Integration of Renewable Based Generation into Sri Lankan Grid 2017-2028
Eng. Dr. H. M. Wijekoon, Chief Engineer Transmission Planning Eng. Buddhika Samarasekara, Chief Engineer (Generation Planning) Transmission and Generation Planning Branch Transmission Division Ceylon Electricity Board Sri Lanka
ANNUAL RENEWABLE ENERGY CAPACITY ADDITIONS MW 400
Average Annual Absorption 37 MW / year
Average Annual Absorption 145 MW / year
350
300
250
200
ANNUAL RENEWABLE ENERGY CAPACITY ADDITIONS
150
100
50
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037
0
Year
Average Annual Absorption of Other Renewables is nearly four times higher than the past. 2
Requirement of RE integration Study NCRE generation especially intermittence based sources like wind and solar power cannot be controlled Energy from these types of generating facilities must be taken “as delivered”, which necessitates the use of other controllable resources. Conventional resources must then be used to follow the net of electric demand and NCRE energy delivery. Conventional recourses also provides essential services such as regulation and contingency reserves that ensure power system reliability. To the extent that NCRE based generation increases the required quantity of these generating services, additional costs are incurred.
The questions to be addressed in NCRE integration ď ą To what extent would NCRE generation contribute to the electric supply capacity needs for CEB? ď ą What are the costs associated with scheduling and operating conventional generating resources to accommodate the variability and uncertainty of NCRE based generation?
NCRE integration study Summary
OTHER RENEWABLE ENERGY Present Status (as at 28th February 2017) No of Projects
NCRE Technology 1 Mini Hydro Power
Capacity (MW)
178
349.64
4
13.08
3 Biomass - Dendro Power
5
11.02
4 Solar Power
7
41.36
5 Wind Power
15
123.85
209
543.5
2
Biomass - Agricultural & Industrial Waste
Total
5
Historical ORE Contribution Annual Energy Contribution from ORE Projects Energy Generation (GWh) Year ORE
Capacity (MW)
System Total
ORE
Total System Installed
Capacity
2003
120
7612
39
2483
2004
206
8043
73
2499
2005
280
8769
88
2411
2006
346
9389
112
2434
2007
344
9814
119
2444
2008
433
9901
161
2645
2009
546
9882
181
2684
2010
724
10714
212
2818
2011
722
11528
227
3141
2012
730
11801
320
3312
2013
1178
11962
367
3355
2014
1215
12418
442
3932
2015
1466
13154
455
3850
2016
1160
14250
516
4018
ORE Project Development –Capacity Additions Up to 15.11.2016
6
RENEWABLE ENERGY- PRESENT STATUS Renewable Energy Contribution Major Hydro
Other RE
Total RE Percentage
8000
70%
7000
60%
6000 50%
40% 4000 30% 3000 20% 2000 10%
1000
0
0% 2006
2007
2008
2009
2010
2011 Year
2012
2013
2014
2015
2016
7
Percentage
Energy (Gwh)
5000
Study Methodology (1) Generation Planning with ORE,
(2) System operation study and (3) Power system analysis study incorporating ORE generation
Renewable Energy Resource Estimation
9
Data Source and Data requirement Generation and transmission planning studies Transmission planning study files for selected cases Data files used for CEB generation planning Half hourly historical demand data and projected system demand and loss data for the period considered for the study. Existing NCRE generation Hydro generation constraints 10 mins wind data for five regions (Mannar, Puttlam, Nothern, Eastern and Hill country) 10 mins solar radiation data for Hambantota and Kilinochchi 5sec solar power output data from existing solar plants SPPA signed, LOI issued all NCRE projects Details on existing conventional power plants (capacity, reactive power capability, efficiency, ramp up and ramp rate etc.) Merit order dispatch Transmission Network data (Steady state and dynamic data) Operation restrictions such as minimum operation of base load plants, water release, plant outputs etc. Pump storage data Other data like hydrology, inflows etc.
PRESENT CAPACITY MIX AS AT DECEMBER 2016 Capacity Share in 2016 Other RE 13% IPP Thermal 16% CEB Coal 22%
30.00
Energy Share in 2016 Other RE 8% CEB Hydro IPP 24% Thermal 15%
Total RE 47% CEB Hydro 34%
CEB Coal 36%
CEB Thermal 15%
CEB Thermal 17% 1 USD= 154 LKR On 18.5.2017
Actual Average Unit Cost of Electricity Generation 2016 28.37
25.00 Unit Cost (LKR/kWh)
Total RE 32%
20.00
Average cost at selling point in 2016 = 18.09
15.00
Average cost at selling point in 2015 = 15.06
24.34 17.59
10.00 5.00
2.32
6.58
CEB Hydro
CEB Coal
Renewables Generation Technology
CEB Thermal
IPP Thermal
11
Energy Mix during last 10 years 14000 1466
12000 723
Energy (GWh)
346 3082
345
3529
435
1977
548 3600
3680
2336
2083
4000 4292
3703
3359
1225 2610
4906 5493 4898
2532 3433
2091
4991 3605
1215
2795 1394
1669
4254
3884
6000
2000
1176
729
10000 8000
734
6012 4905
4021 2729
3634
0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Year CEB Hydro CEB Thermal IPP Thermal NCRE
Renewable Energy Resource Estimation ď ś Major Hydro Total Hydro Energy Estimation based on past 30 years data 6000
5243
5000 4155
GWh
4000 3233
3000 2000 Annual Total
Weighted Average considering worst hydro conditions
1000
4% 8% 12% 16% 20% 24% 28% 32% 36% 40% 44% 48% 52% 56% 60% 64% 68% 72% 76% 80% 84% 88% 92% 96% 100%
0 Duration (%)
New Projects in the Pipeline
Estimated Energy for different hydo conditions
35 MW Broadlands
20 MW Seethawaka
120 MW Uma Oya
15 MW Thalpitigala
Very Wet
31 MW Moragolla
20 MW Gin Ganga
5243 4917
Wet
Medium
4004
Dry
Very Dry
3611
3233 13
Renewable Energy Resource Estimation ď ś Mini Hydro Monthly Average Mini-Hydro Production Per Unit Monthly Average Capacity
0.6
Capacity (p.u)
0.5
0.45
0.4
0.49
0.46 0.42
0.51
0.45 0.41
0.37 0.29
0.3 0.23
0.2
0.16
0.18
0.1 0
Jan
Feb
Mar
Apr
May
Jun Jul Month
Aug
Sep
Oct
Nov
Dec
ďƒ˜ Seasonal variation is derived based on Historical Data 14
Renewable Energy Resource Estimation 2. Wind Five wind regimes are modelled based on site measurements for wind Production estimation Wind Regime 1
