GIC Impacts on the Transmission Grid
Thomas J. Overbye
University of Illinois at Urbana-Champaign
overbye@illinois.edu
WECC Technical Studies Subcommittee
May 7, 2015
2
Geomagnetic Disturbances (GMDs)
•
•
•
GMDs have the potential to severely disrupt operations of
the electric grid by inducing quasi-dc geomagnetically
induced currents (GICs) in the high voltage grid
Until recently power engineers had few tools to help them
assess the impact of GMDs on their system
GMD assessment tools are now moving into the realm of
power system planning and operations engineers
– Calculations are now implemented in power flow and transient
•
–
stability
GIC impact is certainly still an area of research, but tools are here
Presentation presents recent results, but research is
certainly ongoing in this area; particular need for model
validation
3
GMD Overview
•
Solar corona mass ejections (CMEs) can cause changes in
the earth’s magnetic field (i.e., dB/dt). These changes in
turn produce a non-uniform electric field at the surface
– Changes in the magnetic flux are usually expressed in nT/minute;
–
–
–
from a 60 Hz perspective they produce an almost dc electric field
1989 North America storm produced a
change of 500 nT/minute, while a
stronger storms, such as the ones in
1859 and 1921, could produce more
than 5000 nT/minute variation
Storm “footprint” can be continental in scale, for example covering
much of the U.S.
For reference, Earth’s magnetic field is normally between
25,000 and 65,000 nT, with higher values near the poles
Image source: J. Kappenman, “A Perfect Storm of Planetary Proportions,” IEEE Spectrum, Feb 2012, page 29
4
July 2012 GMD Near Miss
•
•
•
According to a July 2014 NASA press release, in July of
2012 there was a solar CME that barely missed the
earth
If it had hit the earth
it would likely have
caused the largest
GMD that we have
seen in the last 150
years
There is still lots of
uncertainly about how large a storm is reasonable to
consider in electric utility planning
Image Source: science.nasa.gov/science-news/science-at-nasa/2014/23jul_superstorm/
5
Solar Cycles
•
•
Sunspots follow an 11 year cycle, and have been observed
for hundreds of years
We're in solar cycle 24 (first numbered cycle was in 1755);
minimum was in 2009, maximum in 2014/2015
But Large CMEs Are Not Well Correlated
with Sunspot Maximums
The large
1921 storm
occurred
four years
after the
1917
maximum
Slide from Chris Balch, "Space Weather and Solar Cycle 24", National Geomagnetic Disturbance Workshop, INL, April 2015
6
Impact of a Large GMD
From an Operations Perspective
•
•
•
•
•
•
•
There would be a day or so warning but without specifics
on the actual magnitude or location
It could strike quickly (they move at millions of miles per
hour) with rises times of less than a minute, rapidly
covering a good chunk of the continent
– Early warning satellites at Lagrange points, 1 million miles out
Reactive power loadings on hundreds of
transformers could sky rocket, causing
heating issues and potential large-scale voltage collapses
Power system software like state estimation could fail
Control room personnel would be overwhelmed
The storm could last for days with varying intensity
Waiting until it occurs to prepare might not be a good idea
7
8
Geomagnetically Induced Currents (GICs)
The impact of the GMD
induced quasi-dc
electric field is modeled
as dc voltages
superimposed on the
transmission lines.
This causes dc currents,
called geomagnetically
induced currents (GICs)
The GIC calculation
then just involves
solving a linear dc
circuit problem.
9
GMD Assessment Software Evolution
•
•
Initial packages were stand alone, not integrated into
commercial power flow or transient stability
In 2011-2012 GMD assessment integrated into power flow
•
More recently sensitivity analysis has been included
– Uniform electric field assumption initially common
– Sensitivity of GICs to input electric field assumptions (nearby lines
–
•
•
provide vast majority of a transformers GICs)
Sensitivity of GICs to assumed substation grounding resistance
(results indicate the values can be quite sensitive!)
