TASK 2 · 2020-06-12 · Task 2.1 Work Package 3 What scarcities to look for? Task 2.2 Scenarios &...

TECHNICAL SHORTFALLS FOR PAN-EUROPEAN POWER SYSTEM

WITH HIGH LEVELS OF RENEWABLE GENERATION

This project has received funding from the European Union’s Horizon 2020 research and innovation programme under grant agreement No 773505.

1

TASK 2.4

2

Why?

What?

How?

Outcomes

So what?

INTRODUCTION

METHODOLOGY

CONCLUSIONS

AGENDA

RESULTS

INTRODUCTION

3

8 Minutes

5

“Perform detailed technical analysis to assess the potential existence of the technical scarcities in a 2030 power system

with high levels of renewables.”

System congestion System restoration

Dynamic voltage control Rotor angle stability

Frequency stability & control Steady state voltage control

Ireland & Northern Ireland Power System

Continental European System

Nordic Power System

METHODOLOGY

7

4 Minutes

8

Scenarios (Future system configuration)

Snapshots for analysis

Models

Analysis

Stimuli

Conclusions Evaluation on

indices

Lim

itatio

ns

Every nth hour Specific conditions Every hour

SYSTEM

CONSIDERED CORE SCENARIOS NETWORK SENSITIVITIES

Nordic system Energy

Transition

Renewable

Ambition

High

Solar -

Poland and

neighbours

Energy

Transition

Renewable

Ambition

Going

Green

Distributed

Renewables

Ireland and

Northern

Ireland

- Steady

Evolution

Low Carbon

Living

RESULTS

9

10

Nordic System Ireland &

Northern Ireland Continental

Europe 10

Frequency stability & control EDF VTT

Steady state voltage control PSEi EirGrid & SONI

Dynamic voltage control PSEi EirGrid & SONI

Rotor angle stability PSEi EirGrid & SONI

System congestion NCNR EirGrid & SONI

System restoration EirGrid & SONI

Steady state voltage control PSEi

Dynamic voltage control PSEi

Rotor angle stability PSEi

System congestion NCNR

System restoration

EirGrid & SONI

11

Frequency Stability & Control

Continental Europe

Frequency stability & control EDF

EDF

5 Minutes

12

Scenarios Stimuli & analysis method Study type

1. Energy Transition (ET) 2. Renewable Ambition (RA)

Time domain simulation • Interconnected incidents:

loss of 2 GW of generation in each zone

• 3 system split configurations

Every hour across the year

aFRR sizing Every hour across the year

13

Interconnected incidents: loss of 2 GW of generation in each zone*

Zone

Energy Transition Renewable Ambition

NADIR < 49 Hz

ROCOF > 1 Hz /s

NADIR < 49 Hz

ROCOF > 1 Hz /s

PL + CZ + SK + HU 0% 0% 0% 0%

ES + PT 0% < 1% 0% ~ 9%

IT 0% 0% 0% 0%

FR 0% 0% 0% 0%

DE + neighbours 0% 0% 0% 0%

ROCOF analysis:

- Maximal ROCOF values in the Iberian Peninsula: 1.3 Hz/s.

- ROCOF values are highly correlated with very high share of VRES (up to 90%

of the instantaneous Iberian generation).

*The loss of 3 GW of generation was also simulated in

France, with similar results.

14

3 system split configurations Iberian peninsula Italy Europe in 3

Splitting event

Energy Transition Renewable Ambition

NADIR < 47.5 Hz

ZENITH > 51.5 Hz

ROCOF > 1 Hz /s

NADIR < 47.5 Hz

ZENITH > 51.5 Hz

ROCOF > 1 Hz /s

Iberian Peninsula 0% 0% ~ 38% < 1% ~ 15% ~ 85 %

Italy < 1% < 1% ~ 58% < 1% ~ 2% ~ 49%

Europe in 3 0% 0% ~ 1% 0% 0% ~ 26%

Hypothesis: the power imbalances after the split are equal to the border power flows before the split (including HVDC links)

15

3 system split configurations

Zoom on the Iberian peninsula split

Imbalances up to +/- 40% of load for the worst hours

ROCOF > 2 Hz/s in most cases

16

3 system split configurations

Zoom on the Iberian peninsula split

Many nadir values < 49 Hz load shedding is activated Several nadir values < 47,5 Hz risk of blackout

