NERC
C TPL-001:
00
“N-1-1” Contingency Analysis
2010 PowerWorld Client Conference
J
June
24
24, 2010
Portland Oregon
NERC Standard TPL-001-1
• Part of NERC Project 2006-02
–A
Assess Transmission
T
i i F
Future
t
Needs
N d and
dD
Develop
l
Transmission Plans
– http://www.nerc.com/filez/standards/Assess-Transmission-Future-Needs.html
• W
Would
ld require
i T
Transmission
i i Pl
Planners and
d
Planning Coordinators to prepare an annual
Planning
g Assessment of its p
portion of the Bulk
Electric System
• Would require study and documentation of
several classes of contingencies
• March 2010 ballot was not approved and will
proceed to recirculation ballot
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TPL-001-1 Event Categories
• P0: No Contingency, Normal System
• P1,
P1 P2
P2: Si
Single-Element
l El
C
Contingency
i
• P3: Generator Outage, followed by System
Adjustments followed by loss of another single
Adjustments,
element
• P4,, P5: Multiple-Element
p
Contingency
g
y
• P6: Transmission Outage, followed by System
Adjustments, followed by loss of another single
element
• P7: Multiple-Element Contingency (Common
Structure)
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Definitions
• Base Case: The power system in its normal
steady-state, operation, with all elements in
service that are expected to be in service.
• Primary Contingency: An loss of one or
more system elements that occurs first. A
Pi
Primary
C
Contingency
ti
may b
be a planned
l
d or
unplanned event.
• Secondary
Secondar Contingenc
Contingency: An contingenc
contingency
that occurs after the Primary Contingency.
This is usually an unplanned event
event.
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System Adjustments
• TPL-001-1 allows “planned System adjustments
such
h as T
Transmission
i i configuration
fi
i changes
h
and re-dispatch of generation… if such
adjustments are executable within the time
duration applicable to the Facility Ratings”
• Interruption of Firm Transmission Service and
Loss of Non-Consequential Load are allowed
for some events
• System Adjustments are sometimes termed
Remedial Action Schemes (RAS) or Special
P t ti Schemes
Protection
S h
(SPS)
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Definitions
• N-1-1 Contingency: A sequence of events
consisting of the initial loss of a single generator
or transmission component (Primary
Contingency), followed by system adjustments,
followed by another loss of a single generator
or transmission
t
i i componentt (Secondary
(S
d
Contingency).
• Model
M d l Criteria:
C it i An
A evaluation
l ti off system
t
conditions in Simulator, that if met, would cause
a conditional system adjustment to occur
occur.
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“N-1-1” Contingencies
• TPL-001-1 category
g y P3 and P6 outages
g
could be classified “N-1-1” contingencies
– A system
y
element is forced out of service
– Adjustments are made if necessary for security
of the N-1 condition
– A second system element is forced out of
service
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PowerWorld Simulator Contingency
Modeling
• Many combinations of
actions and elements,
elements e.g.