Much more detailed non-uniform electric fields are now
being modeled
Calculations are now also integrated into transient stability
for possible dynamic considerations and EMP
10
GMD Enhanced Power Analysis Software
•
•
By integrating GIC calculations directly within power
analysis software (like power flow) power engineers can
readily see the impact of GICs on their systems, and
consider mitigation options
GIC calculations use many of the existing model
parameters such as line resistance. But some nonstandard values are also needed; power engineers would
be in the best position to provide these values, but all can
be estimated when actual values are not available
– Substation grounding resistance
– transformer grounding configuration, transformer coil resistance,
whether auto-transformer, whether three-winding transformer,
generator step-up transformer parameters
11
GIC G-Matrix
•
With knowledge of the pertinent transmission system
parameters and the GMD-induced line voltages, the dc bus
voltages and GIC flows can be calculated by solving a
linear equation
I =GV
– The G matrix is similar to the Ybus except 1) it is augmented to
–
•
•
include substation neutrals, and 2) it is just conductances
The current vector contains the Norton injections associated with
the GMD-induced line voltages
Factoring the sparse G matrix and doing the
forward/backward substitution takes about 1 second for the
62,600 bus Eastern Interconnect Model
Linear system so superposition holds (e.g., doubling the
input doubles the output)
12
Transformer Impacts of GICs
•
•
The dc GICs are superimposed upon the ac currents. In
transformers this can
push the flux into
saturation for part of
the ac cycle
This can cause large
harmonics; in the
positive sequence
(e.g., power flow and
transient stability) these
harmonics can be represented by increased reactive
power losses on the transformer
Mapping Transformer GICs to
Transformer Reactive Power Losses
•
•
•
•
13
Transformer specific, and can vary widely depending upon
the core type
– Single phase, shell, 3-legged, 5-legged
– Most significant with single phase designs
Ideally information supplied by the transformer owner
– Currently support default values, a user specified linear mapping, or
a piecewise linear mapping
For large system studies default data is used when nothing
else is available. Scaling value changes with core type
Still debate in the industry with respect to the magnitude of
damage GICs would cause in transformers (from slight
aging to permanently destroyed)
14
Four Bus Example
IGIC ,3Phase
150 volts

 93.75 amps or 31.25 amps/phase
1  0.1  0.1  0.2  0.2 
Substation A with R=0.2 ohm
Neutral = -18.7 Volts
Neutral = 18.7 Volts
Bus 3
DC = 18.7 Volts
1.001 pu
Bus 1
DC = 28.1 Volts
0.999 pu
Substation B with R=0.2 ohm
Bus 2
765 kV Line
DC =-28.1 Volts
0.997 pu
Bus 4
DC =-18.7 Volts
1.000 pu
3 ohms Per Phase
slack
GIC/Phase =
31.2 Amps
High Side = 0.3 ohms/ Phase GIC Input = -150.0 Volts High Side of 0.3 ohms/ Phase
GIC Losses = 52.6 Mvar
GIC Losses = 52.5 Mvar
The line and transformer resistance and current values are
per phase so the total current is three times this value.
Substation grounding values are total resistance.
Brown arrows show GIC flow.
Specifying the Transformer Loss
Values in Per Unit
•
•
Previously K was specified as Mvars/amps
𝑄loss = 𝑉pu𝐾𝐼GIC
–
–
𝐾 is the “loss factor”, depends on core type, phases, etc.
