a study on environmental & utility planning implications of distributed power generation for a...
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A STUDY ON ENVIRONMENTAL & A STUDY ON ENVIRONMENTAL & UTILITY PLANNING UTILITY PLANNING
IMPLICATIONS OF DISTRIBUTED IMPLICATIONS OF DISTRIBUTED POWER GENERATION FOR A POWER GENERATION FOR A
REGIONAL ELECTRICITY BOARD REGIONAL ELECTRICITY BOARD OF INDIA OF INDIA
S.C. Srivastava, B.K. BarnwalIndian Institute of Technology,
Kanpur-208016, India
Dharam Paul, Praveen GuptaEnviron. & Energy Conservation Div.
Central Electricity Authority, New Delhi-110066, India
R.M. Shrestha, R.ShresthaEnergy Program,
Asian Institute of technologyPathumthani-12120, Thailand
A.K. SrivastavaIllinois Institute of Technology,
Chicago, USA
Mitigating Environmental Emissions from
the Power Sector: Analyses of Technical and
Policy Option in Selected Asian Countries
(Funded by Swedish International Development Agency)
•Issue#1:Least cost supply side option for mitigating GHG and other harmful emissions from the power sector subject to emission target
•Issue#2: Identification of some CDM projects in the power sector and assessment of their GHG and other harmful emission mitigation potential
•Issue#3: Environmental implications of IPPs and decentralized power generation
ObjectiveObjective
• Optimal generation expansion plan under the conventional least cost planning strategy (business as usual case} with and without DSM ( TRP & IRP cases )
• To study the change in optimal generation expansion plan with DPGs introduced as existing and candidate plants.
• Impact of DPGs on total cost of generation expansion and also on emission of different Green House Gases in NREB system.
• Sensitivity Analyses with respect to some key parameters related to DPG plants.
MethodologyMethodology Least cost generation expansion plan minimizes cost of power generation
from existing and candidate power plants and installing candidate power plant over certain period.
If
T: No. of years in planning horizon.s: No. of seasons in year.P: No. of blocks in season.t: No. of vintages in block.J: Total no. of candidate power plants.K: Total no. of existing power plants.
Mathematically, least cost generation expansion planminimizes following objective function,
Where,
Cjv: Discounted capital cost of candidate power plant j, tobe commissioned in vintage v.Wjv:Discounted salvage value of power plant j,commissioned in year v after time horizon T.Yjv: Number of power plants of type j installed in year v
T
t
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J
jpststjpstvjpstv
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vjvjvjv NFUYWC
1 1 1 1 11 1
T
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K
kpststkpstvkpstv NFU
1 1 1 1
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Ukpstv: Power generation from plant k of vintage v inblock p of season s in year t.Fkpstv: Cost of per unit power generation from existing orcommitted power plant k of vintage v in block p of season s inyear t.YPmv: Number of pump storage hydro plants type minstalled in year vNst: Number of days in season s of year t.
pst: Width of block p of chronological load curve of season sof year t.Ujpstv: Power generation from candidate plant j of vintage vin block p of season s in year t.Fjpstv: Cost of per unit power generation from candidatepower plant j of vintage v in block p of season s in year t.
System constraints are :
•Power demand constraint:
Sum of power generation by all power plants (existing and candidate) in each block of the planning horizon will be greater than or equal to total projected power demand during that period.
• Reliability constraint:
Power demand from all the plants (candidate + existing) must be greater than or equal to the sum of power demand and the reserve margin in each year
•Annual energy constraint:
Annual energy constraint are defined to limit the energy generation of each thermal plant according to the capacity, availability and time required for schedule maintenance of the plant.
•Hydro energy constraint: Total energy output of each hydro plant should not exceed the pre specified energy limit in each season.
