Geomagnetic Disturbance
Vulnerability Assessment
Case Study
Created by:
Teshmont Consultants LP
Presented to:
Western Electricity Coordinating Council
Technical Studies Subcommittee
January 21, 2016
1
Presenters
Jaryn Vaile, E.I.T.
jvaile@teshmont.com
(403) 705-8001
Dr. Sameh Kodsi, P.Eng., PE
skodsi@teshmont.com
(204) 228-6426
 GMD Vulnerability Assessment Case Study
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Agenda
 Geomagnetic Disturbance Overview
 NERC Standards
 Case Study
 Scope, Assumptions and Methodology
 Results
 Discussion and Recommendations
 Questions
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Earth’s Geomagnetic Field
3
Geomagnetic Disturbance Overview
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Effects of a GMD on the Power Grid
 Induced quasi-dc geomagnetically-induced current (GIC) in
transmission systems
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Effects of GIC in AC Systems
 Transformer half cycle saturation
 Transformer overheating due to excess flux in the core
 Repeated exposure to GIC causes damage to insulation and
accelerated aging
 Increased Mvar consumption
 Decrease in voltage levels and stability margins
 Reactive compensation devices may be lost during a GMD event
 Failure can cause voltage instability in the system
 Inadvertent or intentional protection malfunction
 1989 Hydro Quebec – Seven SVC’s tripped
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Effects of GIC in DC Systems
 Quasi-DC nature of GIC introduces harmonic components into the
system
 SVCs and filter banks in HVDC converter stations are susceptible to
harmonics
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NERC Standards
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NERC EOP-010-1
 Based on FERC Order No. 779, NERC created two standards,
EOP-010-1 and TPL-007-1 to address the effect of GMDs
 EOP-010-1: Effective April 1, 2015
 Two entities: Reliability Coordinator (RC) and Transmission Operator
(TO)
3 Requirements:
 R1: RC shall develop, maintain, and implement a GMD Operating Plan
 R2: RC shall disseminate forecasted and current space weather
conditions as specified in the Operating Plan
 R3: TO shall develop, maintain, and implement a GMD Operating
Procedure or Process to mitigate effects of a GMD
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NERC TPL-007-1
 TPL-007-1: Likely to come into effect mid-2016, filed January 2015
 Four entities: Planning Coordinator, Transmission Planner,
Transmission Owner, Generator Owner
 Seven requirements for transmission system planned performance
during a benchmark GMD Event
7 Requirements:
 R1: Identify the responsibilities of each entity
• determines which entity fulfills each requirement
 R2: Maintain system models of the planning area
 R3: Maintain criteria for steady state voltage performance
 R4: Complete a GMD Vulnerability Assessment every 60 months
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NERC TPL-007-1
 Requirements:
 R5: Provide GIC flow information to be used for transformer
thermal assessment, including:
• Maximum GIC flow
• Effective GIC time series using the benchmark GIC event
 R6: Conduct a thermal assessment on power transformers where
the GIC flow is ≥ 75 A per phase
• Should include suggested mitigation actions, if necessary
 R7: If a system does not meet performance requirements
(performs within defined steady state limits), a Corrective Action
Plan must be developed
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Case Study
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Objective and Scope
 Objective:
 Investigate risks and effects of a GMD on a transmission system

and equipment
Scope:
 Study limited to 500 kV and 240 kV stations
 Create a DC GIC model
 Calculate level of GIC and increased levels of reactive power
consumption on the transmission system equipment
 Identify transformers with effective GIC ≥ 75 A per phase
 Provide recommendations for future actions
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Study Assumptions and Parameters
 The 2015/16 Winter Peak base case was used to model
the transmission system.
 Where transmission lines crossed through areas of
different geo-electric field magnitudes, the larger of the
two magnitudes was applied.
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Study Assumptions and Parameters (2)
 When transformer DC resistance was unavailable,
transformer modelling data was used.
 Transmission elements below 200 kV were excluded.