𝑄loss is in Mvars, 𝐼GIC is in Amps
Since Qloss varies with V, this required an assumed
nominal voltage (usually 500 kV) with the actual nominal
voltage of each transformer used to scale the 𝐾 values
𝑉base,highkv
𝑄loss = 𝑉pu 𝐾
𝐼GIC
500
– Disadvantages: Arbitrary assumed kV needed, 𝐾 in Mvars/Amp
cannot well model default piece-wise linear relationships that
may exist for the three-leg transformers
15
Specifying Transformer Losses Scalars
in Per Unit
•
Current Approach: Representing the 𝐾 values in per unit
– Using a base derived using the transformer’s high side voltage
– Current base using the peak value
Peak (or "crest") value
I base,highkv , peak 
•
16
Sbase 1000 2
Vbase,highkv 3
used since this is a dc
current base
Convert to per unit by dividing Qloss by Sbase,3ph
Qloss

Sbase
V pu K old
Vbase,highkv
1000 I GIC 2
500
Vbase ,highkv I base,highkv , peak 3
K values are independent
of the assumed MVA
base
1000 2 K old
Qloss , pu  V pu (
) I eff,pu  V pu 1.633 K old  I eff,pu  V pu K new I eff,pu
500 3
K new  1.633K old
Specifying Transformer Losses Scalars
in Per Unit
•
Example: 345/138 kV transformer with IGIC = 100 amps
and K = 1.5; use Sbase of 100 MVA
100  1000 2
100
 236.7 A  I pu 
 0.422
236.7
345 3
The use of
 0.422  1.5  0.634  Qloss  63.4 Mvar
I base,highkv , peak 
Qloss , pu
this per unit
approach
should be
standardized!
PowerWorld cases
all use the new
approach now
17
18
Single Phase Transformer K Comparison
Graph provided by University of Tennessee
19
Four Bus Example: Input Data
•
•
Next several slides demonstrate how GICs and their
impacts can be calculated in an integrated fashion
Earlier four bus system with an assumed electric field
– Substation coordinates need to be given to get line length
– In example Sub A is at 40N, 87W, Sub B is at 40N, 89W
– Line length is 170.8 km (106.2 mile)
20
Four-Bus Inputs: Substations
•
Key inputs are the grounding resistance and geo-location
(latitude and longitude)
Latitude and
longitude
Grounding
resistance
= 0.2 
21
Grounding Resistance
•
•
•
Substation grounding resistance is the resistance in ohms
between the substation neutral and earth ground (zeropotential reference)
An actual “fall of potential” test is the best way to determine
this resistance
Defaults are provided based on number of buses and
highest nominal kV, but research has shown this to be a
poor substitute for actual measurements
– Typical values range from 0.1 to 2.0 
– Substations with more buses and higher nominal kV are assumed to
have lower grounding resistance
22
Four-Bus Inputs: Transformers
•
Key inputs
– Coil resistance (DC ohms)
– Grounding configuration
– Autotransformer? (Yes/No)
– Core Type
Most essential parameters;
these determine the basic
topology of the GIC
network
23
Four-Bus Inputs: Transformers
•
•
•
•
Manually Enter Coil Resistance
– “Yes, User Set”: user enters “High Side Ohms per Phase”
–
and “Medium Side Ohms per Phase”
“No, Auto Default”: values estimated
XF Config High and XF Config Med: most common
options are “Gwye” and “Delta”
Is Autotransformer: “Yes”, “No”, or “Unknown”
Core Type
24