eg
– Open a line
– Change generator output
– Partially curtail a load
• Unconditional or
conditional actions, which
occur only when specified
system criteria are met
• Very detailed modeling
of System
y
Adjustments
j
is possible
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N-1-1 Analysis Process
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B7 Case:
Normal System Operation
150 MW
40 Mvar
153 MW
AGC ON
One
64 MW
63 MW
A
80 MW
30 Mvar
Three
MVA
1.00 pu
1.05 pu
A
28 MW
90 MW
28 MW
Four
MVA
60 MW
40 MW
20 Mvar
A
80%
MVA
1.00 pu
A
55 MW
MVA
MVA
60 MW
A
89 MW
MVA
56 MW
Two
1.04 pu
2 MW
A
3 MW
50 MW
AGC ON
2 MW
A
MVA
80 MW
Five
79 MW
1.02 pu
150 MW
AGC ON
53 MW
A
A
130 MW
40 Mvar
MVA
200 MW
0 Mvar
Six
1.04 pu
MVA
3 MW
27 MW
26 MW
A
53 MW
Seven
MVA
27 MW
A
26 MW
1.04 pu
MVA
250 MW
AGC ON
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200 MW
AGC ON
slack
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200 MW
0 Mvar
10
B7 Case: Primary Contingencies
• Without System Adjustments, case has
severall b
branch
h overloads
l d d
during
i various
i
Primary Contingencies
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System Adjustments
• If effective System Adjustments are known,
i
incorporate
them
h
iinto contingency
i
d
definitions
fi i i
• Simulator’s tools may be used to help design
S t
System
Adjustments
Adj t
t if they
th are nott known:
k
– Sensitivity Analysis
– Line Loading Replicator
– OPF: apply to post-contingent system when system
adjustments are permitted post-contingency
– SCOPF: apply to pre-contingent system when
system adjustments are not permitted postcontingency
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TLR Sensitivities:
Single Element
• For contingencies
g
with a single
g overload, solve
contingency of interest
• Use TLR Sensitivities and Custom Expressions
to estimate the impact of adjusting generators
and loads in relieving the overload
Overloaded
Line
Source of
Make-up
Power
13
TLR Sensitivities:
Multiple Element
Source of
p Power
Make-up
WTLR shows
good
d llocations
ti
tto
change
load/generation
14
Line Loading Replicator
Overloaded line and
estimated MW flow to meet
MVA limit
IInjection
j ti group containing
t i i allll
possible System Adjustment
controls (gens and/or loads)
Suggested changes for
achieving desired loading
15
OPF: System Adjustments After
Contingency
• Primary Contingency: Loss of Line between buses 5 and 7
150 MW
40 Mvar
153 MW
AGC ON
67 MW
66 MW
A
One
80 MW
30 Mvar
Three
MVA
1.00 pu
1.05 pu
A
19 MW
86 MW
19 MW
Four
MVA
65 MW
40 MW
20 Mvar
A
MVA
1.00 pu
A
62 MW
MVA
MVA
66 MW
50 MW
AGC ON
13 MW
A
A
86 MW
MVA
62 MW
T
Two
A
1.04 pu
51 MW
13 MW
106%
119 MW
117 MW
MVA
Five
0.98 pu
150 MW
AGC ON
0 MW
A
130 MW
40 Mvar
MVA
200 MW
0 Mvar
Six
1 04 pu
1.04
51 MW
1 MW
1 MW
A
0 MW
Seven
MVA
1 MW
A
1 MW
1.04 p
pu
MVA
250 MW
AGC ON
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201 MW
AGC ON
sla ck
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200 MW
0 Mvar
16
OPF Results
• Drop generator at bus 4, increase generator at
bus 6
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OPF Results: Difference Flows
0 MW
0 Mvar
0 MW
AGC ON
One
5 MW
4 MW
A
0 MW
0 Mvar
Three
MVA
0.00 pu
0.00 pu
A
11 MW
5 MW
11 MW
Four
MVA
7 MW
0 MW
0 Mvar
A
MVA
0.00 pu
A
9 MW
MVA
MVA
7 MW
Gen drop
of 43 MW
at bus 6
provides
30 MW
relief on
overloaded
line
A
4 MW
MVA
9 MW
Two
0.00 pu
23 MW
A
31 MW
10 MW
43 MW
AGC ON
23 MW
A
MVA
Fi
Five
30 MW
-0.04 pu
0 MW
AGC ON
53 MW
A
0 MW
0 Mvar
MVA
0 MW
0 Mvar
Six
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0.00 pu
10 MW
27 MW
27 MW
A
53 MW
Seven
MVA
27 MW
A
27 MW
0.00 pu
MVA
-43 MW
AGC ON
0 MW
AGC ON
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sla ck
0 MW
0 Mvar
18
Modeling System Adjustments
•
•
•
Contingency Block for Remedial Action Scheme
Block may be applied to multiple contingencies that cause similar
overloading on line 2-5
25
Optionally assign Model Criteria to block elements or entire block to