 A default value of 0.1 Ohm was used for the substation
grounding resistance when data was unavailable.
 Neighbouring systems were modelled as the next path to
ground away from the study network.
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Methodology – Model Development
 Followed NERC requirements and recommendations
 GIC Model includes:
 Two 500 kV HVDC lines and interties
 Multiple networks of 240 kV and above
 Another utility’s substations directly connected to the network

were included using assumptions to model transmission elements
 All power transformers > 200 kV were included
 Earth conductivity structures were modeled using data from the
Space Weather Hazard Assessment for the region
The model included neighbouring networks by including the line to
the first substation away and its resistance to ground
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Methodology – Model Development (2)
Earth Conductivity Zones
Simplified Map
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Methodology – Model Development (3)

Earth
Zone
Mean (V/km)
95%
Confidence
Interval
(V/km)
1
0.049
0.18
3.65
Extreme 1
in 100
Years
(V/km)
4.23
2
0.045
0.17
3.28
3.81
3
0.023
0.09
1.61
2.03
4
0.037
0.14
2.76
2.96
5
0.034
0.13
2.43
2.84
6
0.036
0.13
2.57
2.89
7
0.087
0.30
3.95
4.39
8
0.055
0.19
2.50
2.67
9
0.082
0.28
3.79
3.72
10
0.073
0.25
3.37
3.27
Maximum
(V/km)
GMD Scenario Geo-electric Field Magnitudes
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Methodology – Scenario Development
 Four GMD scenarios were simulated based on the statistical analysis
of actual recorded magnetic fields:
1.
2.
3.
4.
Mean scenario represents the average recorded GMD level
from over a 30 year period
95% Confidence Interval scenario was established by the
cumulative counts of a GMD level as a percentage of the
total time over a 30 year period
Maximum scenario was established by the maximum
recorded geomagnetic data over a 30 year period
Extreme 1 in 100 years scenario was developed using the
theory of extreme value statistics using recorded data over
a 30 year period
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Methodology – Transformer Mvar Loss
Modelling
 Increases in reactive power losses resulting from half-
cycle saturation of transformers in presence of high GIC
can affect system voltages and lead to voltage collapse
under extreme conditions
 The reactive power losses corresponding to the GIC in a
transformer obey a linear relationship
 The calculated reactive losses were added in the base
case power flow model as reactive constant current loads
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Methodology – Transformer Mvar Loss
Modelling
Generic GIC to Mvar Scaling Factors
(PSS®E PAG)
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High Risk Transformer GIC and Mvar Losses
Transformers with Effective GIC ≥75 A/Phase (High Risk)
Substation
Transformer
Maximum
Effective GIC
(A/Phase)
Reactive
Geo-Electric
Power Loss
Field
(Mvar)
Orientation
1-75
T 17501
138.87
19.33
180°
Extreme 1 in
100 Years
2-75
Phase-Shifting
Trans (PST)
94.65*
27.26
120°
Extreme 1 in
100 Years
3-75
T 37501
91.37
12.72
110°
Extreme 1 in
100 Years
4-75
T 47501
90.03
12.53
110°
Extreme 1 in
100 Years
5-75
T 57501
88.22
12.28
60°
Extreme 1 in
100 Years
6-75
HVDC Converter
Transformer
88.13
103.99
30°
7-75
T 77501, 02, 03
87.23
102.93
30°
Scenario
Applied
Extreme 1 in
100 Years
Extreme 1 in
100 Years
*94.65 A/phase occurred with the series compensation in service