Northern
2
Mannar
3 4
Puttalam Eastern
5
Hill Country
Location Jaffna Pooneryn Nadukuda Nannattan Silawathu Udappuwa Kokilai Seethaeliya Balangoda 15
Renewable Energy Resource Estimation 2. Wind Wind measurement data is collected for each wind regime Wind plants are modelled for each wind regime Wind plant production is estimated Use System Advisory Model (SAM) for wind and solar profile estimation 20 18 16 14 12 10 8 6 4 2 0
2nd Week of May
2nd Week of October
1 238 475 712 949 1186 1423 1660 1897 2134 2371 2608 2845 3082 3319 3556 3793 4030 4267 4504 4741 4978 5215 5452 5689 5926 6163 6400 6637 6874 7111 7348 7585 7822 8059 8296 8533
speed 9m/s))
Example : Production of Mannar 25MW Wind Block
Hours
16
1 284 567 850 1133 1416 1699 1982 2265 2548 2831 3114 3397 3680 3963 4246 4529 4812 5095 5378 5661 5944 6227 6510 6793 7076 7359 7642 7925 8208 8491
Capacity (MW))
Wind Plant Power output
25
20
15
10
5
0 Hours
Output Variation of 10 MW Wind Power Plant in Putlam
Renewable Energy Resource Estimation 2. Wind Wind Plant modelling main parameters
Block Capacity Turbine capacity (MW)
Mannar
Puttalam
Hill Country
Northern
Eastern
25MW
20MW
10.45MW
20MW
20MW
2MW x10
0.55MW x19
2MW x10
2MWx10
91%
91%
91%
91%
91%
Nadukuda 2015
Udappuwa 2009-2010
Seethaeliya 2012-2014
Pooneryn 2015
80
80
50
80
2.5MW x10
Plant availability Wind measurement Data (location -Year) Hub Height (m)
Kokkilai 2015 80
Results on Wind plant modelling Mannar
Puttalam
Hill country
Northern
Eastern
Block Capacity
25MW
20MW
10MW
20MW
20MW
Annual Plant Factor
36.7%
31.4%
19.1%
34.1%
37.3%
Annual Energy(GWh)
80
55
17
59.7
47.9
19
Renewable Energy Resource Estimation
3. Solar
Two Solar regimes are modelled based on data for production estimation Location
Plant Factor
Hambantota
16.3%
Kilinochchi
15.6%
20
Renewable Energy Resource Estimation 3. Solar Sample Solar measurement data ( 1 minute time step) in Kilinochchi. 1400 Solar Irradiance (W/m2)
1200
19th Jan
9th Feb
11th March
1000 800 600 400 200 1 59 117 175 233 291 349 407 465 523 581 639 697 755 813 871 929 987 1045 1103 1161 1219 1277 1335 1393
0
Mins 21
Renewable Energy Resource Estimation 4. Biomass Biomass Plants are considered as dispatchable power plants and modeled as thermal plants
22
Optimized Generation Expansion Plan
23
ACTUAL AND FORECAST ENERGY/PEAK DEMAND As per Draft LTGEP 2018-2037 50000
9000
45000
Actual
8000
Forecast
40000
7000
30000
5000
25000 4000
20000 Generation
15000
3000
Peak Demand
10000
2000
5000
1000
Estimation of avg. growth rate approx. 5 %
2042
2040
2038
2036
2034
2032
2030
2028
2026
2024
2022
2020
2018
2016
2014
2012
2010
2008
2006
2004
0 2002
0
Demand (MW)
6000
2000
Energy (GWh)
35000
Three main cases of long term generation expansion plans were developed for the purpose of this study. 1 2
3
Reference Case Case 1 Case 2
Only the existing “other renewable energy� is included and No future ORE development is assumed Expansion plan with new coal development up to 1200MW, with pump storage development Expansion plan without both pump storage development and coal development
NCRE Projection Year
Mini Hydro (MW)
Wind (MW)
Biomass (MW)
Solar (MW)
Total ORE Capacity (MW)
Annual Total ORE Generation (GWh)
Share of ORE from Total Generation %
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
329 344 359 374 384 394 404 414 424 434 444 454
144 244* 294 414 489 539 599 644 729 729 754 799
34 39 44 49 54 59 64 69 74 79 84 89
50 210 305 410 465 471 526 581 685 740 795 900
557 837 1002 1246 1392 1463 1592 1708 1912 1982 2076 2242
1793 2425 2792 3402 3784 4022 4338 4620 5084 5229 5447 5796
12.2% 15.5% 16.8% 19.6% 20.8% 21.0% 21.6% 21.9% 23.0% 22.5% 22.3% 22.6%
* According to the latest implementation schedules, 100MW Wind Park in Mannar considered for the year 2018 above is expected to be commissioned in July, 2019. 26
PROJECTED DEVELOPMENT OF OTHER RENEWABLE ENERGY 9000
Solar (MW)
Wind (MW)
Biomass (MW)
Mini Hydro (MW)
Other renewable energy share (%)
25.0%
8000 7000
Energy (GWh)
30.0%
20.0%
6000 5000
15.0%
4000 10.0%
3000 2000
5.0%
1000 0
0.0% 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037
Year
As per Draft LTGEP 2018-2037
27
Energy Share (%)
10000
Reference Case 2017-2028 YEAR
2017
2018
2019
2020 2021 2022
RENEWABLE ADDITIONS (MAJOR HYDRO)
-
120 MW Uma Oya HPP
35 MW Broadlands HPP 15 MW Thalpitigala HPP 31 MW Moragolla HPP 20 MW Seethawaka HPP 20 MW Gin Ganga HPP
2023
-
2024
-
2025 2026 2027 2028
1x200 MW Pump Storage Power Plant 1x200 MW Pump Storage Power Plant 1x200 MW Pump Storage Power Plant -
THERMAL ADDITIONS 100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2* (Southern Region) 2x35 MW Gas Turbine 1x35 MW Gas Turbine 1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region+ 1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region 1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region
THERMAL RETIREMENTS
LOLP %
-
0.631
8x6.13 MW Asia Power 4x17 MW Kelanitissa Gas Turbines
1.494
4x18 MW Sapugaskanda diesel
0.756
6x5 MW Northern Power
0.261
100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2*
163 MW AES Kelanitissa Combined Cycle 163 MW Combined Cycle Power Plant (KPS–2) Plant 1x300 MW New Coal Power Plant Phase I, 115 MW Gas Turbine Trincomalee -2 4x9 MW Sapugaskanda Diesel Ext. 1x300 MW New Coal Power Plant Phase I, Trincomalee -2 4x9 MW Sapugaskanda Diesel Ext. 4x15 MW CEB Barge Power Plant 1x300 MW New Coal Power Plant Phase II, Trincomalee -2 1x300 MW New Coal Power Plant - Southern
0.898 0.996
0.850
0.452
0.971 0.109
-
0.235
-
0.079
New Coal Development Restricted to 1200MW, First Coal Plant by 2023 YEAR
2017
2018
2019
2020 2021 2022
RENEWABLE ADDITIONS (MAJOR HYDRO)
-
120 MW Uma Oya HPP
35 MW Broadlands HPP 15 MW Thalpitigala HPP 31 MW Moragolla HPP 20 MW Seethawaka HPP 20 MW Gin Ganga HPP
