. A positive value implies a
negative reactive power margin, and a negative value implies a positive reactive power margin. See
Figure 3, below.
2
3
Power System Simulator for Engineering (PSS/E)
TPL-001-4, Table 1 – Steady State & Stability Performance Planning Events
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MPC Planning Criteria
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Effective Date: July 1, 2016
MPC requires the following reactive power margin:
•
For 345 kV buses Qmargin ≤ -100 MVAR
•
For 230 kV buses Qmargin ≤ -50 MVAR
•
For 115 kV buses Qmargin ≤ -10 MVAR
Figure 3 – Q-V Curve
1.8 Cascading
In all analyses, cascading must not occur for NERC Category P0 through P7 4 events. Cascading may
occur for Extreme Events 5; however, an evaluation of possible actions designed to reduce the likelihood
or mitigate the consequences and adverse impacts of the event(s) shall be conducted. Cascading is
defined by MPC as the non-consequential loss of 1000 or more MW of load following a contingency, or
the loss of more than four (4) elements. This can be modeled by:
4
5
•
Steady State: review post-contingent loading on circuits in the steady-state analysis and
tripping lines loaded at 125% emergency rating until no further overloaded circuits exist.
•
Transient Stability: review distance relay margins and trip any lines that violate distance
relay transient criteria until no further violations exist.
•
If more than four (4) elements have tripped due to Steady State overloads or Transient
Stability distance relaying, then cascading may have occurred.
•
Actual relay settings and element capabilities will be reviewed on each of the tripped
elements to determine if tripping would have occurred. If four (4) or more elements trip
assuming actual relay settings, then cascading has occurred.
TPL-001-4, Table 1 – Steady State & Stability Performance Planning Events
TPL-001-4, Table 1 – Steady State & Stability Performance Extreme Events
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MPC Planning Criteria
Version 2.00
Effective Date: July 1, 2016
APPENDIX A: REVISION RECORD
This document must be reviewed and approved at least once every fifteen (15) calendar months.
The review and approval process is documented in digital format using the MPC NERC Document
Management System.
This revision history is provided for informational purposes only and change summaries should not be
considered a complete description of changes. In the event of a conflict between this document and the
MPC NERC Document Management System, the MPC NERC Document Management System shall
prevail.
Version
1.05
2.00
6
TPL-001-4 R3.5, 4.5
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Change Summary
Issue Date
Updated cascading criteria language to cover
Extreme Events, 6 and updated format.
Effective Date
03/21/2016
07/01/2016