Transformer Assumptions
•
•
•
It is always best to provide known quantities,
especially for configuration and autotransformer fields
If any transformer information is unknown, assumed
values need to be used
Coil Resistance
– ohms per phase estimate based on positive-sequence AC
–
per-unit series resistance and transformer impedance base
Assumed split between each winding:
𝑅𝑝𝑢
𝑅𝐵𝑎𝑠𝑒,𝐻𝑖𝑔ℎ𝑆𝑖𝑑𝑒
= 𝑅𝐻𝑖𝑔ℎ𝑆𝑖𝑑𝑒 + 𝑎𝑡2 𝑅𝐿𝑜𝑤𝑆𝑖𝑑𝑒
𝑅𝐻𝑖𝑔ℎ𝑆𝑖𝑑𝑒 = 𝑎𝑡2 𝑅𝐿𝑜𝑤𝑆𝑖𝑑𝑒
25
Transformer Assumptions: Autotransformers
•
Units are assumed to be autotransformers if all of the
following criteria are met
– unit is not a phase-shifting transformer
– high side and low side are at different nominal voltages
– high side nominal voltage is at least 100 kV
– turns ratio is less than or equal to 4
Transformer Assumptions:
Mapping GICs to Reactive Power Losses
•
•
As mentioned earlier the relationship between GICs and
reactive power losses now uses the per unit approach,
and allows for linear or piecewise linear models
Impact in the power flow and transient stability is modeled
as a reactive current source, so Mvars vary linearly with
voltage
26
27
Other Considerations
•
•
•
Specifying a minimum voltage level to include in the
analysis allows electric fields to be ignored on
transmission lines below a cutoff kV
GIC losses can be ignored on an area basis
GIC input voltages can be ignored on an area basis
28
Scaled Electric Field Modeling
•
•
•
GICs are dependent upon the assumed electric field
NERC approach is to use a scaled uniform direction
electric field
Field/voltage input is
– Electric-Field Magnitude (V/mile or V/km)
– Storm Direction (0 to 360 degrees)
All directions are a linear
combination of the north
and east directions
α and β scaling factors
(covered later)
29
Four Bus Case – Eastward Field
•
•
Below values show results with uniform 0.88 V/km
eastward field
With uniform field, voltage is path independent
0.88 V/km 170.8 km  150 V
I base,highkv , peak (100 MVA Base) 
QLoss ,pu,GIC 
100  1000 2
 106.7 A
765  3
31.2
 1.80  0.526  52.6 Mvar
106.7
Substation A with R=0.2 ohm
Neutral = -18.7 Volts
Neutral = 18.7 Volts
Bus 3
DC = 18.7 Volts
1.001 pu
Bus 1
DC = 28.1 Volts
0.999 pu
Substation B with R=0.2 ohm
Bus 2
765 kV Line
DC =-28.1 Volts
0.997 pu
Bus 4
DC =-18.7 Volts
1.000 pu
3 ohms Per Phase
slack
GIC/Phase =
31.2 Amps
High Side = 0.3 ohms/ Phase GIC Input = -150.0 Volts High Side of 0.3 ohms/ Phase
GIC Losses = 52.6 Mvar
GIC Losses = 52.5 Mvar
Values
would be
zero for a
N-S field
for this
case
30
42 Example System
2 5 M var
28
2 1 .0 M var
Substation 3
Substation 2
Total GIC Losses
0.0 Mvar
18
6 0 0 MW
-2 M var
17
15
16
A
A
M VA
6 0 0 MW
-2 M var
A
9 0 0 MW
2 1 M var
A
Amps
A
33
Amps
M VA
A
89%
M VA
A
22
A
92%
M VA
MVA
36
A
91%
M VA
30
MVA
Amps
A
4 0 0 MW
1 5 0 M var
A
Amps
29
Amps
A
A
Amps
A
Substation 5
A
Amps
20
Amps
5
Amps
A
A
A
Amps
M VA
Amps
24
32
A
A
Amps
A
A
A
A
Amps
25
Amps
M VA
34
Amps
Amps
1 0 0 M var
4 0 0 MW
A
M VA
A
21
M VA
40
Amps
A
Am p s
Amps
Amps
A
A
Amps
Amps
A
Amps
12
Amps
A
Substation 8
A
3
A
M VA
4
1
7 8 .1 M var
42
A
A
M VA
M VA
13
7 5 M var
7 5 MW
