Power System Modeling of GMD Impacts Thomas J. Overbye University of Illinois at Urbana-Champaign [email protected] April 7, 2015

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 packages GIC impact is certainly still an area of research, but tools are here Presentation presents recent results 2

Four Bus Example 3 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.

Mapping Transformer GICs to Transformer Reactive Power Losses 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 this information would need to be supplied by the transformer owner Currently support default values, or a user specified linear or piecewise linear mapping For large system studies default data is used when nothing else is available. Scaling value changes with core type 4

Specifying the Transformer Loss Values in Per Unit 5

Specifying Transformer Losses Scalars in Per Unit 6 Peak (or "crest") value used since this is a dc current base K values are independent of the assumed MVA base or voltage

Specifying Transformer Losses Scalars in Per Unit Example: 345/138 kV transformer with I GIC = 100 amps and K = 1.5; use S base of 100 MVA 7 The use of this per unit approach should be standardized! PowerWorld cases all use the new approach now

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 Uniform electric field assumption initially common More recently sensitivity analysis has been included 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 8

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 9

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 Normalized as 10 Negative of this ratio is defined as

Grounding Sensitivity, 20 Bus System Grounding sensitivities can be computed for a 20 bus system as 11 Values above 0.5 indicate that the local substation resistance is the dominant parameter in determining the GICs at that substation

Grounding Sensitivity, EI System The previous sensitivity values were calculated for 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 12

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 E peak = 8 * * 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 13

PowerWorld GIC Calculations with Geomagnetic Latitude Scaling () 14 Magnetic latitude is about 10 degrees greater than geographic latitude

Earth Resistivity Scalar () 15 Image Source: http://www.naturalhistorymag.com/sites/default/files/imagecache/large/media/200 9/05/0309partner2_jpg_18912.jpg The earth resistivity layers can now be modeled in PowerWorld, allowing different scenarios to be considered

Quantifying Scaling Effect on GICs 16 * A uniform electric field across the whole EI is not a realistic assumption (scenario is purely illustrative)

Parametric Studies GMD analyses of a large scale system Focus on steady-state voltage stability What happens if E max exceeds 8 V/km? Comprising of two parametric studies 1. Effects of including/excluding neighboring regions At which value of E max 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 17

EI System Example 2010 Series, 2012 Summer Case from MMWG/ERAG of the North American Eastern Interconnect (EI) system Bus and substation coordinates added GIC model parameters estimated/assumed Transformer K values Transformer winding resistances from series resistances Substation grounding resistances (SubR) based on number of lines and highest nominal kV (0.1 2.0 ) Estimation method heuristic, we did not have actual values Next slide shows a gradual increase in an Eastward electric field for the entire EI 18

Main Results and Further Analysis Non-convergence at E max = 14.5 V/km ( E max, c ) Collapse occurred in Area A on the East Coast Some other Areas also have low voltage profiles e.g. Northwest portion of EI, and a region to the North of Area A Next, studies focusing on Area A What portion of the system apart from Area A needs to be modeled for voltage stability studies? Considered 1) Only Area A, 2) Tie-line connected Areas, and 3) Whole EI How to account for uncertainties in SubR values? Scaled SubR values by = 1/5, 1/4, 1/3, 1/2, 2, 3, 4, and 5 Regional scaling factors used for these studies 20

E max as Assumed Substation Ground Resistance is Varied 21

E max as Assumed Substation Ground Resistance is Varied 22

Key Takeaways Impacts of size of study system: Study with only Area A losses overestimates the level of E max Including losses of first neighbors of Area A has an effect similar to considering the whole EI Considering individual Areas by themselves may not be sufficient as a worst case scenario, for accurate voltage stability studies Extent of neighboring region that needs to be modeled will be system dependent Next Steps: To formalize how much of the system should be modeled for voltage stability studies 23

Leveraging GMD Analysis to 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 (GMDs), but with quicker rise-times and larger magnitudes 24

HEMP E3 The earths 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 earths 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! 25

HEMP E3 20 bus GIC benchmark case (augmented to include ac parameters and dynamic models) Visualization* Composite E3 Disturbance *preliminary studies First 60 seconds of IEC 61000-2-9 Time varying voltage contours (such as this one) shed light on potential mitigation strategies for preventing grid collapse during HILF events 26

HEMP Power Grid Impact Simulation 27 An interactive scenario is available at http://publish.illinois.edu/smartergrid/Power-Dynamics-Scenarios

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 28

Thank You! 29

Documents

Power System Modeling of GMD Impacts Thomas J. Overbye University of Illinois at Urbana-Champaign [email protected] April 7, 2015