Zenith values up to 53 Hz LFSM-O is not sufficient

More details in 2020 CIGRE paper C4-658, ”Assessment of the dynamic frequency stability of the future Continental Europe power system – Interconnected incidents and system splits”

17

aFRR sizing

For a given level of risk taken by the TSO, the average and extreme aFRR needs will increase with the penetration of VRES.

aFRR duration curves, Renewable Ambition scenario, risk level = 1%

More details in 2019 Wind Integration Workshop paper, ”Probabilistic estimation of the aFRR requirement in the future European power system with high RES penetration”

18

Key outcomes

Interconnected incidents

• For all zones of the Continental system, frequency nadir values for interconnected incidents seem to be manageable, as they stay above the first load-shedding threshold

• ROCOF values are more problematic, as they can reach 1,3 Hz/s and very few systems can currently run with such high levels of ROCOF

System splits

• Classical frequency control mechanisms are not sufficient for dealing with such events

• Even load shedding and LFSM-O, as modelled in the study, are not always sufficient to avoid black out situations

aFRR requirements

• The transition to higher penetrations of variable renewables results in a higher requirement for aFRR, and the annual variability requirement also increases

19


Ireland & Northern Ireland

Continental Europe

Frequency stability & control EDF EirGrid & SONI

EirGrid & SONI

4 Minutes

20


1. Low carbon living (LCL) 2. Steady evolution (SE)

• Economic dispatch analysis Every hour across the year

• Time domain simulation - Loss of infeed - Loss of outfeed/export

Every 7th hour across the year

• Inertia scarcity index: Evaluated through least cost dispatching, RoCoF used as index

• Reserve adequacy index: For both speed and magnitude of reserve provision, evaluation through time domain simulations, frequency nadirs and zeniths as index

0

1

2

3

4

5

6

0 1000 2000 3000 4000 5000 6000 7000 8000

Ro

Co

F (

Hz/s

)

2030 LCL MARUN 2030 LCL EOC

21

• Multiple models for each scenario: Market run (MARUN), enhanced operation (EOC) • Inertia scarcity demonstrated: Excessive RoCoF indicates lack of inertia

• RoCoF constrained dispatches used: The scarcity is mitigated beforehand to enable time domain simulations

With RoCoF Constraint

Without RoCoF Constraint

22

• For LCL scenario: No significant scarcity – only 0.6% cases below 49 Hz, Mean = 49.52 Hz • Improvement in nadirs: Generally higher SNSP , improving frequency nadirs

• Underlying factors: 1) Increasing renewable reduces LSI, 2) Fast dynamic reserve

• Important assumptions: Current FFR product modelled, significant quantity of fast dynamic reserve

• SE scenarios: Lower RES, less interconnection and smaller fast reserve magnitudes • For SE scenario: Worse – 4% cases below 49 Hz, Mean = 49.42 Hz

• Underlying factors: Smaller fast reserve levels

23

• Inertia scarcity found and mitigated before time domain simulations

• Higher renewable scenario characterised by higher interconnection and higher fast dynamic reserves shows better under-frequency performance

• Fast dynamic reserves are critical for system stability, a fast reserve product helps enormously – current FFR product included in simulations

• Abundant fast reserve resources can mask the gaps in scheduling practices occurring due to changing reserve portfolio and system conditions

• Need for revision of scheduling practices, catering for changes in reserve portfolio identified.

Key outcomes

24



Europe

Frequency stability & control EDF EirGrid & SONI VTT


VTT 4 Minutes

25


1. Energy Transition (Sysflex core scenario)

2. High solar (Nordic sensitivity)

3. Renewable Ambition (Sysflex core scenario)

Time domain simulation • Interconnected incidents: loss

of generation equal to the dimensioning incident


Nordic analysis: Introduction

26

Power system

model

(Simulink)

Frequency

nadir

Frequency

rate of

change

Dimensioning

incident

Dispatch model

Frequency nadir

27

Energy Transition High Solar Renewable Ambition

Rate of change of frequency

28

Energy Transition High Solar Renewable Ambition

Effect of fast frequency reserve

• Addition of 200 MW FFR produces a small increase in frequency nadir

29

30



Europe 30











System restoration

31

Steady State Voltage Control

Continental Europe

Steady State Voltage Control PSEi

PSEi

6 Minutes

32

Scenarios Stimuli & analysis method

Study type

1. Energy Transition (ET)

2. Going Green (GG)

3. Distributed Renewables (DR)

• Load flow analysis - intact system - N-1 conditions

Selected snapshots

• Short circuit analysis - intact system - n-1 conditions

Selected snapshots

• P-V Analysis - intact system - n-1 conditions

Selected snapshots

• Q-V Analysis - intact system - n-1 conditions

Selected snapshots

33

Capacity scenarios for CE (Going Green)

