A STUDY ON ENVIRONMENTAL & UTILITY PLANNING IMPLICATIONS OF DISTRIBUTED POWER GENERATION FOR A REGIONAL ELECTRICITY BOARD OF INDIA S.C. Srivastava, B.K.

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

S

s

P

p

t

v

J

jpststjpstvjpstv

J

j

T

vjvjvjv NFUYWC

1 1 1 1 11 1

T

t

S

s

P

p

t

Vv

K

kpststkpstvkpstv NFU

1 1 1 1

T

t

S

s

P

p

t

v

J

jp ststjp stvjp stv NFU

1 1 1 1 1

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