THERMAL ADDITIONS 100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2* (Southern Region)
-
2024
-
2025 2026 2027 2028
1x200 MW Pump Storage Power Plant 1x200 MW Pump Storage Power Plant 1x200 MW Pump Storage Power Plant -
LOLP %
-
0.477
2x35 MW Gas Turbine
8x6.13 MW Asia Power 4x17 MW Kelanitissa Gas Turbines
0.535
1x35 MW Gas Turbine 1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region+
4x18 MW Sapugaskanda diesel
0.270
-
6x5 MW Northern Power
0.364
-
-
0.731
1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region
100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2*
0.609
163 MW Combined Cycle Power Plant (KPS–2)
163 MW AES Kelanitissa Combined Cycle Plant 115 MW Gas Turbine 4x9 MW Sapugaskanda Diesel Ext.
0.551
2023
THERMAL RETIREMENTS
1x300 MW New Coal Power Plant Phase I, Trincomalee -2 1x300 MW New Coal Power Plant Phase I, Trincomalee -2
-
4x9 MW Sapugaskanda Diesel Ext. 4x15 MW CEB Barge Power Plant
0.318
0.339
-
-
0.283
-
-
0.462
-
0.169
1x300 MW Natural Gas fired Combined Cycle
(No Coal Development & No PSPP Development) YEAR
2017
2018
2019
2020 2021
2022
RENEWABLE ADDITIONS (MAJOR HYDRO)
-
120 MW Uma Oya HPP
-
THERMAL ADDITIONS 100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2* (Southern Region) 2x35 MW Gas Turbine
LOLP %
-
0.477
8x6.13 MW Asia Power 4x17 MW Kelanitissa Gas Turbines
1x35 MW Gas Turbine 1x300 MW Natural Gas fired Combined Cycle 4x18 MW Sapugaskanda diesel Power Plant – Western Region+
35 MW Broadlands HPP 15 MW Thalpitigala HPP
-
31 MW Moragolla HPP 20 MW Seethawaka HPP 20 MW Gin Ganga HPP
THERMAL RETIREMENTS
-
6x5 MW Northern Power -
1x300 MW Natural Gas fired Combined Cycle 100 MW Furnace Oil fired Power Plant 1* Power Plant – Western Region 70 MW Furnace Oil fired Power Plant 2*
163 MW AES Kelanitissa Combined Cycle Plant 1x300 MW Natural Gas fired Combined Cycle 115 MW Gas Turbine Power Plant – Southern Region 4x9 MW Sapugaskanda Diesel Ext. 1x300 MW Natural Gas fired Combined Cycle Power Plant – Southern Region 1x300 MW Natural Gas fired Combined Cycle 4x9 MW Sapugaskanda Diesel Ext. Power Plant - Western Region 4x15 MW CEB Barge Power Plant 1x300 MW Natural Gas fired Combined Cycle Power Plant - Western Region 1x300 MW Natural Gas fired Combined Cycle Power Plant -Southern Region
0.535
0.270
0.364 0.731
0.609
163 MW Combined Cycle Power Plant (KPS–2)
2023
-
2024
-
2025
-
2026
-
2027 2028
-
0.547
0.322 0.293 0.698
0.504 0.385
Power System Operational Study The objective of the operational study is to analyze (1) System integration impacts and any associated costs including the generation upgrades (2) Operational measures and ancillary services required for increased integration of wind and other renewable energy (ORE) technologies
Annual Energy (GWh) Monthly energy in 20 blocks
System operation study approach
Repeat process for each year 3 times (dry, high wind and wet period) for the period 2017-2036
Run SDDP (Stochastic Dual Dynamic Program) for multiple years & obtain relevant period Future Cost Function (Wind, Solar, Biomass and Minihydro are dispatched continuously according to the given profile since they are modelled as zero cost plants)
Monthly Future Cost function Run NCP for 2 days per month (Weekday & Weekend) for each period for multiple years
-Obtain daily plant dispatch schedule at 30 minutes time step -Curtailment requirement of other renewable plants outputs if any
Load Forecast 2017-2041
- Irrigation Requirement - Water Value of Reservoirs - Hydro inflow forecast methodology - Fuel Prices - Power Plant maintenance Schedule - Forced Outages - Power plant operation characteristics - Power plant additions/retirements -Annual Other RE capacity development - Annual profiles of wind and solar from SAM (System Advisor Model) hourly resource - Biomass annual profile - Mini hydro annual profile
-Monthly Future Cost Function of the SDDP -Half an hourly load forecast -Hydro Plant parameters and configurations -Thermal Plant parameters and configurations -NCRE generation profile 30 min -Daily inflows to the reservoirs in half an hour intervals -Daily Maintenance schedule and outages -Irrigation and other water releases requirements -Spinning reserve requirements -Initial state of the system for initiating the simulation
Operational Study Long Term- Hydro Thermal Optimization (SDDP Software)  Optimum use of hydro resource and the corresponding operation of thermal power plants are simulated at monthly time step.  Future Hydro conditions are predicted using probabilistic methods 30,000
Energy (GWh)
25,000
20,000 2,314
15,000 4,131 -
10,000
4,750
5,000
1,664 4,175
4,317
563 3,210
546
733 4,109
5,035
4,627
1,853
2,514
3,477
3,670
3,961
5,021
5,051
5,099
5,097
5,064
4,421
4,583
6,059
467 2,066
4,375
8,757
8,121
8,241
8,435
8,651
4,304
4,471
4,867
5,039
5,146
5,451
5,584
5,306
5,339
5,457
5,679
5,276
1,407 2,342 6,435
4,746
-
-
5 3,750
4,813
2,109
22
39 4,964
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Large Hydro
Other Renewable
Coal Thermal
LNG Thermal
Other Thermal
PSPP
33
Percentage share of Other Renewable Energy sources 100%
30 171
share of Other renewable (%)
90%
666
805
805
948
1087
1087
1231
Solar 873
238 1375
273
50%
1536
1752
1923
2059
Wind 2379
2379
2454
2583
308
40%
20%
523
401
60%
30%
523
401
80% 70%
312
Biomass 343
1,065
378
413
449
484
1,113
519
554
589
624
1,372
1,405
1,437
1,469
1,162 1,210
1,243
1,275
1,307
10%
1,340
0% 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Year
MiniHydro
Short Term Dispatch Analysis using NCP software NCP software tool was used to simulate daily dispatch of selected days in 30 minute time step The curtailment requirement of renewable energy production was identified. All the system constraints were modelled according to the present operational procedures of the system control center. The inputs that were used for the model and specified constraints are mentioned later in this section.