+ more

RES in PL

=

34

Capacity scenarios for CE (Distributed Renewables)

+ some RES in

PL are moved to the radial

DS

=

35

Operation snapshots for CE

+ = Maximum load snapped (/4)

Maximum load snapped (/3) Maximum load snapped (/2)

Maximum load snapped (/1)

Capacity scenario

Worst cases under study: • Maximum Load

• Minimum Inertia • Minimum Reactive

power margins for the Synchronous Generation

36

Contingencies and disturbances

Very detailed model representing EHV and 110 kV power

grid Simplified model representing EHV power grid

Equivalent models

Contingencies and disturbances

37

Steady-state voltage deviation analysis

• All network contingencies have been assumed in Polish power system owing to the detailed representation of power grid used for Poland.

• Analysis has been focused on 110 kV network in Poland, especially the nodes to which passive and active radial distribution systems are connected.

• Problems of low voltage levels occur particularly in the Maximum Load operational snapshots (with relatively low SNSP).

• The highest number of 110 kV nodes for which the voltage is below 0.9 p.u. are observed for the Going Green capacity scenario.

• The impact of reduced voltage regulation due to higher RES generation becomes apparent at high load conditions.

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rtia

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ctiv

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2

DR

/Min

_Rea

ctiv

e/3/

4

SN

SP

(%)

Num

ber

of 1

10 k

V n

odes

Number of 110 kV nodes for which V < 0,90 (N-1) SNSP

0

10

20

30

40

50

60

70

0,75

0,8

0,85

0,9

0,95

1

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ctiv

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SNSP

(%)

Vo

lta

ge

(p

.u.)

Min. voltage [p.u] of 110 kV node (N-1) SNSP

FIGURE : SNSP AND NUMBER OF 110 KV NODES FOR WHICH V < 0.90 P.U. (N-1)

FIGURE: SNSP AND MIN. VOLTAGE [P.U.] OF 110 KV NODES (N-1)

38


• Minimum Inertia and Minimum Reactive snapshots show increased over-voltage deviations, although this issue is observed across all snapshots and scenarios.

• The highest numbers of nodes with over-voltage issues correspond to the Going Green scenario.

• The highest values of over-voltage at 110 kV nodes are observed in the Distributed Renewables scenario.

• The key factor affecting steady-state voltage issues is the power demand.

• Due to the fact that Minimum Inertia and Minimum Reactive snapshots are much closer to the minimum load time, more over-voltage problems can be observed.

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/Min

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ea

ctiv

e/3

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SN

SP

(%)

Num

ber

of 1

10 k

V n

odes

Number of 110 kV nodes for which V > 1,1 (N-1) SNSP

0

10

20

30

40

50

60

70

1,11,111,121,131,141,151,161,171,181,19

1,2

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/Max

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ad

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ctiv

e/3

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SN

SP

(%)

Vo

lta

ge

(p

.u.)

Max. voltage [p.u] of 110 kV node (N-1) SNSP

FIGURE: SNSP AND NUMBER OF 110 KV NODES FOR WHICH V > 1.1 P.U. (N-1)

FIGURE: SNSP AND MAX. VOLTAGE [P.U.] OF 110 KV NODES (N-1).

39


• Higher RES level causes not only changes in the number and magnitude of voltage deviations but also shifts the problem from one location to another.

• When RES generation increases, the voltage problems are shifted from Central and South-West to the North-East and the North-West parts of the Polish power system in the Going Green and Distributed Renewables scenarios, respectively.

• It has been also observed that increasing RES impacts upon the magnitude of voltage values without causing significant changes in spatial distribution for the Distributed Renewables capacity scenario.

higher 𝑆𝑁𝑆𝑃

higher 𝑆𝑁𝑆𝑃

40

Voltage Stability analysis

• The Voltage stability margins in Polish part of CE power system have been assessed with the use of the Power-Voltage (P-V) Curve method.

• The voltage is a function of active power in this area from operational point up to the loss of load flow convergence.

