Changes in system

inertia with high

renewable

implementation

1/15/2020

Jon Jensen, Kent

Bolton, Dick Simons

▪ This study was performed through the

System Inertia Task Force (SITF). A group of

stakeholders and subject matter experts.

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SITF

▪ Assess impact on reliability of Bulk Electric System (BES) in the Western Interconnection (WI) as inertia decreases from retirement of coal resources and addition of Inverter Based Resources (IBR) by assessing the following:

• Frequency response

• Reliability impact

• Transient voltage stability

• Impact of IBR with/without frequency response capability

• Crucial contingency changes

• Transmission path loading change

• Short circuit fault duty

• Resource adequacy

• Capital cost of added IBR

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Purpose

▪ 2028 Anchor Data Set (ADS) Phase 2 V2.0

▪ Retire 100% of coal resources

▪ Add Wind/Solar/Battery to replace coal

resources

▪ Select hours of PCM to study in PowerFlow

▪ Dynamic and contingency analysis

▪ Capital cost

▪ Fault current analysis

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Assessment Approach

▪ Alberta

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Resource conversions

Unit Name Capacity, MW

Sheerness_2_2 408

Sheerness1-1 408

Genesee_2_2 422

Genesee1-1 422

Genesee_3_3 527

Keephills3_1 498

Total: 2,685

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Resource retirements

Total of 18,976 MW coal retirements, 21,661 MW including Alberta resource conversions

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Resource Additions

Total of 115,840 MW added capacity

MW Comparison

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Energy Comparison

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PowerFlow hours to analyze

8/4/2028

10/28/2028

▪ Hour 5198 (8-4-2028 hour 14)

• Generation = 135,972 MW

• IBR/Sync = 2.02

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8-4-2028

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Path Flow

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Paths

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Inter-regional transfers

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Inertia

• SITF case has about 62% of the Inertia as the Phase 1 case.• Note MVA on plot does not include IBR MVA, synchronous only.

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Inertia

• We see decreased inertia where coal was removed

• Other differences due to dispatch/load differences between cases

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System Cost $/MW for a 1MW System-E3

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Capital Cost

Capital Cost – 2023 Install year

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▪ Levelized Cost of Energy (LCOE) represents the energy price

output needed to recuperate the cost of the plant over its

estimated lifetime. CCGT has an LCOE of about $48/MWh

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LCOE-Energy Price $/MWh

▪ Plot shows decreasing

fault current only

▪ IBR vs Synch machine

fault current

▪ Difference in 28HS1 vs

SITF (Dispatch difference)

▪ Reliability concerns

▪ Geographic information

system (GIS) data for

about half of the busses

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Fault Current

The Standard Disturbances include:

▪ Chief Joe Brake insertion

• Insertion for 30 cycles and then removal of the large braking resistor in the Northwest

▪ Double Palo Verde Outage

• Simultaneous tripping of two Palo Verde generation units

▪ Colorado River Red Bluff Outage

• 3 phase fault with tripping of two transmission lines in Southern California

▪ Gates – Midway and Diablo-Midway Outage

• 3 phase fault with tripping of three transmission lines in Northern California

▪ Brownlee – Hells Canyon Outage

• 3 phase fault with tripping of one large transmission line in Idaho. This includes the approximation of an associated Remedial Action Scheme (RAS).

▪ Daniel Park – Comanche Outage

• 3 phase fault and then tripping of two large transmission lines in Colorado

▪ Pacific DC Intertie (PDCI) Block

• Simulates a block (removal of the lines from service) of the DC line from Celilo (in the Northwest) to Sylmar (in Southern California)

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Dynamics

Dynamics double PV outage (units 1 & 2)

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f nadir f delt response RoCoF

ADS 59.86461 0.136112 2018.335 -0.027

SITF 59.77664 0.223797 1168.739 -0.13564

F nadir is in Hz, fdelt is in Hz, f response is in MW/.1 Hz and RoCoF is in Hz/s.

▪ Six times as much IBR generation capacity

needed to replace the coal capacity due to

capacity factor differences.

▪ …

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Observations

▪ Updating all Short Circuit Model busses with GIS data to more fully represent system on map plot;

▪ Completing additional Short Circuit analysis in CAPE/Aspen where one case has all coal removed and the other one includes coal to include Zero and Negative sequence;

▪ Completing autumn Power Flow and dynamics analyses;

▪ Studying dynamics where frequency response and voltage regulation capability is turned on for all IBR;

▪ Evaluating differences in Path flow loading and run contingencies on related loaded paths;

▪ Analyzing in greater depth the impact on reliability from the addition of energy storage (Batteries/CAES);

▪ Evaluating possible mitigation techniques for path overloads; and

▪ Optimizing the system for the best mix of energy storage and renewables.

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Recommendations

Contact:

Jon Jensen

Kent Bolton

Dick Simons

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