apply the RAS only at certain loading conditions
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Primary Contingency with System
Adjustments
150 MW
40 Mvar
153 MW
AGC ON
58 MW
57 MW
A
One
80 MW
30 Mvar
Three
MVA
1.00 pu
1.05 pu
A
42 MW
95 MW
42 MW
Four
MVA
51 MW
40 MW
20 Mvar
A
85%
MVA
1.00 pu
A
44 MW
MVA
MVA
51 MW
100 MW
OFF AGC
22 MW
A
A
95 MW
MVA
44 MW
Two
A
1.04 p
pu
0 MW
21 MW
99%
110 MW
109 MW
MVA
Five
0.98 pu
150 MW
AGC ON
0 MW
A
130 MW
40 Mvar
MVA
200 MW
0 Mvar
Six
1.04 pu
0 MW
0 MW
0 MW
A
0 MW
Seven
MVA
0 MW
A
0 MW
1 04 pu
1.04
MVA
200 MW
OFF AGC
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200 MW
AGC ON
slack
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200 MW
0 Mvar
20
Secondary Contingencies
• Solve a Primary Contingency and set as reference
• Run the contingency analysis on the set of Secondary
Contingencies
• Repeat OPF or SCOPF processes for secondary
contingencies that result in overloads
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SCOPF where System Adjustments are
not Permitted After Contingency
-60 MW
AGC ON
• SCOPF
One
difference
case (relative
to Base Case)
C
)
• Load must be Two
shed
h d att b
bus 5
for system to
be secure for 0 MW
the secondary 0 MvarSix
contingencies
g
0 MW
0 Mvar
17 MW
17 MW
A
0 MW
0 Mvar
Three
MVA
0.00 pu
0.00 pu
A
28 MW
43 MW
28 MW
Four
MVA
11 MW
0 MW
0 Mvar
A
MVA
0.00 pu
A
16 MW
MVA
MVA
11 MW
50 MW
AGC ON
6 MW
A
A
42 MW
0.00 pu
0.00 pu
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MVA
16 MW
6 MW
A
2 MW
13 MW
MVA
Five
13 MW
-0.03 pu
0 MW
AGC ON
53 MW
A
-60 MW
0 Mvar
MVA
2 MW
26 MW
26 MW
A
53 MW
Seven
MVA
26 MW
A
26 MW
0.00 pu
MVA
-50 MW
AGC ON
-1 MW
AGC ON
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slack
0 MW
0 Mvar
22
System Adjustments Revised
• Revised RAS to apply to Primary Contingency
so that Secondary Contingencies are secure
with no further System Adjustments
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Generator and Load Models
• Use OPF with Minimum Control Change
objective
bj i ffunction
i to assign
i uniform
if
cost per
MW to adjust any OPF control
• However,
H
it may b
be d
desirable
i bl tto assign
i a hi
higher
h
cost to load controls than to generation controls
– In this way,
way load shedding may also be considered
considered,
but would only be applied if generator actions are
ineffective or extreme
– Use OPF with Minimum Cost objective function, and
assign “V-shaped” marginal cost curves to
generators and appropriate
g
pp p
benefit curves to loads
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Generator Cost Curve
• Slope of curve is “cost” to adjust generator output by 1
MW
• Set breakpoint to the current operating point
• Easy to implement with Auxiliary File
Slope of line is
MWh Price 1
Cost ($/h)
Slope of line is
MWh Price 2:
Set to -MWh Price 1
MW Break 1:
Set to Gen Min MW
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MW Break
B k2
2:
Set to Gen MW
(present output)
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Gen Output (MW)
25
Generator Cost Curve Auxiliary File
• Cost to move all g
generators is set to $10 p
per
MW
// assign all generators a cost of $10/MWh to deviate from their
present outputs
SCRIPT
{
SelectAll(GEN);
SetData(GEN, [GenBidMW, GenBidMWHR, GenBidMW:1, GenBidMWHR:1],
["@GenMWMin", -10, "@GenMW", 10], Selected);
UnSelectAll(GEN);
}
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Load Benefit Models
• Maximum load is set to nominal value
• Load benefit is much higher than cost to
redispatch generation
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Combining Two Lists of Contingencies
• Use “Join Active
Contingencies”
feature to
combine list of
primary and
secondary
d
contingencies
into a complete
N-1-1 set
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More Information
• White p
paper
p and sample
p p
power flow case
and contingencies
– http://www.powerworld.com/Resources/TransmissionPlanning.asp
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