•Fuel or resource availability constraint:Limit to the energy generation of the plants by particular fuel types if such limitations exist during the planning horizon.•Annual emission constraint: The annual emission level of each pollutant from total generation system should not exceed the pre-specified value of each year
Utility load shape and demand forecast
Existing and candidate plant data of utility DPG plants
Generation Expansion plan using IRPA with Utility supplying utility
load (BAU case)
Generation Expansion Plan using IRPA with
Utility + DPG plants supplying total load
•Generation Mix (G1)•Total Cost (C1)•CO2, SO2 and NOxEmissions (E1)
•Change in Emissions = E1+E0 ~E2
•Change in Cost = C1+C0 ~C2
•Change In Generation mix = G1~G2
•Generation Mix (G1)•Total Cost (C1)•CO2, SO2 and NOxEmissions (E1)
Flowchart for IRPA with DPG
Case Studies
Four case studies have been done :
1. Traditional Resource Planning (TRP) without any DPG plant (The TRP cases do not include any DSM options)
2. Traditional Resource Planning with DPG plants.
3. Integrated Resource Planning (IRP) without any DPG plant
(The IRP cases include DSM options).
4. Integrated Resource Planning with DPG plants.
using
• Input data of Northern Regional Electricity Board (NREB),
and
• Integrated Resource Planning Analysis (IRPA) developed by
Asian Institute of Technology and CPLEX as software tool
NREB systemNREB system
•NREB is one of the five Regional Electricity Boards (REBs) of
India
•Consists of seven State Electricity Boards (SEB)
•REBs exist to promote the integrated operation between SEBs
of that Region
•Electricity generation in India is predominantly thermal base
with hydro-thermal mix of 25:75 in year 1996-1997
•Installed generating capacity in NREB as on March 2000 was 25847 MW
•Transmission and Distribution losses in the country stood at 21% in
year 1996-1997 ( Transm. Loss appx. 4%)
•NREB system has 160 Thermal plants and 230 Hydro plants at present including 29 existing DPGs each of hydro kind.•Present generation capacity of NREB system:(March, 2000) Thermal plants : 17239 MW, Hydro plants : 7698 MW, Nuclear plants : 910 MW, Total : 25847 MW•Country utilizes power reliability indices - Loss of Load Probability (LOLP) of 2% and Energy Not Served (ENS) not to exceed 0.15% in expansion planning•Projected peak demand of NREB for 2001-2002 is 31375 MW•Projected energy requirement of NREB for year 2001-2002 is 181649 GWh•Study considers five types of DSM options, 3 candidate DPGs based on renewable sources viz. wind, solar and micro-hydro.
Estimated potential of renewable in India
Energy Source
Estimated Potential
Wind Energy
20000 MW
Solar Energy
5*1015 kWh/pa
Biomass 17000 MW
Source: Naidu, 1996
Input data and assumptionsInput data and assumptions
•Planning horizon : 2003-2017
•Base year : 1998
•Discount rate : 10%
•Two seasons are taken in a year with season 1 of July, August,
September and season 2 of rest of the months
•Reserve margin is taken as 5% for all the year
•Ten types of fuels are taken as gas, nuclear, lignite , oil and six grades
of coal
•Two types of clean supply side options - Pressurized Fluidized Bed
Combustion (PFBC) and Integrated Gasification Combined Cycle
IGCC are considered. (By using PFBC and IGCC technology
efficiency can be improved up to 45% .)
•Seven types of candidate thermal plants, two types of supply side
options, three types of DPG plants and 21 candidate hydro plants are considered.
•Peak load forecast for planning horizon is shown in table 1.