A
A
A
M VA
A
M VA
M VA
A
M VA
Amps
A
MVA
A
Amps
37
A
31
41
M VA
Substation 4
slack
11
A
Amps
A
5 3 .2 7 M var
1 0 0 MW
5 0 M var
3 0 0 MW
1 2 5 M var
A
Amps
Amps
A
Amps
A
2
39
A
Amps
Amps
A
M VA
A
35
A
A
Amps
5 0 MW
2 5 M var
Amps
38
A
5 0 MW
7 5 M var
A
A
Amps
Amps
A
23
A
M VA
93%
3 0 0 MW
7 5 M var
1 4 0 0 MW
5 0 0 M var
A
A
7 3 1 MW
7 9 M var
8
M VA
A
M VA
Amps
9 0 0 MW
2 1 M var
7
Amps
A
Amps
A
M VA
A
A
19
Substation 6
6
1 2 0 0 MW
3 0 0 M var
A
M VA
14
A
26
Amps
M VA
2 1 .1 M var
A
M VA
5 0 MW
2 0 M var
Substation 1
A
M VA
27
A
A
Amps
M VA
3 0 0 MW
2 5 0 M var
5 0 0 MW
-1 3 M var
5 0 0 MW
-1 3 M var
31
42 Bus Example System: 5 V/km Eastward
2 5 M var
28
1 8 .3 M var
Substation 3
Substation 2
Total GIC Losses 1516.8 Mvar
18
6 0 0 MW
3 2 7 M var
17
15
16
A
A
M VA
6 0 0 MW
3 2 7 M var
A
9 0 0 MW
4 0 0 M var
A
Amps
A
33
Amps
M VA
A
88%
M VA
A
22
A
97%
M VA
MVA
36
A
92%
M VA
A
102%
Amps
4 0 0 MW
1 5 0 M var
A
Amps
29
Amps
A
A
Amps
A
Substation 5
A
Amps
20
Amps
5
Amps
A
A
A
Amps
M VA
Amps
32
A
A
Amps
A
A
A
A
Amps
25
Amps
M VA
34
Amps
Amps
1 0 0 M var
4 0 0 MW
A
M VA
A
21
M VA
40
Amps
A
Am p s
Amps
Amps
A
A
Amps
Amps
A
Amps
12
Amps
A
Substation 8
A
3
A
M VA
4
1
5 6 .2 M var
42
A
A
M VA
M VA
13
7 5 M var
7 5 MW
A
A
A
M VA
A
M VA
M VA
A
M VA
Amps
A
MVA
A
Amps
37
A
31
41
M VA
Substation 4
slack
11
A
Amps
A
4 3 .8 0 M var
1 0 0 MW
5 0 M var
3 0 0 MW
1 2 5 M var
A
Amps
Amps
A
Amps
A
2
39
A
Amps
Amps
A
M VA
A
35
A
A
Amps
5 0 MW
2 5 M var
Amps
38
A
5 0 MW
7 5 M var
A
A
Amps
Amps
A
23
A
30
A
24
1 4 0 0 MW
5 0 0 M var
A
M VA
MVA
3 0 0 MW
7 5 M var
7 4 2 MW
3 2 7 M var
8
M VA
A
M VA
Amps
9 0 0 MW
4 0 0 M var
7
Amps
A
Amps
A
M VA
A
A
19
Substation 6
6
1 2 0 0 MW
3 0 0 M var
A
M VA
14
A
26
Amps
M VA
1 6 .4 M var
A
M VA
5 0 MW
2 0 M var
Substation 1
A
M VA
27
A
A
Amps
M VA
3 0 0 MW
2 5 0 M var
5 0 0 MW
1 8 7 M var
5 0 0 MW
1 8 7 M var
32
42 Bus Example System: 5 V/km Northward
2 5 M var
28
1 9 .6 M var
Substation 3
Substation 2
Total GIC Losses 936.9 Mvar
18
6 0 0 MW
1 8 0 M var
17
15
16
A
A
M VA
6 0 0 MW
1 8 0 M var
A
9 0 0 MW
3 0 4 M var
A
Amps
A
33
Amps
M VA
A
89%
M VA
A
22
A
94%
M VA
MVA
36
A
92%
M VA
30
MVA
Amps
A
4 0 0 MW
1 5 0 M var
A
Amps
29
Amps
A
A
Amps
A
Substation 5
A
Amps
20
Amps
5
Amps
A
A
A
Amps
M VA
Amps
24
32
A
A
Amps
A
A
A
A
Amps
25
Amps
M VA
34
Amps
Amps
1 0 0 M var
4 0 0 MW
A
M VA
A
21
M VA
40
Amps
A
Am p s
Amps
Amps
A
A
Amps
Amps
A
Amps
12
Amps
A
Substation 8
A
3
A
M VA
4
1
6 7 .9 M var
42
A
A
M VA
M VA
13
7 5 M var
7 5 MW
A
A
A
M VA
A
M VA
M VA
A
M VA
Amps
A
MVA
A
Amps
37
A
31
41
M VA
Substation 4
slack
11
A
Amps
A
4 6 .7 7 M var
1 0 0 MW
5 0 M var
3 0 0 MW
1 2 5 M var
A
Amps
Amps
A
Amps
A
2
39
A
Amps
Amps
A
M VA
A
35
A
A
Amps
5 0 MW
2 5 M var
Amps
38
A
5 0 MW
7 5 M var
A
A
Amps
Amps
A
23
A
M VA
97%
3 0 0 MW
7 5 M var
1 4 0 0 MW
5 0 0 M var
A
A
7 3 2 MW
1 2 7 M var
8
M VA
A
M VA
Amps
9 0 0 MW
3 0 4 M var
7
Amps
A
Amps
A
M VA
A
A
19
Substation 6
6
1 2 0 0 MW
3 0 0 M var
A
M VA
14
A
26
Amps
M VA
1 8 .9 M var
A
M VA
5 0 MW
2 0 M var
Substation 1
A
M VA
27
A
A
Amps
M VA
3 0 0 MW
2 5 0 M var
5 0 0 MW
3 2 M var
5 0 0 MW
3 2 M var
33