Operational Study • Input Data o o o o o o o o o o o o o o o o
Hydro Inflow Data 44 years (38 Gaging station) Demand Data (20 years) Plant characteristics Renewable Profiles Fuel characteristics and Prices Irrigation Requirement Water Value of Reservoirs Fuel Prices Power Plant maintenance Schedule Plant Forced Outage rates Power plant operation characteristics Power plant additions/retirements Annual Other RE capacity development Annual profiles of wind and solar (hourly Data) Biomass annual profile Mini hydro annual profile 36
Operational Constraints • -
Hydro Power Plants Unit Generation and turbine outflow constraints Reservoir operation constrains Cascade hydro plant topologies Drinking Water/Irrigation requirements Must run Hydro power plants Generation Reserves for frequency control operation Spinning reserve from all hydro plants
• -
Thermal Power Plants Minimum loading level constraints Lakvijaya Coal Power plant – 190 MW (70%) New Coal Power Plant – 135MW (50%) Kelanithissa Combined cycle plant -75MW (45%) Westcoast Combined cycle plant -108MW (40%) Sojitz Kelanithissa Combined cycle plant -70MW (44%) Plant Startup Costs and Minimum Up time and Minimum Down time (hours) Maximum ramp up and Maximum ramp down rates (MW/min)
System Operational Constraints -
Half hourly demand requirement Energy deficit is not allowed Total secondary Spinning reserve requirement is specified. Largest Generation unit online should not be greater than 30% of the system load.
•
Renewable Power Plants
-
Must run condition for wind, biomass, solar and Mini hydro Curtailment is allowed at instances where above constraints cannot be met
Assumptions -
Future plant additions and retirements are according to the optimized expansion plan
-
“Other Renewable� generation sources were considered as Non Dispatchable plants for the estimation of curtailment requirement
-
Future Wind Solar and Mini-hydro Generation profiles were estimated based on measured data and past performance assuming no significant variation for future years
-
Maintenance plans of major power plants (Coal fired and Combined cycle Plants) for future years as per the maintenance scheduling procedure
Operational Study Short Term Optimization (NCP Software) Daily Economic dispatch of power plants are simulated at 30 min time step . System operational limitations are identified When the generation constraints cannot be satisfied, excess amount of renewable energy is curtailed a given year was divided in to three periods to capture the seasonality effects of hydro conditions, renewable variations and demand variations JAN
FEB
MAR
Dry Period
APR
MAY
JUN
JUL
High Wind Period
AUG
SEP
OCT
NOV
DEC
Wet Period
• total 36 simulations were carried out for 2018, 2020, 2022, 2024, 2025, 2028
40
Daily dispatch of other renewables and curtailments 2020 High Wind period Week Day 3000 2500
1500 1000 500
Time (30 Minutes)
Biomass Total wind Curtailment requirement
Minihydro Total soalr PSPP Pump
22:30
21:00
19:30
18:00
16:30
15:00
13:30
12:00
10:30
9:00
7:30
6:00
4:30
3:00
1:30
0 0:00
MW
2000
Curtailment for 2020 High Wind period Week Day 160 140 120
MW
100 80 60 40 20 0
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Curtailment‌
Time (30 Minutes)
2020 High Wind period Weekend Weekend day 3000 2500 2000
1000 500 0 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00
MW
1500
Time (30 Minutes)
Biomass Total wind Curtailment requirement Demand
Minihydro Total soalr PSPP Pump PSPP Generation
2020 High Wind period Weekend Curtailment of VRE Weekend day 90
Curtailment requirement
80 70
MW
60 50 40
30 20 10 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Time (30 Minutes)
2020 Wet period Week Day 3000 2500 2000
1000 500 0 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00
MW
1500
Time (30 Minutes)
Biomass Total wind Curtailment requirement Demand
Minihydro Total soalr PSPP Pump PSPP Generation
Curtailment 2020, Wet period Week Day Curtailment‌ 180 160 140
MW
120
100 80 60 40 20 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Time (30 Minutes)
2020 Wet period Weekend 3000 2500 2000
1000 500 0 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00
MW
1500
Time (30 Minutes) Curtailment requirement Total wind Biomass Demand
Total soalr Minihydro PSPP Pump PSPP Generation
Curtailment, 2020 Wet period Weekend Curtailment requirement
160 140 120 MW
100 80 60 40 20
0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Time (30 Minutes)
2025 High Wind period Week Day 4000 3500 3000
2500
1500 1000 500
Time (30 Minutes) Biomass Total wind Curtailment requirement Demand
Minihydro Total soalr PSPP Pump PSPP Generation
23:00
22:00
21:00
20:00
19:00
18:00
17:00
16:00
15:00
14:00
13:00
12:00
11:00
10:00
9:00
8:00
7:00
6:00
5:00
4:00
3:00
2:00
1:00
0
0:00
MW
2000
2025 High Wind period Week Day Curtailment of VRE Curtailment requirement 450 400 350
MW
300 250 200 150 100 50 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Time (30 Minutes)