Table 1: Projected Peak Load In NREB System
Year Peak Load (MW)
Energy Reqrmnt (GWh)
2003 33800 203169
2007 44009 254161
2012 60077 350185
2017 82000 482488
Name Coal 4 -500 Coal 6 -500 CCGT –500Nuclear -
500PFBC -450 IGCC -400 BIGCC-132
Fuel type used Coal 4 Coal 6 Gas Nuclear Coal 6 Coal 6 Wood
Fuel consumptionrate unit
000’kg/MWh
000’kg/MWh
000’m3/MWh
000’gm/MWh
000’kg/MWh
000’kg/MWh 000’kg/
MWhFuel
Consumption0.7 0.7 0.2 0.027 0.51 0.51 0.51
Calorific value(kBtu/kg)
13.5 13.5 41.74 406350 15.56 15.56 19.21
CO2 emission factor
(kg/MWh)1026 1026 550 0 907 551 71.64
SO2 emission factor(kg/MWh)
6 6 0.4 0 0.255 0.235 0.918
NOx emission factor
(kg/MWh)2.5 2.5 1.64 0 0.6 0.6 0.6
Installed capacity(MW)
500 500 250 500 450 400 132
Earliest availableyear
2004 2005 2003 2007 2005 2005 2005
Annual allowableMaximum unit
85 45 80 6 10 10 10
Availability
0.71 0.71 0.8 0.58 0.85 0.85 0.85
Unit depreciableCapital cost (k$)
450000 450000 175000 600000 510000 500000 162875
Unit non-depreciable
Capital cost (k$)50000 50000 19500 66000 52500 50000 18100
Heat rate at full load(Mcal/MWh)
2500 2500 2062 2777 2013 1850 2469
Operating cost(k$/MWh)
0.0012 0.0012 0.0008 0.0015 0.0012 0.0013 0.0174
Annual maintenancehour
864 864 1296 896 864 864 864
Fixed O&M cost(k$/MWmonth
2 2 1.67 2.7 2.2 2.32 5.4
Candidate thermal plants
Candidate Hydro Power Plants
Name Capac. Year Unit Cost En.Sea.1 En. Sea.2
Hibra 120 2007 2 143555 187200 280800
Palamaneri 100 2007 4 42265 137900 256100
Budhil 35 2008 2 37729 57200 85800
L. Nagpala 250 2008 2 82109 339325 630175
Kuther 130 2009 2 119444 188200 282300
Uhl st. III 50 2010 2 49019 80400 120600
Maner Bali 76 2010 4 84512 115850 215150
T. Vishnugadh 120 2010 3 56465 185033 343633
Parbati III 167 2010 3 106071 266266 399400
Dhauliganga II 70 2010 3 90683 111416 206916
Kishanganga 110 2011 3 100529 102500 239166
Kotlibhel 250 2012 4 72508 473462 879287
Uri II 70 2012 4 137877 108450 253050
Bursar 250 2014 4 144632 121950 284550
Shahpur Kandi 168 2014 1 299177 333440 708560
Sewa st II 60 2014 2 38258 47250 110250
Pakhal dul 250 2015 4 59941 44250 103250
Kishau 120 2015 5 153555 92890 172510
Parbati I 250 2015 3 278000 391200 586800
Name
Capacity(MW)
EAYear
Avail. OpeartingCost
FixedO&M(000’$/
MWmonth)
Generation pattern Season1 Generation patternSeason2
Karnah-I 1 2003 0.87 0 1.86 0.4166 0.3276
Karnah-II 1 2003 0.87 0 1.86 0.4166 0.3276
Stakna-I 2 2003 0.87 0 1.86 0.4166 0.3276
Stakna-II 2 2003 0.87 0 1.86 0.4166 0.3276
chennani-II-I 1 2003 0.87 0 1.86 0.4166 0.3276
chennani-II-II 1 2003 0.87 0 1.86 0.4166 0.3276
Sal st II-I 1 2003 0.87 0 1.86 0.5554 0.2808
Sal st II-II 1 2003 0.87 0 1.86 0.5554 0.2808
gumma-I 1.5 2003 0.87 0 1.86 0.5554 0.2808
gumma-II 1.5 2003 0.87 0 1.86 0.5554 0.2808
charanwala 1.2 2003 0.87 0 1.86 0.4166 0.3276