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Transformer GIC and MVAR Losses
Transformers with Effective GIC 50-75 A/Phase
Maximum
Reactive
Geo-Electric
Effective GIC Power Loss
Field
Scenario Applied
(Mvar)
Orientation
(A/Phase)
Substation
Transformer
1-50
HVDC Converter Trans
70.01
39.66
60°
Extreme 1 in 100 Years
2-50
T 25001, 03, 04
69.77
82.32
40°
Extreme 1 in 100 Years
3-50
T 35000, 01, 02
68.92
81.32
90°
Extreme 1 in 100 Years
4-50
T 45004, 05, 06
62.37
73.60
130°
Extreme 1 in 100 Years
3-50
T 35003
62.21
18.04
90°
Extreme 1 in 100 Years
5-50
HVDC Converter Trans
62.17
73.36
60°
Extreme 1 in 100 Years
4-50
T 45007, 08, 13
62.07
73.24
130°
Extreme 1 in 100 Years
6-50
T 65002
56.17
67.93
40°
Extreme 1 in 100 Years
6-50
T 65003
56.17
67.93
40°
Extreme 1 in 100 Years
7-50
T 75001
53.10
7.39
160°
Extreme 1 in 100 Years
7-50
T 75002
53.10
7.39
160°
Extreme 1 in 100 Years
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Transformer GIC and MVAR Losses
NORTH CITY Transformers with Effective GIC >10 A/Phase
Substation
Transformer
Maximum
Effective GIC
(A/Phase)
Reactive
Power Loss
(Mvar)
Geo-Electric
Field
Orientation
Scenario Applied
NC-1
T 05
25.26
3.52
180°
Extreme 1 in 100 Years
NC-2
T 03
24.43
7.08
60°
Extreme 1 in 100 Years
NC-3
T 01
22.90
3.19
90°
Extreme 1 in 100 Years
NC-2
T 01
19.77
5.73
60°
Extreme 1 in 100 Years
NC-4
T 02
15.73
2.19
50°
Extreme 1 in 100 Years
NC-4
T 01
15.73
2.19
50°
Extreme 1 in 100 Years
NC-2
T 02
13.85
4.02
60°
Extreme 1 in 100 Years
NC-5
T 02
11.24
1.56
130°
Extreme 1 in 100 Years
NC-5
T 01
11.18
1.56
130°
Extreme 1 in 100 Years
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Transformer GIC and MVAR Losses
SOUTH CITY Transformers effective GIC
Substation
Transformer
Maximum
Effective GIC
(A/Phase)
Reactive
Power Loss
(Mvar)
Geo-Electric
Field
Orientation
Scenario Applied
SC-1
T 01
20.86
2.90
130°
Extreme 1 in 100 Years
SC-1
T 02
20.30
2.83
130°
Extreme 1 in 100 Years
SC-2
T 01
10.53
1.47
40°
Extreme 1 in 100 Years
SC-3
AUTO 01
9.25
1.29
160°
Extreme 1 in 100 Years
SC-3
AUTO 02
9.25
1.29
160°
Extreme 1 in 100 Years
SC-2
T 02
8.16
1.14
40°
Extreme 1 in 100 Years
SC-2
T 03
8.16
1.14
40°
Extreme 1 in 100 Years
SC-3
GSU 01
3.25
0.45
160°
Extreme 1 in 100 Years
SC-3
GSU 02
2.08
0.29
160°
Extreme 1 in 100 Years
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SS 4-75, T 47501 GIC and MVAR Loss
SS 4-75, T 47501 GIC
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SS 4-75, T 47501 MVAR
26
SS 5-75, T 57501 GIC and MVAR Loss
SS 5-75, T 57501 GIC
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SS 5-75, T 57501 MVAR
27
SS 7-75, T 77501/02/03 GIC and MVAR Loss
SS 7-75, T 77501/02/03 GIC
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SS 7-75, T 77501/02/03 MVAR
28
Effect of Series Compensation on GIC
Maximum
Effective
GIC
(A/phase)
94.65
74.34
Series
Compensation
Geo-Electric
Field Orientation
(°)
In-Service
110
By-Passed
120
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Transmission Line GIC
Transmission Lines with GIC Flow ≥ 5% of “Winter Rating” Current
Length (km)
Geo-Electric
Field
Orientation
Scenario Applied
Line
Voltage (kV)
Maximum GIC
(A/Phase)
L01
500
-118
229
40°
Extreme 1 in 100
Years
L02
240
-57
97
40°
Extreme 1 in 100
Years
L03
240
103
63
180°
Extreme 1 in 100
Years
L04
240
76
65
180°
Extreme 1 in 100
Years
L05
240
-68
53
70°
Extreme 1 in 100
Years
L06
240
64
82
180°
Extreme 1 in 100
Years
L07
240
62
13
50°
Extreme 1 in 100