• Voltage stability margins within Polish Power System have been calculated for all investigated scenarios and operational cases, including (N-0) and (N-1) states.

• Relatively high correlations between voltage stability margin and the load level occur in the Energy Transition and Going Green scenarios.

• A secondary factor having impact to increasing the voltage stability margin is the renewables generation which change the load in power network elements.

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SNSP

(%)

Vol

tage

sta

bilit

y m

argi

n (%

)

Stab. margin (N-0) Stab. margin (N-1) SNSP

FIGURE: SNSP AND VOLTAGE STABILITY MARGINS CALCULATED FOR POLISH POWER SYSTEM

41


• In order to obtain the P-V Curves, the load was increasing in particular ODMs individually.

• For (N-1) states there are two cases in which divergence of the load flow has been obtained.

• Districts having remote generation (both conventional and renewable) are characterised by lower voltage stability margins.

FIGURE: APPROXIMATE LOCATION OF DISTRICTS OF POLISH REGIONAL TSO’S CONTROL CENTRES.

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05

101520253035404550

SN

SP

(%)

VO

LTA

GE

STA

BIL

ITY

MA

RG

IN (%

)

Stab. margin (ODM 1) Stab. margin (ODM 2) Stab. margin (ODM 3)

Stab. margin (ODM 4) Stab. margin (ODM 5) SNSP

FIGURE: SNSP AND VOLTAGE STABILITY MARGINS CALCULATED FOR DISTRICTS OF POLISH REGIONAL TSO’S CONTROL CENTRES (N-1).

ODM 1

ODM 2ODM 3

ODM 4

ODM 5

42


• Q-V curves present the relationship between the reactive power injected into a power network node and the nodal voltage level.

• For all scenarios and operational cases, the weakest 110 kV nodes have been identified within all the critical zones and selected for the Q-V curve analysis.

• (N-1) contingency states for various snapshots have been analysed for the purpose of Q-V curve calculation.

• In general, the scenarios characterized by high RES capacity entail a higher risk of nodal voltage in-stability. FIGURE: Q-V CURVES FOR ONE OF THE ANALYSED 110 KV NODES.

43

Steady-state voltage control– Key outcomes

• EHV system in Poland remains relatively un-effected by increasing RES levels across the Continental European System.

• However, the 110 kV Polish system exhibits a lack of steady state reactive power capacity, as demonstrated by deteriorating steady state voltage regulation.

• The reactive power scarcity becomes most apparent at high load and minimum inertia conditions.

• P-V analysis across various zones of the Polish system demonstrates that within the subnetworks of the Polish system, regions with higher magnitude of installed renewable capacity, shows a trend towards diminishing stability margins.

• Q-V analysis on the Polish system demonstrates that the scenarios characterised by high RES capacity exhibit a higher risk of potential nodal voltage instability.

44

Steady State Voltage Control


Continental Europe

Steady State Voltage Control PSEi EirGrid & SONI

EirGrid & SONI

6 Minutes

45


1. Low carbon living (LCL)

2. Steady evolution (SE)

• Load flow analysis - intact system - n-1 conditions


• Short circuit analysis - intact system - n-1 conditions


• QV Analysis - intact system - n-1 conditions


46

Steady State Voltage Control Steady state voltage deviations

• Evaluation index: Steady state voltage deviations for steady state reactive power scarcity

• Increase in renewable generation causing higher deviations • Trend observed due to reduction in reactive capacity due to displaced conventional gen.

• Higher renewables scenario, amplifies the deficiency in steady state reactive power

47

Steady State Voltage Control QV analysis

• Evaluation index: MVARs required to attain a pre-define voltage

• Trend: MVAR requirement increases with SNSP – general lack of MVARs

48

Steady State Voltage Control Short circuit analysis

• Evaluation index: Short circuit power or MVA level is used as index • Results presented for a strong & a week bus

Week bus trend: Initial increase in fault level, followed by sharp decline Strong bus trend: Not as clear due to frequent generation dispatch

49

• The results of voltage deviation analysis are supported by QV analysis

• Clear trend of increasing renewables causing reduced steady state reactive capacity – scarcity has been identified

• System short circuit levels are significantly reduced at high renewable generation levels, implications for protection & stability

• Weaker & renewable energy dominant parts of the network need consideration, this can be done in a number of ways, possibly using a reactive power product

Key outcomes

50



Europe 50











System restoration

51

Dynamic Voltage Control

Continental Europe

Dynamic Voltage Control PSEi

PSEi

5 Minutes

52


Study type


2. Going Green (GG)


• Time domain simulations - Short circuit faults

Selected snapshots

53

Fault Ride-Through (FRT) analysis

• The obtained voltage waveforms have been compared with the Low Voltage Fault Ride-Through (LVRT) profiles required by the RfG network code.