pugal 1 1.5 2003 0.87 0 1.86 0.4166 0.3276
RMC mangrol-I 2 2003 0.87 0 1.86 0.4166 0.3276
RMC mangrol-II 2 2003 0.87 0 1.86 0.4166 0.3276
RMC mangrol-III 2 2003 0.87 0 1.86 0.4166 0.3276
suratgarh-I 2 2003 0.87 0 1.86 0.4166 0.3276
suratgarh-II 2 2003 0.87 0 1.86 0.4166 0.3276
chitaura-I 1.5 2003 0.87 0 1.86 0.4860 0.3042
chitaura-II 1.5 2003 0.87 0 1.86 0.4860 0.3042
salwa-I 1.5 2003 0.87 0 1.86 0.4860 0.3042
salwa-II 1.5 2003 0.87 0 1.86 0.4860 0.3042
galogi-I 1 2003 0.87 0 1.86 0.4860 0.3042
galogi-II 1 2003 0.87 0 1.86 0.4860 0.3042
chirkilla 1 2003 0.87 0 1.86 0.4860 0.3042
urgam-I 1.5 2003 0.87 0 1.86 0.4860 0.3042
urgam-II 1.5 2003 0.87 0 1.86 0.4860 0.3042
nirgajni-I 2.5 2003 0.87 0 1.86 0.4860 0.3042
nirgajni-II 2.5 2003 0.87 0 1.86 0.4860 0.3042
Existing DPG hydro plants
Name Microhydro-2 Solar PV -2 Wind -2
Fuel type used Water Solar Wind
CO2 emission factor (kg/MWh) 0 0 0
SO2 emission factor (kg/MWh) 0 0 0
NOx emission factor (kg/MWh) 0 0 0
Installed capacity (MW) 2 2 2
Earliest available year 2003 2003 2003
Annual allowable Maximum unit 500 50 50
Availability 0.87 0.25 0.35
Unit depreciable Capital cost (k$) 2222.2 6000 1400
Unit non-depreciable Capital cost (k$) 0 0 0
Operating cost (k$/MWh) 0 0.0012 0.00075
Annual maintenance hour 0 168 240
Fixed O&M cost (k$/MWmonth 1.86 2.5 1.35
Candidate DPG plants
Demand Side Management Options
Sector DSM Options
Residential
1: Replacement of 100 W incandescent bulb by 20W CFL
2: Replacement of 60W incandescent bulb by 11W CFL
3: Replacement of 40W incandescent bulb by 9W CFL
Agriculture4: Replacing inefficient pumps by efficient ones
5: Partial rectification of pumps
RESULTS( NREB System)
Capacity Mix (%) by Plant Types
TRP without DPG
TRP with DPG
IRP without DPG
IRP with DPG
Hydro 24.7 24.7 26.5 26.5
Coal 43.3 43.3 46.4 45.9
CCGT 21.5 20.6 24.6 22.3
Nuclear 1.9 1.0 1.1 1.6
Lignite 0.4 0.4 0.5 0.5
PFBC 4.2 4.2 0.9 1.4
IGCC 3.8 3.8 0.0 0.0
Solar - 0.0 - 0.0
Wind - 0.9 - 1.0
BIGCC 0.1 0.0 0.1 0.0
Micro Hydro - 0.9 - 0.9
Total Capacity (GW)
106.5 106.4 99.4 99.5
Generation Mix (%) by Plant Types
TRP without DPG
TRP with DPG
IRP without DPG
IRP with DPG
Hydro 20.3 20.4 26.2 26.3
Coal 51.9 51.7 52.6 51.1
CCGT 13.3 12.8 18.2 16.6
Nuclear 2.0 1.0 1.3 1.9
Lignite 0.5 0.5 0.7 0.7
PFBC 6.3 6.3 0.8 1.3
IGCC 5.6 5.6 0.0 0.0
Solar - 0.0 - 0.0
Wind - 0.9 - 1.2
BIGCC 0.1 0.0 0.1 0.1
Micro Hydro - 0.7 - 0.8
Total Gen. (TWh)
477.9 476.1 370.3 368.4
Technology Options (Number of Units) Selected
TRP without DPG
TRP with DPG
IRP without DPG
IRP with DPG
Coal 460 60 60 59
Coal 6 0 0 00
CCGT 73 69 7970
Nuclear 2 0 01
PFBC 10 10 23
IGCC 10 10 00
BIGCC 1 0 10
Solar - 0 -0
Wind - 500 -500
Micro-hydro - 500 -471
Capacity Utilization and Unserved Energy of the System
TRP without
DPGTRP with