2025 High Wind period Week End Curtailment requirement Total soalr
3500
2500
Total wind
2000
Minihydro
1500
Biomass
1000 PSPP Pump 500 Demand
0
0:00 1:30 3:00 4:30 6:00 7:30 9:00 10:30 12:00 13:30 15:00 16:30 18:00 19:30 21:00 22:30
MW
3000
Time (30 Minutes)
PSPP Generation
2025 High Wind period Weekend Curtailment requirement
350 300
MW
250 200
150 100 50 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Time (30 Minutes)
2025 High Wind period Week Day Without future Pump Storage Development Curtailment requirement Total soalr
4000 3500 3000
Total wind
Minihydro 2000
Biomass
1500
PSPP Pump
1000 500
Demand
Time (30 Minutes)
22:30
21:00
19:30
18:00
16:30
15:00
13:30
12:00
10:30
9:00
7:30
6:00
4:30
3:00
1:30
0 0:00
MW
2500
PSPP Generation
2025 High Wind period Week Day Without future Pump Storage Development Curtailment requirement
500
450 400
MW
350 300 250 200 150 100 50
0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Time (30 Minutes)
2025 High Wind period Week End Without future Pump Storage Development
3000
Curtailment requirement Total soalr
2500
Total wind
2000
Minihydro
1500
Biomass
1000
PSPP Pump 500
Demand
Time (30 Minutes)
22:30
21:00
19:30
18:00
16:30
15:00
13:30
12:00
10:30
9:00
7:30
6:00
4:30
3:00
1:30
0 0:00
MW
3500
PSPP Generation
2025 High Wind period Week End Without future Pump Storage Development Curtailment requirement 450 400 350
MW
300 250 200 150 100 50
0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Time (30 Minutes)
Main Observations of NCP simulation results No renewable energy curtailments are observed in dry periods. Curtailments can be observed on High wind period from 2020 onwards. Reduced curtailments can be observed in wet periods compared to high wind period. Weekend days have higher curtailment levels at day time than week days where the demand is relatively high. Off peak curtailment is significant in the lowest off-peak of the week which usually occurs on Mondays. Both off-peak and daytime curtailments can be observed in high wind periods. Introduction of pump storage units gradually decreases the curtailment requirement after 2025. Curtailment requirement increases in the case where no pump hydro and coal development is considered in 2025 high wind period with 50% the minimum load operation of future combined cycle power plants. However the curtailment is reduced when the combined cycle plants are operated with 30% minimum load restriction. Curtailment requirement is very low with the introduction of 600MW pump storage power plant in the year 2028.
Year
2020
None
None
150MW None
80 MW 50 MW
170MW None
140MW None
2022
None
None
220MW None
140MW 100MW
None
None
2025
None
None
380MW None
330MW 280MW
70MW None
20MW None
-
70MW None
30MW 111MW
-
-
2028
1.
1.
Maximum VRE Curtailment Requirement Dry Period High Wind Period Wet period (Jan-Apr) (May-Aug) (Sep-Dec) Weekday Weekend Weekday Weekend Weekday Weekend -Off-peak -Off-peak -Off-peak -Off-peak -Off-peak -Off-peak -Daytime - Daytime - Daytime - Daytime - Daytime - Daytime Case 1: With Future Coal Power, LNG and Pump Storage Development
-
Case 2: With No Future Pump Storage and Coal Power Development With new combined cycle minimum load operation constraint at 50% 2025
None
None
445MW None
380MW 430MW
None
None
2028
None
None
80MW None
200MW 276MW
None
None
175MW 160MW
None
None
With new combined cycle minimum load operation constraint at 30% 2025
None
None
215MW None
*Shadowed cells indicate that one or more coal units are under maintenance in the considered month of the period.
Transmission Network Study
Transmission Network Study To evaluate the potential impacts of intermittent resources on the transmission grid To define a planning process by which conventional and renewable resources can be accommodated
To identify anticipated transmission congestion locations To evaluate transmission and other grid improvements required to integrate NCRE sources
Classification of Power System Stability
Source : Power System Stability and Control by Kundur Prabha
The objective of the stability analysis is to assess the system stability following a major disturbance (e.g. three- or single-phase fault or power plant/load rejection). The studies are carried out to analyze The transient frequency variations Voltage variations synchronous generator rotor angle variation for stability. In general, transient studies are carried out for a few second (10 sec). These studies require detailed dynamic models of the generators, loads, tap changing transformers, HVDC lines, and Flexible AC Transmission System (FACTS) devices like STATCOM. The non-linearities of such devices have to be accurately modeled in order to reflect transient behavior of the system.
In case of Solar PV, the output power variations due to cloud cover are in the range of a few minutes to 10 minutes depending on the size of the solar PV plant. Therefore short term frequency stability study has to be carried to see the limitation of PV capacities under steady state operating condition..