• For the purposes of analysis following sets of disturbances have been assumed:

• 150 ms self-clearing close 3-phase short circuit in transmission lines leading out of a power plant station, as regards SGMs.

• 150 ms self-clearing 3 phase short circuit at the point of common connection (PCC), as regards PPMs.

• A set of the largest PPMs within the whole Polish power system and selected two critical zones regarding steady-state voltage stability, have been selected for the test simulations.

FIGURE: FRT RESPONSES FOR SGMS (SELECTED EHV BUSBAR OF KOZIENICE POWER PLANT STATION, 150 MS SELF-CLEARING 3 PHASE SHORT CIRCUIT).

54

Fault Ride-Through (FRT) analysis

• In order to assess how outages may influence the LVRT capability of non-synchronous generators, critical contingencies identified in the voltage control analyses, also have been applied to the pre-fault power system operation state.

• All the analysed D-type wind farms and active distribution systems (B and C-type PPM generation included) have the FRT capability implemented in their control systems.

• For PPMs there have been no significant impact observed of different operational cases (resulting in different SNSP) to FRT responses.

FIGURE: FRT RESPONSES FOR PPM (SELECTED PCC OF D-TYPE PPM, GOING GREEN SCENARIO).

FIGURE: FRT RESPONSES FOR PPM (SELECTED PCC OF C-TYPE PPM, DISTRIBUTED RENEWABLES SCENARIO).

55

Dynamic Voltage Control– Key outcomes

Fault Ride Through analysis:

• As a result of the analysis, no LVRT requirement violations have been observed in the transient simulations.

• The FRT response curves for SGMs and PPMs within Maximum Load operational snapshots tend to have less oscillation than for Minimum Inertia and Minimum Reactive ones.

• Following differences between FRT plots representing Maximum Load and other operational snapshots can be explained by greater power system stiffness, related to lower 𝑆𝑁𝑆𝑃 level values.

• A clear indication of a lack of dynamic reactive injection capacity in the Polish system as a subset of the Continental European system is not apparent.

• An absence of dynamic reactive power scarcity for Continental European system at higher renewable energy levels cannot be concluded.

56

Dynamic Voltage Control


Continental Europe

Dynamic Voltage Control PSEi EirGrid & SONI

EirGrid & SONI 5 Minutes




• Time domain simulations - Short circuit faults,

cleared by line tripping

Selected snapshots

Case Selection

58

Which of the 8760 hours from each scenario to focus upon?

Split 8760 based on: • SNSP • Inertia • Large gen.

near load centres

TYPE 1

TYPE 2

Each of the 8 types is high or low in terms of these three measures

How does the scarcity manifest?

59

Larger voltage drops that propagate further after any contingency on the system (e.g. line faults)

None

Localised

Global

Can be localised in terms of: • contingencies, or • conditions

Can be specific or systematic

Illustrative voltage traces for a fault

Measuring the scarcity…

60

Bus 1:

1 unique violation

No delayed recovery

Bus 3:

1 unique violation

Delayed recovery

1. Unique Violations

2. Early Recovery

How far did the fault ‘spread’

Understand VAr s provided during fault

0.5 p.u. threshold applied

Bus 2:

1 unique violation

Delayed recovery

Bus 4:

No unique violation

No delayed recovery

Unique Violations – LCL

61 Network model has ~1300 buses

SNSP < 10%

SNSP >80%

SNSP from 20% t0 80%

Global scarcity Localised scarcity

Minimal Scarcity

Box plot of unique violations for 306 contingencies for each snapshot

SNSP doesn’t tell the whole story

Early Recovery – LCL

62

Box plot of early recovery (% )for 306 contingencies for each snapshot

More early recovery as SNSP increases

SNSP < 10%

SNSP >80%


What this looks like…

Same contingency for a Type 1 and Type 2 Hour 63

A more volatile voltage profile

Exhibiting fast recovery from a wide ranging initial dip

Would system really survive these swings?