WECC GICs: Uniform 5 V/km Eastward
Transmission Atlas ®
34
WECC GICs: Uniform 5 V/km Northward
Transmission Atlas ®
35
Power Flow Convergence
•
•
Integrated GIC modeling can certainly impact power flow
convergence since the GIC induced reactive power losses
simultaneously adds (potentially) lots of reactive power
Several techniques can help prevent divergence
– Just calculating the GICs without solving the power flow
– Not calculating GMD induced voltages for equivalent lines
– Gradually increasing the assumed electric fields to avoid
–
–
–
simultaneously adding too much reactive power at one time
Only calculating the GIC transformer reactive power losses for
specified areas; reactive power doesn’t tend to travel far
Freezing the transformer taps and switched shunts in certain
problematic areas
Solving in transient stability for a gradually increasing GMD
36
Sensitivity Considerations
•
•
Data is needed at least for the study footprint and near
neighbors
Transmission line resistance values are readily obtained
from the power flow cases
•
•
DC resistance is quite close to ac values; temperature dependence
(0.4% per degree C) plays a role
Estimates of transformer winding resistance can be
obtained from the power flow cases
– Usually whether they are auto-transformers can be determined
– Whether device is a three winding transformer can usually be
•
guessed (if not explicitly modeled)
Recent research has indicated that the GICs can be quite
sensitive to the assumed grounding resistance
G Matrix Substation Grounding
Considerations
•
•
The GIC sensitivity to the substation resistance can be
determined by using a Thevenin equivalent, where the
resistance is the driving point value
– Can be computed quickly using sparse vector methods
Sensitivity at substation i is defined as
Negative of this ratio
is defined as
•
Normalized as
Ri
i :
Ri  RTH ,i
37
38
Grounding Sensitivity, 20 Bus System
•
Grounding sensitivities can be computed for a 20 bus
system as
Values about 0.5 indicate that the local substation
resistance is the dominant parameter in determining
the GICs
39
Grounding Sensitivity, EI System
•
The previous sensitivity approach was applied to the
Eastern Interconnect
– Since we didn't know the actual substation grounding resistance,
•
–
these values needed to be estimated
Subject to a uniform 1 V/km eastward electric field
Table shows the
resultant sensitivities
for the ten substations
with the highest GICs;
again substation
resistance often
dominates
40
GIC Source Sensitivity Analysis
•
•
•
Sensitivities of the effective GICs for a transformer (or
set of transformers) to the assumed transmission line
GMD-induced electric fields can be calculated
Sensitivities are derived by first writing the effective GIC
for transformer r in matrix form
where G is the GIC conductance matrix, ET are the input
fields tangential to each line, B relates the voltages to
the Norton current injections, and Cr relates the voltages
to the effective current; V is the GIC voltage vector
G, B, Cr are sparse, hence quick computation
41
GIC Sensitivity Analysis, cont.