Years
L08
240
-61
8
50°
Extreme 1 in 100
Years
L09
240
60
46
10°
Extreme 1 in 100
Years
L10
240
60
20
30°
Extreme 1 in 100
Years
L11
240
40
124
170°
Extreme 1 in 100
Years
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0° N Orientation, Extreme 1 in 100 Years
Scenario
GIC Flows in
Transmission Lines and
Substation Grounds
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60° NE Orientation, Extreme 1 in 100 Years
Scenario
GIC Flows in
Transmission Lines and
Substation Grounds
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90° NE Orientation, Extreme 1 in 100 Years
Scenario
GIC Flows in
Transmission Lines and
Substation Grounds
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130° NE Orientation, Extreme 1 in 100 Years
Scenario
GIC Flows in
Transmission Lines and
Substation Grounds
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System-Wide Reactive Power Increases
Maximum
GeoSystem
Electric
Reactive Power
Field
Loss (Mvar)
Orientation
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Scenario
Applied
884
60°
Extreme 1 in 100
Years
773
60°
Maximum
40
60°
95% Confidence
Interval
11
60°
Mean
35
System AC Voltages with
Reactive Power Increases
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System AC Voltages > 200 kV with
Reactive Power Increases - N-0 @ 60°
Geo-Electric Field Orientation
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Single Contingency Results –
Transformer Effective GIC
Transformers with Effective GIC ≥75 A/Phase in Contingency (High Risk)
N-0
Change in
Geo-Electric
Maximum
Maximum
Field
Effective GIC Effective GIC
Orientation
(A/Phase)
(A/Phase)
Substation
Transformer
N-1 Maximum
Effective GIC
(A/Phase)
8-75
T 87501
80.5 - 828
46.0 – 811
34.6
30°
Extreme 1 in
100 Years
8-75
T 87502
79.33 - 828
44.0 – 811
35.33
30°
Extreme 1 in
100 Years
9-75
T 97501
89.87 – 622
53.1 - 682
36.77
150°
Extreme 1 in
100 Years
10-75
T 107500, 01, 02
101.76 - 828
69.71 - 802
32.05
90°
Extreme 1 in
100 Years
10-75
T 107504
108.79 - 734
62.21 - 802
46.58
90°
Extreme 1 in
100 Years
11-75
T 117533, 28, 27
104.45 - 499
63.46 - 548
40.99
130°
Extreme 1 in
100 Years
12-75
HVDC Converter
Transformer
98.14 - 911
70.01 - 884
28.13
60°
Extreme 1 in
100 Years
13-75
T 137513, 15, 16
80.57 - 773
72.95 - 836
7.62
30°
Extreme 1 in
100 Years
Scenario
Applied
38
Single Contingency Results – Voltage
Stability
Worst Case Point of System Voltage Collapse
Contingency
Point of
Geo-Electric
Collapse
Field
Amplification
Orientation
Factor*
Total GIC
Scaled Geo-electric Field Magnitude (V/km)
Reactive
Power
Demand Zone Zone Zone Zone Zone Zone Zone Zone Zone Zone
1
2
3
4
5
6
7
8
9
10
(Mvar)
N-0
3.6
60°
3150
15.1
13.6
7.2
10.5
10.1
10.3
15.6
9.5
13.3
11.6
Contingency 1
1.9
60°
1700
7.93
7.14
3.81
5.55
5.33
5.42
8.23
5.01
6.98
6.13
Contingency 2
1.9
0°
1409
7.93
7.14
3.81
5.55
5.33
5.42
8.23
5.01
6.98
6.13
Contingency 3
2.0
90°
1606
8.46
7.62
4.06
5.92
5.68
5.78
8.78
5.34
7.44
6.54
Contingency 4
2.6
90°
2054
10.84 9.76
5.20
7.59
7.28
7.41 11.25 6.84
9.53
8.38
Contingency 5
2.6
90°
2054
10.84 9.76
5.20
7.59
7.28
7.41 11.25 6.84
9.53
8.38
Contingency 6
2.6
60°
2266
10.84 9.76
5.20
7.59
7.28
7.41 11.25 6.84
9.53
8.38
Contingency 7
2.6
30°
2173
11.10 10.00 5.33
7.77
7.46
7.59 11.52 7.01
9.77
8.58
SKK2
SKK1
*Amplification Factor is number of times the
“Benchmark 1 in 100 Years GMD Magnitude”
39
Slide 39
SKK1
we may call it amplification factor or something like that
SKK2