System Regulation Requirement due to intermittence based generation 10 9 8
Power Output (MW)
7 6 5 4 3 2 1 0 5:31:12 AM
7:55:12 AM
10:19:12 AM
12:43:12 PM
3:07:12 PM
5:31:12 PM
Power Output Variation of 10 MW Solar PV Plant (1sec data)
800
8000
700
7000
600
6000
500
5000
400
4000
300
3000
200
2000
100
1000 0
0
Time (min) T1
T2
T3
T4
T5
T6
T7
T8
T9
T10
Individual turbine output and total 10 MW wind farm output
Total
Total Power Output (kW)
9000
0 60 120 180 240 300 360 420 480 540 600 660 720 780 840 900 960 1020 1080 1140 1200 1260 1320 1380
Power Output (kW)
900
Impact of Intermittency of VRE (Data resolution)
Power output variation in a day of 650 kW Hambantota plant (1sec data)
Enlarged view of Fig. above for the time period 10.00 hrs. To 10.50 hrs
Power output variation in a day of 10 MW Hambantota plant
Enlarged view of Fig. 6.4 for the time period 10.30 hrs to 13.00 hrs
Week day, Week end and Daily Solar PV power variation
Spinning Reserve Requirement Present policy is to keep 5% of the demand as the spinning reserve Required capacity in each year for 5% spinning reserve
Peak Demand (MW) Spinning Reserve (MW)
2016 2483
2018 2020 2022 2788 3131 3394
2024 3681
2026 4014
2028 4398
124
139
184
201
220
157
170
Spinning reserve required for load variability using the method adopted by Mid-West System operator in USA Peak Demand (MW) Sinning reserve for catering load variability (MW)
2016 2483
2018 2788
2020 3131
2022 3394
2024 3681
2026 4014
2028 4398
73
79
85
88
91
92
98
10% of VRE capacity is taken as additional reserve requirement to cater for intermittency
Effect of solar ramp rate and short term frequency stability The output power of solar PV plant will vary with cloud cover as given The power could be either ramp down or ramp up with the movement of the cloud over the solar
It is clear that ramp rate will vary randomly and cannot be accurately simulated. The International Energy Agency (IEA) study has shown that the solar ramp rate depends on following factors. Geographical spread Time scale: Weather patterns:
Output Power Variation of 10 MW Saga Solar PV plant in Hambantota on 30-11-2016
4.00 3.32
-2.00 -3.00
-1.33
-1.34 -2.06 -1.99
-1.84
Time
Power Ramp up and Ramp down of “Saga Solar PV plant” on 4-12-2016
2:50:51 PM
1:05:25 PM
12:46:56 PM
12:10:54 PM
11:52:25 AM
11:24:51 AM
10:26:35 AM
-0.82
10:20:19 AM
-0.74
10:02:27 AM
0.83
9:40:22 AM
9:25:39 AM
9:20:00 AM
1.00
-1.00
1.23
1.00
9:58:42 AM
1.13
0.00
1.94
1.85
2.00
9:10:55 AM
Ramp Rate (MW/min)
3.00
Land requirement and time taken to pass a cloud Capacity (MW)
Time to pass a cloud with Area requirement (km2) a speed of 25 km/h (min)
10
0.2025 (50 acres)
1.1
20
0.4050 (100 acres)
1.5
30
0.6075 (150 acres)
1.9
50
1.0125 (250 acres)
2.4
Poonarin
Potential Sites for Solar PV Plant Development
Sri Lanka Present Transmission Network
Cases Studied For Each Year • Year 2018 – – – – –
Case 1: Swing machine is only used for free governor Case 2: Swing machine + GT7 used for free governor Case 3: Swing machine + KCCP used for free governor Case 4: With All Hydro Governor (Victoria, Kotmale, Upper Kotmale, N’Lax) Case 5: Swing machine + KCCP + GT7 + 2x35MW GTs used for free governor
• Year 2020 – Case 1: With All Hydro Governor (Victoria, Kotmale, Upper Kotmale, N’Lax) used for free governor – Case 2: Swing machine + KCCP + GT7 used for free governor – Case 3: Swing machine + KCCP + GT7 + LNG used for free governor – Case 4: Swing machine + KCCP + GT7 + LNG + 2x35MW GTs used for free governor
• Year 2022, 2025, 2028, 2031, 2036 – LNG + GTs + Hydro (Victoria, Kothmale, Upper Kothmale)
Solar ramp rates used for the study Solar Power Ramps 11
10
9
8
7
6
5
4
3 0
25
50
75
Time (seconds) b c d e f g
Normal Ramp g b c d e f
High Ramp
100
Analysis for the year 2018- Case 1, only swing machine used in free governor mode Renewable Energy Type Wind Dendro Mini Hydropower Solar
Capacity (MW)
Amount dispatched
246 39 329 117
100% 100% 10% 100%
Capacity (MW) Distributed Solar Plants Solar Hambantota 30 Vavuniya 10 Polonnaruwa 10 10 Valachchenai Mahiyangana 10 10 Monaragala 10 Vavunativu 7 Habarana 10 Anuradhapur 5 a Kilinochchi 5 Sub Total 60 57 Grand Total 117 Grid Substation
Ramp Fast varying Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal
Solar power capacities with their locations
Total Solar Power Variation(MW) 120
115
110
105
100
95
90
85
80 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
100
Time (seconds) b c d e f g
100*((3*A)+(3*E)+(4*B)+(2*C)+D) : VicGovonlyHamb30other30and57SD
Effective solar ramp rate considered for 117 MW solar PV capacity
System Frequency Response 50.25 50.2 50.15 50.1 50.05 50 49.95 49.9 49.85 49.8 49.75 49.7 49.65 49.6 49.55 49.5 0
25
50
75
100
125
150
175
Time (seconds) b c d e f g
With 57MW Distributed Solar g b c d e f
With 60MW Distributed Solar g b c d e f
With 58MW Distributed Solar
Frequency variation for the solar ramp given above
200
Victoria swing bus power response for the solar power ramp Victoria(Swing Bus) Power Variation 27.5 25 22.5 20 17.5 15 12.5 10 7.5 5 2.5 0