DPGIRP without
DPGIRP with
DPG
Average Capacity utilization
51.82 52.50 48.47 49.29
Av. Unserved Energy (MWh)
3.208 25.242 11.862 113.205
Expansion Costs During Planning Horizon
Expansion Cost (M$)TRPwitho
ut DPGTRP with
DPG
IRP without
DPG
IRP with DPG
Capital cost (1) 13409.4 13302.2 11689.4 11731.0
Fixed O&M (2) 6829.0 6804.4 6519.8 6506.8
Fuel and Variable (3) 26505.3 26018.3 22757.1 22114.7
Fuel and O&M (2+3) 33334.3 32822.7 29276.9 28621.5
Sub total (1+2+3) 46743.7 46124.9 40966.3 40352.6
DSM cost (4) 0.0 0.0 707.5 707.5
Total Cost (1+2+3+4) 46743.7 46124.9 41673.8 41060.1
Average Incremental Cost (AIC) of GenerationAIC(US
cents/kWh)
TRP without DPG
TRP with DPG
IRP without DPG
IRP with DPG
Without DSM 2.86 2.80 2.68 2.60
With DSM 2.86 2.80 2.86 2.78
Environmental implications
Total environmental emissions
Emissions
TRP without
DPG
TRP with DPG
IRP without
DPG
IRP with DPG
CO2 (Gkg) 3166.6 3122.9 2636.4 2548.5
SO2 (Mkg) 15998.3 16039.9 14416.8 13992.8
NOx (Mkg) 8220.2 8186.2 7297.3 7066.3
Sensitivity Analyses
• Sensitivity analyses are carried out by varying the capacity-cost of candidate DPG plants- Solar, Wind and Micro-hydro.
1. Solar plants were selected when their capacity cost was reduced to 0.5 $/WP (for both TRP and IRP cases) from 3 $/WP.
2. Wind plants were selected even up to the capacity cost of 9000 $/kW for IRP case and 3000 $/kW for TRP case (against the base value of 700 $/kW).
3. Micro-hydro plants were found to remain cost-effective even when their unit capacity cost was increased by 120% of their base value.
Conclusions• With introduction of DPG plants, capacity mix of CCGT decreases. Solar plants were not selected in any of the cases, while all wind plants were selected for both the TRP and IRP cases. All the micro-hydro units in TRP case and most in the IRP case were selected.•· With the introduction of DPG, the reliability of the system worsens. •· Introduction of DPG plants reduces CO2, SO2 and NOx emission
except the SO2 in TRP case. Capital cost decreases in the case of TRP,
while it increases in the case of IRP. It reduces the fuel and O&M cost, total expansion cost & average incremental cost. Thus, one can expect reduction in electricity price with the introduction of DPG plants.•· Solar plants are not selected in any of the cases due to their higher capacity cost. They get selected only when the capacity cost is lowered to 0.5 $/Wp •· Micro-hydro power plant units get selected even by increasing the capacity cost by 120% of its base value. • Even when the capacity cost of wind units are increased to 3500 $/kW for the TRP case and to 9500 $/kW for the IRP case, they get selected. The wind power plant is most economically feasible plant among all the three considered DPG plant types.
Thank
you