•
•
Sensitivities, telling which voltage inputs contribute
to the current, are determined just by differentiating
the previous equation
Each entry k in ST,r tells how IEffective for transformer r
would vary for a 1 V/km variation in the electric field
tangential to the kth transmission line
42
Four Bus Example
Transpose of ST vectors for the four bus system
Transmission
Lines
Line 1 -- 2
Line 3 -- 4
Bus 1 GSU
Bus 4 GSU
Bus 2-3 Auto
35.02
5.87
5.87
40.25
-18.30
36.21
43
Twenty Bus Case Results

T3, 18-17
Eastward
T3, 18-17
Max
T8, 20-5
Eastward
T8, 20-5
Max
Ieffective
Line 2-3
Line 2-17
Line 15-4
Line 17-16
Line 4-5,1
Line 4-5,2
Line 5-6
Line 5-11
Line 6-11
Line 4-6
Line 15-6,1
Line 15-6,2
Line 11-12
Line 16-20
Line 17-20
31.55
5.82
-4.50
0.62
11.64
1.35
1.35
0.76
0.00
-0.05
2.46
1.72
1.72
0.40
0.01
8.27
48.09
5.84
5.84
0.65
12.01
1.65
1.65
0.81
0.00
0.25
2.47
1.81
1.81
0.40
0.46
12.45
13.07
-2.53
1.95
8.07
-0.79
-11.38
-11.38
21.57
0.00
-0.25
9.19
0.63
0.63
1.98
-0.06
-4.55
92.1
2.53
2.54
8.55
0.82
13.95
13.95
23.16
0.00
1.23
9.21
0.66
0.66
1.98
6.03
6.86
44
Large Case Results
In the Eastern Interconnect
example, usually very
few lines contribute the
GICs for each transformer
Conclusion is detailed electric
field values are only needed for
the contributing lines
For AEP’s 60 transformers
with the largest
effective currents about
50% of the GICs are
contributed by just 10
lines (out of 57,000 in the
case); 76% by just 20
lines; 99% by 1% of
the lines
45
Benchmark GMD Scenario
•
•
•
Derived from the March 1989 event
Peak electric field is 8 V/km for a reference location
(60 deg. N, resistive Earth)
Electric field for other regions scaled by two factors
– Epeak = 8 * α * β V/km
– “1 in a 100 year” event
– Details can be found at
•
http://www.nerc.com/pa/Stand/Project201303GeomagneticDist
urbanceMitigation/Benchmark_GMD_Event_June12_clean.pdf
GIC Calculations with Geomagnetic
Latitude Scaling (α)
Transmission Atlas
®
46
Magnetic
latitude is about
10 degrees
greater than
geographic
latitude in much
of North America
Magnetic latitudes
are changing
because the
earth's magnetic
poles are moving
Earth Resistivity and Geomagnetic
Latitude Scalars (α β)
Transmission Atlas
®
Earth Image Source: http://www.naturalhistorymag.com/sites/default/files/imagecache/large/media/2009/05/0309partner2_jpg_18912.jpg
The earth resistivity
layers are now
modeled in
power system
software, allowing
different scenarios
to be considered
47
48
Quantifying Scaling Effect on GICs
•
PowerWorld directly handles transmission lines that span
areas with different a and b values
– Voltage is calculated by integrating the electric field along the
•
length of the transmission line
With a uniform 8 V/km electric field the total WECC GIC
losses (with default data) are about 40,000 Mvars
– 9100 Mvar in Northwest, 4400 Mvar in Arizona, 4200 Mvar in
•
PGE, 2400 Mvar in Alberta
With the ab scaled 8 V/km electric field the total WECC
GIC losses are about 7,000 Mvars
– 1500 Mvar in Northwest, 180 Mvar in Arizona, 450 Mvar in PGE,
•
2100 Mvar in Alberta
PowerWorld v19 will allow individual resistivity scalars (b)
to be specified on a substation basis
49
Parametric Studies
•
GMD analyses of a large scale system
– Focus on steady-state voltage stability
– What happens if Emax exceeds 8 V/km?