25
50
75
100
125
150
Time (seconds) b c d e f g
100*A : VicGovonlyHamb30other30and57SD
175
200
Analysis for the year 2018- Case 2, Victoria+GT7 in the free governor mode
Grid Substation Hambantota Vavuniya Polonnaruwa Valachchenai Mahiyangana Monaragala Vavunativu Habarana Anuradhapura Kilinochchi Sub Total Grand Total
Capacity (MW) Distributed Solar Plants Solar 30 20 20 10 20 10 10 10 10 10 10 10 5 5 120 60 180
Ramp Fast varying Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal
Effective solar ramp rate for 180 MW solar PV capacity Total Solar Power Variation (180MW) 210 200 190 180 170 160 150 140 130 120 110 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
Time (seconds) b c d e f g
DP_TM_2018_study 4_Case 2_Solar180
75
80
85
90
95
100
Frequency Response for different solar PV capacities Frequency Variation 50.2
50.1
50
49.9
49.8
49.7
49.6
49.5 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
Time (seconds) g b c d e f b c d e f g b c d e f g
g b c d e f DP_TM_2018_study 4_Case 2_Solar150 g b c d e f DP_TM_2018_study 4_Case 2_Solar180 g b c d e f DP_TM_2018_study 4_Case 2_Solar90
DP_TM_2018_study 4_Case 2_Solar120 DP_TM_2018_study 4_Case 2_Solar170 DP_TM_2018_study 4_Case 2_Solar190
95
100
GT7 Power Variation 120 115 110 105 100 95 90 85 80 75 70 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
Time (seconds) b c d e f g
DP_TM_2018_study 4_Case 2_Solar180
Power response of GT7 for solar PV ramp given
100
Victoria Power Variation 30 27.5 25 22.5 20 17.5 15 12.5 10 7.5 5 2.5 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
Time (seconds) b c d e f g
DP_TM_2018_study 4_Case 2_Solar180
Victoria swing bus power response for the solar power ramp
95
100
Analysis for the year 2018-Case 4 Hydro Generators, Victoria, Kothmale, Upper Kothmale & and New Laxapana in the free governor mode Total Solar Power Variation (290 MW) 325
300
275
250
225
200
175
0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
Time (seconds) b c d e f g
DP_TM_2018_study 4_Case 4_Solar290
Effective solar ramp rate for 290 MW solar PV capacity
95
100
Capacity (MW)
Solar Plants
Distributed Solar
Hambantota
30
-
Vavuniya Polonnaruwa Valachchenai Mahiyangana Monaragala Vavunativu Habarana Anuradhapura Kilinochchi Ampara Mannar Embilipitiya Trinco Sub Total Grand Total
20 20 20 10 20 20 10 20 20 20 20 230
10 10 10 10 10 5 5 60
Grid Substation
290
Ramp Fast varying Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal
Frequency Response 50.3 50.2 50.1 50 49.9 49.8 49.7 49.6 49.5 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
Time (seconds) g b c d e f b c d e f g b c d e f g
DP_TM_2018_study 4_Case 4_Solar150 f g b c d e DP_TM_2018_study 4_Case 4_Solar210 g b c d e f
DP_TM_2018_study 4_Case 4_Solar180
DP_TM_2018_study 4_Case 4_Solar290 g b c d e f
DP_TM_2018_study 4_Case 4_Solar300
DP_TM_2018_study 4_Case 4_Solar240
Frequency Response for different solar PV capacities
95
100
Victoria Power Variation 37.5 35 32.5 30 27.5 25 22.5 20 17.5 15 12.5 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
100
Time (seconds) b c d e f g
DP_TM_2018_study 4_Case 4_Solar290
Victoria swing bus power response for the solar power ramp Hydro Governor Power Variation 80
70
60
50
40
30
20
10
0 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
100
Time (seconds) b c d e f g
Victoria
b c d e f g
Kothmale
b c d e f g
Upper Kothmale g b c d e f
New Laxapana
Power response of all hydropower plants in droop mode
Summary of Short Term Frequency Stability analysis Year
Scenario
Capacity
Victoria only
117 MW
Victoria + GT7
180 MW
Victoria + KCCP
210 MW
All Hydro Generators (Victoria, Kothmale, Upper Kothmale and New Laxpana)
290 MW
Victoria + KCCP+GT7+ 2x35MW GTs
300 MW
Victoria + Hydro (Kothmale, Upper Kothmale, New Laxapana)
302 MW
Victoria + KCCP + GT7
272 MW
Victoria + KCCP + GT7 + LNG
522 MW
Victoria + KCCP + GT7 + LNG + 3x35MW GT
582 MW
2022
LNG + GTs + Hydro (Victoria, Kothmale, Upper Kothmale)
540 MW
2025
LNG + GTs + Hydro (Victoria, Kothmale, Upper Kothmale)
730 MW
2028
LNG + GTs + Hydro (Victoria, Kothmale, Upper Kothmale)
940 MW
2018
2020
Contingency Analysis
Contingency simulations have been carried out for following case in 2020, 2025 and 2028.  When the frequency is at minimum due to the solar ramp, a three phase fault occur at Norochcholai 220 kV busbar and the fault is cleared after 6 cycles.  Further one unit of Norochcholai tripped after fault is cleared.
Frequency response for the contingency *simulation given above in 2020 Frequency Variation 50.2 50.1 50 49.9 49.8 49.7 49.6 49.5 49.4 49.3 49.2 49.1 49 48.9 48.8 48.7 48.6 48.5 48.4 48.3 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
100
Time (seconds) b c d e f g
60MW Solar Park + 242MW Solar Plants -Fault at 27.2 sec
Fault occurred at 27.2 sec and it was cleared after 0.12 sec (at 27.32 sec). Unit 3 (275 MW) tripped at just after fault is cleared. It was noticed that about 271 MW of load was shed to bring the frequency to stability limit.