How long a delay can be tolerated?

Type 2 recovers to similar voltage as

Type 1 on-fault

Type 1 Type 2

What this means…

64

Conclusions are valid, but large voltage swings call into question the security of the system

Are modelling limitations masking mass converter trips?

What is the winder system impact of delayed recovery?

How long a delay can be tolerated?

A global scarcity of dynamic voltage control is emerging

Widespread localised issues for contingencies and hours of operation

Scarcity is driven by the location of synchronous machines

Is a detailed issue and while low SNSP leads to more areas with no synch. Gen., attempts to analyse/manage through lens of SNSP may fail

65



Europe 65











System restoration

66

Rotor Angle Stability

Continental Europe

Rotor Angle Stability PSEi

PSEi 5 Minutes

67


Study type


2. Going Green (GG)


• Time domain simulations

- Short circuit faults Selected snapshots

68

Critical Clearing Time analysis

FIGURE: C|K3|1C CLOSE 3 PHASE SHORT CIRCUIT ELIMINATED BY LINE

TRIPPING AT NORMAL CLEARING TIME 𝒕𝐈 = 𝟏𝟎𝟎 𝐦𝐬.

FIGURE: C|K3|2C CLOSE 3-PHASE SHORT-CIRCUIT IN A DOUBLE-CIRCUIT LINE

ELIMINATED BY LINE TRIPPING AT NORMAL CLEARING TIME 𝒕𝐈 = 𝟏𝟎𝟎 𝐦𝐬

FIGURE: F|K3|1C FAR 3 PHASE SHORT CIRCUIT ELIMINATED BY LINE TRIPPING AT

IMPEDANCE RELAY II ZONE (85% LINE LENGTH) CLEARING TIME 𝒕𝐈+ = 𝟏𝟐𝟎 𝐦𝐬 FROM

THE POWER STATION SIDE OF LINE AND NORMAL CLEARING TIME 𝒕𝐈 = 𝟏𝟎𝟎 𝐦𝐬 FROM

THE OTHER END OF LINE SIDE.

FIGURE: C|K3|B PHASE SHORT-CIRCUIT IN A BUSBAR SYSTEM ELIMINATED AT

NORMAL CLEARING TIME 𝒕𝐈 = 𝟏𝟎𝟎 𝐦𝐬.

𝑘t =𝑡cr − 𝑡I

𝑡I⋅ 100%


𝑡I⋅ 100%


𝑡I⋅ 100%

𝑘t =𝑡cr − 𝑡I+

𝑡I+⋅ 100%

• Critical clearing times 𝑡cr, described as the longest clearing times for which a power system will remain in synchronism, have been calculated using a binary search method:

69


• The selected disturbances have been applied on the transmission lines and busbars in the EHV substations transferring power from the biggest conventional Polish power plants.

• Transient stability analysis covers 9 operation snapshots for each of the 163 considered fault event contingencies.

• For each of the analyzed scenarios, median values for the CCTs tend to be the highest for the Maximum Load operational snapshots.

• The larger the active power demand is, the larger the number of synchronous generators operating, which leads to the increase of the inertia level in the power system.

FIGURE: C|K3|1C CRITICAL CLEARING TIME RESULTS – BOX PLOTS.

FIGURE: C|K3|2C CRITICAL CLEARING TIME RESULTS – BOX PLOTS.

70


• Generally, Minimum Reactive and Minimum Inertia operational cases simulation results tend to be comparable, but lower than corresponding values for the Maximum Load.

• The lower the reactive power generation is, the lower the voltages of generators are, which causes the decrease of transient stability margin.

• The overall power systems’ inertia is being reduced for the Minimum Inertia, and Minimum Reactive operational cases, due to the higher renewables penetration.

FIGURE: F|K3|1C CRITICAL CLEARING TIME RESULTS – BOX PLOTS.

FIGURE: C|K3|B CRITICAL CLEARING TIME RESULTS – BOX PLOTS.

71

Oscillation damping analysis

• For the purposes of oscillatory stability analysis, settling and halving times have been calculated in order to assess the damping of inter-area and inter-plant oscillations.

• Settling and halving times have been calculated for close 3-phase short circuit disturbances in which clearing times are assumed to be 100 ms.

• High penetration of renewables and decrease of the synchronous generation cause significant issues with an oscillation damping.