Not sure what the points from 1 to 10 means rgarding the scaled GEO-electric field. are these the numbers associated with the plots in
the next slide? please explain.
Sameh K.M. Kodsi, 2016/01/19
Sameh K.M. Kodsi, 2016/01/19
SVC Contingency Results – Voltage
Stability
40
System AC Voltage with Reactive
Power Increases – N-0 @ 60° GeoElectric Field Orientation
41
General Discussion
 DC winding resistances were unavailable for 55% of transformers
 Grounding resistance data unavailable for 36% of substations
 Lower voltage (less than 240 kV) network outside of the scope
 Seven transformers exceeded the 75 A per phase threshold
 Preliminary investigation of the system voltage stability performance
under benchmark 1 in 100 years GMD scenario, shows no concern of
voltage instability
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Discussion - Modeling
 Autotransformers provide a path for the GIC to travel between the

high and low voltage sides
Autotransformers represent half of the transformers modeled for this
study
Two Winding Autotransformer DC Equivalent
 Exclusion of low voltage side of transformers may affect total GIC
flows and the associated increase in the reactive power loading.
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Discussion - Autotransformers
 In the PSS®E Program Application Guide: Volume 1 the formula for
effective GIC in a two-winding autotransformer is given as:

 Where:
∗







is the number of turns in the series winding
is the number of turns in the common winding
is the nominal voltage of the high voltage side
is the nominal voltage of the low voltage side
is the GIC current in the series winding
is the GIC current in the common winding
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Discussion - Autotransformers
 The formulation for effective GIC is derived from equating the sum of
the magneto-motive force (MMF) in the series and common windings
to a total MMF for the
transformer
 The sign convention for
GIC in PSS®E results in
and having opposite
signs while in reality these
currents flow in the same
direction through the winding
 When PSS®E performs the calculation for effective GIC the opposite
signs of and result in a cancellation of the MMF in the two
windings when the MMFs are actually in the same direction
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Discussion - Autotransformers
 When the proper sign convention is used in the calculation,
significantly higher values of effective GIC in autotransformers are
observed than what is reported by PSS®E
 Teshmont reported this error to PSS®E and received
confirmation that this will be fixed in future releases
 To complete the study, a script was written to perform the correct
effective GIC calculations for autotransformers
 After the corrections 5 additional transformers (7 in total) were found
to be above the 75 A per phase limit and 288 Mvar of additional
reactive power at the worst-case storm orientation
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Recommendations
 Perform thermal assessments for transformers that exceed the 75
A/phase (IEEE/ANSI C57.163 – C57.91)
 Sensitivity of results to the inclusion of lower voltage networks
 GIC Studies with the inclusion of the entire high voltage network
 PSCAD/EMTDC studies on harmonic generation due to half-cycle
saturation of transformers and interaction with AC filters and SVCs
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THANK YOU!
QUESTIONS?
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