Voltage Variation 1.2 1.1 1 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0
25
Time (seconds) g b c d e f b c d e f g b c d e f g b c d e f g
633 - VOLT 2230 [VICTO-2
220.00] : 60MW + 70MW + 172W Fault at 27.2 sec
655 - VOLT 2560 [PANNI-2
220.00] : 60MW + 70MW + 172W Fault at 27.2 sec
665 - VOLT 2705 [NEWANU-2 653 - VOLT 2400 [HAMBA-2
220.00] : 60MW + 70MW + 172W Fault at 27.2 sec 220.00] : 60MW + 70MW + 172W Fault at 27.2 sec
220 kV busbar voltages at different busbars due to the three phase fault at Norochcholai 220 kV bus
50
Power Variation at Puttalam Coal Unit 1 and 2 600
500
400
300
200
100
0 0
5
10
15
20
25
30
35
40
45
50
Time (seconds) b c d e f g
Unit 1 g b c d e f
Unit 2
: Power swing at Norochcholai generators Hydro Power Plant Power Variation 80 70 60 50 40 30 20 10 0 -10 -20 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
Time (seconds) b c d e f g
Victoria
b c d e f g
Upper Kotmale g b c d e f
Kotmale
b c d e f g
New laxapana
Power swing at hydropower plants
90
95
100
Summary of the contingency simulation study
Scenario
State
Hydro Maximum Day Peak – DH
System Stable with Load Shedding
Thermal Maximum Day Peak - DT
System Stable with Load Shedding
Minimum VRE Day Peak – VRE_DP
System Stable
Hydro Maximum Night Peak - NH
System Stable with Load Shedding
Thermal Maximum Night Peak - NT
System Stable
Minimum VRE Night Peak – VRE_NP
System Stable
Hydro Maximum Off Peak - HMOP
System Stable with Load Shedding
Thermal Maximum Off Peak - TMOP
System Stable
PROJECTED DEVELOPMENT OF OTHER RENEWABLE ENERGY Year
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037
Cumulative Cumulative Cumulative Mini hydro Wind Biomass Capacity (MW) Capacity Capacity (MW) (MW) 344 144 39 359 194 44 374 414 49 384 489 54 394 539 59 404 599 64 414 644 69 424 729 74 434 729 79 444 754 84 454 799 89 464 824 94 474 894 99 484 929 104 494 974 104 504 1044 109 514 1114 109 524 1184 114 534 1279 114 544 1349 119
As per Draft LTGEP 2018-2037
Cumulative Solar Capacity (MW) 210 305 410 465 471 526 581 685 740 795 900 954 1009 1064 1119 1173 1229 1283 1338 1442
Cumulative Total ORE Capacity (MW) 737 902 1246 1392 1463 1592 1708 1912 1982 2076 2242 2336 2476 2580 2691 2830 2965 3105 3265 3454
Annual Total ORE Generation (GWh) 2103 2471 3402 3784 4022 4338 4620 5084 5229 5447 5796 6014 6365 6601 6844 7193 7509 7860 8252 8670
Share of ORE from Total Generation % 13.0% 14.3% 18.4% 19.5% 19.8% 20.3% 20.6% 21.6% 21.2% 21.0% 21.3% 21.1% 21.2% 21.1% 20.9% 21.1% 21.1% 21.2% 21.4% 21.5% 96
Levelized Cost of Renewable Energy (Except Major Hydro) Renewable Technology and Typical Plant Factor Solar PV (at 17% PF) - 1412 USD/kW Capital Cost (2017-2020) -1100 USD/kW Capital Cost (2021-2025) -900 USD/kW Capital Cost (2026 onwards) Wind (at 35% PF) Mini Hydro (at 37% PF) Biomass (at 80% PF)
Components of Levelized Cost (USCts/kWh) Capacity O&M Total Levelized Fuel Component Component Component Cost (UScts/kWh) 11.14
0.66
-
11.80
8.68
0.66
-
9.34
7.10
0.66
-
7.76
7.26 6.22 3.44
0.93 1.59 5.76
8.99
8.19 7.80 18.19
SCENARIO 1 2 3 4 5
6
Victoria+KCCP for Regulation reserve All Hydro Generators for Regulation reserve (Vic, Kot, Upp Kot & New Lax) LNG+GTs+HYDRO for Regulation reserve PSPP development included LNG+GTs+HYDRO for Regulation reserve PSPP and Coal power development excluded LNG+GTs+HYDRO for Regulation reserve PSPP included and Coal development excluded LNG+GTs+HYDRO for Regulation reserve LNG Development only in the Western Region Reference Case
PV Cost up to 2036 (USD million)
Difference with Scenario 3 (USD million)
12,979
(118)
12,993
(104)
13,097
-
13,653
556
13,618
521
12,872
(225)
12,382
(715)
Difference of PV Cost for Each Scenario Compared with Scenario 3 800
556
Difference(USD Millions)
600
521
400 200
0
0 -200
(118)
(104)
(225)
-400 -600 -800
(715) Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 6 Reference
RECOMMENDATIONS Day ahead, hourly basis and accurate Wind and Solar PV energy forecasting system should be implemented as early as possible. This should be implemented before the commissioning of 100 MW wind farm in Mannar and 100 MW solar park in Monaragala. 24 hour (round the clock), renewable energy desk has to be set up at new system control center and output from each renewable energy sources have to be monitored (if existing plants are not equipped with communication facilities, measures have to be taken for establishing them). In order for smooth operation of power system, VRE curtailment rights have to be given to system operator. A compensation mechanism has to be included in PPA of future VRE plants. All future conventional plants including IPPs have to be procured for running on free governor mode (2%-5% droop) when they are on the system for dispatching.
RECOMMENDATIONS… All conventional generators must be procured with dynamic simulation models compatible for PSCAD, PSS/E and DigSilent. The parameters of these models have to be tuned for site condition of the place that they are located. If the proposed conventional plants are not commissioned as scheduled, the VRE addition in the plan has to be revised accordingly. Thus it is proposed to review this plan in line with Long Term Generation Expansion Plan (once in two years). Planned network strengthening projects must be completed as scheduled. Future coal plants should be developed based on Advanced Subcritical basis and could be able to de-load the plant up to 35% in order to keep the VRE curtailment at a minimum level. It was noted that increase of penetration level of RE sources leads to increase in unit cost of generation. Thus this variation should be reflected in the tariff set in future.
THANK YOU
Sri Lanka Present Transmission Network
Study Methodology Renewable Energy Resource Estimation and Projection Major Hydro, Mini Hydro, Wind , Solar, Biomass Long Term Generation Expansion Planning System Studies •Operational Study ( Long Term and Short Term) •Transmission Network Study ( Steady State and Transient Stability) •Economic Analysis
• • • •
Results and Analysis Identification of System Operational limitations Identification of impact on System Stability Renewable Energy Curtailment Requirement Determination of of Cost Implications 104
Scenario
Description
Regulation RE Projection Reserve Option
Reference Scenario
Only existing ORE plants at 1st September 2016 were included and no future development considered.
Only the existing and committed ORE
Scenario 1:
Victoria and Kelanitissa Combined Cycle Plant are the only generators allocated to absorb Solar and Wind vitiations which operate on frequency control mode. Solar integration is limited.
Revision 1
Option 1
Scenario 2:
All hydro generators capable of frequency regulation (Vict, Kot, Upp Kot & New Lax) will be operating on frequency control mode. Solar integration is limited.
Revision 1
Option 2
Scenario 3:
All the converted & future LNG combined cycle power plants, gas turbine plants and all hydro generators capable of frequency regulation would be operating on frequency control mode.
Revision 1
Option 3
Scenario 4:
The development of future Coal Power Plants and the Pumped Storage Power Plant (PSPP) were excluded from the optimized expansion plan.
Revision 2
Option 3
Scenario 5:
The development of the future coal plants was excluded from the plant schedule and the development of pump storage power plant was included.
Revision 1
Option 3
Scenario 6:
Future Coal power and pump storage development is included and the development of the future LNG plants was limited to 5 plants in the Western Region only.
Revision 1
Option 3
-