• For each of the analysed capacity scenarios, both halving and settling time median values tend to be lowest for the Maximum Loads operational snapshots, due to low SNSP level.

FIGURE: HALVING AND SETTLING TIMES DEFINITION.

FIGURE: HALVING TIMES– BOX PLOTS.

FIGURE: SETTLING TIMES– BOX PLOTS.

72

Oscillation damping analysis

• The overall power systems’ inertia is being reduced for the Minimum Inertia and Minimum Reactive scenarios, due to the higher renewables penetration, instead of synchronous generation.

• The lower the reactive power generation is, the lower the voltage of generators connected at the power plant are, which causes reduced oscillation damping.

• In the first two seconds of the simulation inter-plant oscillation components are more noticeable (approximately 1,42 Hz), then the nature of the oscillations turns to inter-area values (from 0,63 Hz for Maximum Load to 0,76 Hz for Minimum Inertia and Minimum Reactive).

• High penetration of synchronous generation due to the higher active power demand helps to better damp power systems oscillations.

FIGURE OSCILLATIONS DAMPING – ROTOR ANGLE PLOTS FOR VARIOUS OPERATION SNAPSHOTS.

73

Rotor Angle Stability – Key outcomes

Critical Clearing Times analysis:

• The analysis of critical clearing time shows no emergence of a localised scarcity in stability margin when assessed in terms of the expected primary protection operation times. All the obtained critical clearing times met the grid requirements.

• There is also no evident trend in transient stability margins in the function of capacity scenario.

• Performed analysis has shown that the local conditions of synchronous generation (generator operation point, the nearest network topology and configuration, other synchronous units committed in the vicinity) determine the synchronous torque.

74

Rotor Angle Stability – Key outcomes

Oscillation damping analysis:

• Oscillation damping presents a global scarcity with poor settling and halving times for all cases and scenarios.

• Time-domain simulations have identified the poor oscillation damping during severe system disturbances, such as three-phase short-circuit events, with only the Maximum Load cases having any significant number of acceptable settling and halving times.

75

Rotor Angle Stability


Continental Europe

Rotor Angle Stability PSEi EirGrid & SONI


76




• Time domain simulations - Sort circuit faults

Selected snapshots

Case Selection

77

Which of the 8760 hours from each scenario to focus upon?

Split 8760 based on: • SNSP • Inertia • Large gen.

near load centres

TYPE 1

TYPE 2

Each of the 8 types is high or low in terms of these three measures

How does the scarcity manifest?

78

Reduced synchronising and damping torque Loss of synchronism and larger oscillations

One generator or a small group oscillate or separate

Large groups oscillate or separate

None

Localised

Global

Angle Margin

79

How often does angular instability occur?

Localised instability

SNSP < 10%

SNSP >80%


Measure spread of machine angles : η= ((360- δmax) / (360+δmax)) ×100

Stable when AM > 0

Unstable unit

Critical Clearing Time

80

Do we clear faults fast enough?

The longest fault clearance time for which the system remains stable

Absolute worst case clear time is 25 cycles

Localised issue for backup protection

76% cases have CCT above 70 cycles

SNSP < 10%

SNSP >80%


Decay Time Constant

81

Time required for oscillation magnitude to decay to 36.8% of initial value

Acceptable if < 7 seconds

Localised issue emerging

Issue volatile with SNSP…

SNSP < 10%

SNSP >80%


Do we have enough damping?

What this means…

82

Further study required to

• Would protection pick up?

• Are generator models detailed enough to capture stresses placed upon then with only 4 units online?

• How to define a synchronising torque requirement

• Will certain units risk becoming undispatchable without support?

A localised scarcity of rotor angle stability is emerging

Systematic shortfall of synchronising and damping torque for certain units

Scarcity is driven by the location of synchronous machines

Certain machines or small groups to become isolated in weak parts of the network. More severe in steady evolution.

83



Europe 83











System restoration

84

System Congestion

Continental Europe

System Congestion NCNR

NCNR 5 Minutes

85


Distributed Renewables (DR) Energy transition (ET) Going Green (GG)

Load flow analysis (N-0) Decomposition of Load Flow (Power Flow Coloring)

21 timestamps (7 per a scenario) differenciated by load level, inertia and reactance

Background – Cross-border congestion management • Market allocated flows and real flows differ significantly

• This difference can increase due to higher integration of the renewables (uncertainty).