– Comprising of two parametric studies
1. Effects of including/excluding neighboring regions
– At which value of Emax does the power flow lose convergence, due
to increased reactive power losses?
2. Uncertainty of substation grounding resistance values
– Scaling resistance values by a factor “γ”
50
Mitigation Strategies
•
•
•
•
Tools can help engineers determine effective mitigation
strategies
GIC flows can be reduced both through operational
strategies such as opening lines,
and through longer term
approaches such as installing
blocking devices
Redispatching the system can
change transformer loadings,
providing margins for GICs
Algorithms are needed to provide power engineers with
techniques that go beyond trial-and-error
51
Validation
•
•
GIC modeling is still evolving; there is a need for much
more validation work
Currently there are just 22 magnetic
field monitors in North America
– Values are often not correlated on
•
•
•
short time scales (less than minutes)
Need more transformer neutral GICs
but to be useful these need to be associated with realtime system models
Need accurate measurements V, MW, and Mvars on both
sides of transformers with neutral GICs
Useful data is only obtained during modest or larger
GMDs
High Altitude Electromagnetic Pulse
(HEMP)
•
•
•
HEMPs produce three
energetic waves that
interact with power system
components (E1, E2, E3)
Geoelectric fields are
induced via E3 (the focus of
this research)
Similar to solar storms
(GMS), but with quicker
rise-times and larger
magnitudes
HEMP E3
•
The earth’s magnetic field is disturbed by 1) the fireball
generated by the blast and 2) energized metallic debris
• E3 is not a direct energy coupling like E1/E2
• E3 is a geoelectric field induced by the earth’s changing
magnetic field
• E3 is very similar to GMD except faster rise times and
magnitudes
• Leverage existing GMD research to establish the
foundation of E3 modeling and simulation
*Rise-times make HEMP E3 appropriate for transient
stability timeframe, system dynamics are crucial!
Simulated HEMP E3 Disturbance
The highest E3 is not right over the blast;
also, large EMPs can be caused by
relatively small (e.g., North Korea type)
weapons
20
E(t) (V/km)
15
10
5
0
-5 0
10
5/6/2015
10
1
Time (s)
10
2
[IEC] [FERC]
10
3
HEMP E3
20 bus GIC benchmark
case (augmented to include
ac parameters and dynamic
models)
Composite E3
Disturbance
40
35
30
E3(t) (V/km)
25
20
15
10
5
0
-5
-10
0
10
1
2
10
10
Time (s)
First 60 seconds of IEC 61000-2-9
Visualization*
Time varying voltage contours (such as this
one) shed light on potential mitigation
strategies for preventing grid collapse during
HILF events
*preliminary studies
3
10
56
HEMP Power Grid Impact Simulation
57
Data Issues
•
Getting the correct extra GIC (or EMP) related data into
the power flow (or transient stability) packages will be key
– Examples: Substation resistance, transformer K values, etc., will
•
•
•
be key
Studies will require data for individual areas, along with
data from neighboring areas
Standardized, flexible data formats would be helpful
– We'll be tracking a moving target for a few years, as needed fields
continue to evolve
Small, benchmark cases will help in making sure the
different packages are giving the same results
58
Conclusions
•
GIC impact assessment has progressed to point at which
it can be treated like other engineering problems with a
cost/benefit assessment
– There is lots of uncertainty, but we work in an industry with lots of
•
uncertainty!
Getting started with GIC assessment can be relatively
straightforward, consisting of doing GIC enhanced power
flow studies
– Can be used to determine mitigation strategies and locations for
•
monitoring equipment
Integration into transient stability is straightforward, and
can be leveraged for GMD and EMP studies
59
Thank You!