• The difference is called unscheduled flow

Do we need coordination of XB remedial actions for the future power system?

Coordinated remedial actions are the most efficient

Remedial actions (inter-TSO) are needed

Unscheduled flows can create congestions

86

Import/Export Transit

Loop flow Scheduled Flow

UNSCHEDULED FLOW

Allocated Flows

UAF

(prepared by EDF)

Unscheduled Flow – interpretation and results

4

6 5

Unscheduled flow

Results (cross-border CEE)

87

• The results show that the magnitude of unscheduled flows is scenario-dependant and can vary from 500 MW to 4000 MW

• For some borders, correlation of UF is visible. General direction of UF in the region is North to South.

• Power Flow Coloring is used for identification of unscheduled flows. The method is compliant with the ENTSO-E flow type definitions.

Unscheduled Flows – interpretation and results

88

System Congestion


Continental Europe

System Congestion NCNR EirGrid & SONI


89




• Load flow analysis - intact system - n-1 conditions


• Congestion context: The context of congestion is different to Continental system

• Congestion index: Thermal overloading metric

90

I. Overloading increment with SNSP: Density as well as magnitude II. Summer vs Winter: Load decreases in summer, but so does the thermal rating III. Nominal congestion for above 220 kV network: Renewable location impact IV. Overload mechanism: Renewables feeding far away load centres, lack of local absorption V. Higher renewable scenario: Amplifies all the effects

91

• Clear trend of increasing renewables causing increased congestion – global scarcity identified

• Congestion driven by a lack of transmission paths from renewables to load centres and an absence of local absorption

• Wind farm collector networks (110 kV here) need to be managed, this can be done in a number of ways, network upgrades and/or a congestion product among the options

Key outcomes

CONCLUSIONS

96

7 Minutes

97

RoCoF (dimensioning incident)

Localised concern Inertia Scarcity No Scarcity

RoCoF (System split)

Frequency containment (dimensioning incident)

Frequency containment (System split)

Steady State voltage Regulation

Fault level

Continental Europe Ireland & Northern

Ireland Nordic System

Global concern Not applicable

Evolving Characteristic Evolving Characteristic Evolving Characteristic

Global concern Not applicable

S.S reactive power Scarcity

S.S reactive power Scarcity

No Scarcity Dynamic reactive injection scarcity

Not analysed

Not analysed

Scarcity Concern Evolving Characteristic

• Various aspects of system stability in view of increasing renewable generation levels are analysed.

• Due to varying nature of systems under consideration, the inter-system comparison in terms of just the presence or absence of a scarcity does not tell the complete story.

• Therefore, the results for system stability aspects can be categorised into:

98

Rotor angle margin Localised concern

System congestion

System restoration

Transmission Capacity Scarcity

Global concern

Evolving Characteristic Not analysed

Not analysed

Dynamic voltage regulation

Critical clearing times

Oscillation damping

No Scarcity Dynamic reactive injection scarcity

Evolving Characteristic Evolving Characteristic

Damping Scarcity Damping Scarcity

Not analysed

Continental Europe Ireland & Northern

Ireland Nordic System

• Ireland & Northern Ireland system is witnessing the renewable generation impacts, while the continental system generally appears to be evolving towards them

99

• Multiple scarcities identified clearly for Ireland & Northern Ireland system

• For continental system, some scarcities and areas of concern have been identified. An evolution of system needs is apparent

• Lack of a clearly evident system scarcity, does not imply the absence of a scarcity altogether

• The manifestation of scarcities depends on the choice of focus area, snapshot selection, renewable energy levels and stimuli used

• Where identified the system scarcities can potentially be mitigated through system services, underpinned by a well considered regulatory and economic framework

• The studies relied on RMS models, the analysis was therefore limited to electromechanical transients & synchronous frequency ranges.

Conclusions

100

Task

2.4

S

carc

ity

iden

tifi

cati

on

& a

nal

ysis

Work Package 3 Task 2.1 What scarcities to look for?

Task 2.2 Scenarios & sensitivities

Task 2.3 Models & analysis to be run

Work Package 10

Task 2.6

Inputs

This project has received funding from the European Union’s Horizon 2020 research and innovation program under grant agreement No 773505.

Thank You!

Questions?

101

TASK 2 · 2020-06-12 · Task 2.1 Work Package 3 What scarcities to look for? Task 2.2 Scenarios &...

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