Clean, Green Coal

Energy Systems Research Laboratory, FIU

Clean, Green Coal• “Clean coal” is a vague term that refers to a number of

processes by which coal can be used to make electricity with less “pollution.”

• These technologies include– Electrostatic precipitators, which remove particles

from the flue gases. Precipitators are uniformly used.– Scrubbers are used to remove sulfur dioxide, which

was implicated in creating acid rain. – Low NOx burners are used to remove nitrogen oxides

(Nox).– CO2 removal is more difficult, with sequestration an

option

Professor O. A. Mohammed, EEL5285 Lecture Notes, Spring 2017


Growth in Coal Generation: US and China

Source http://www.netl.doe.gov/coal/refshelf/ncp.pdf



Background on the Electric Utility Industry

• First real practical uses of electricity began with the telegraph (around the civil war) and then arc lighting in the 1870’s (Broadway, the “Great White Way”).

• Central stations for lighting began with Edison in 1882, using a dc system (safety was key), but transitioned to ac within several years. Chicago World’s fair in 1893 was key demonstration of electricity

• High voltage ac started being used in the 1890’s with the Niagara power plant transferring electricity to Buffalo; also 30kV line in Germany

• Frequency standardized in the 1930’s



Regulation and Large Utilities• Electric usage spread rapidly, particularly in urban areas. Samuel

Insull (originally Edison’s secretary, but later from Chicago) played a major role in the development of large electric utilities and their holding companies– Insull was also instrumental in start of state regulation in 1890’s

• Public Utilities Holding Company Act (PUHCA) of 1935 essentially broke up inter-state holding companies– This gave rise to electric utilities that only operated in one state– PUHCA was repealed in 2005

• For most of the last century electric utilities operated as vertical monopolies



Vertical Monopolies

• Within a particular geographic market, the electric utility had an exclusive franchise

Generation

Transmission

Distribution

Customer Service

In return for this exclusivefranchise, the utility had theobligation to serve all existing and future customersat rates determined jointlyby utility and regulators

It was a “cost plus” business



Vertical Monopolies

• Within its service territory each utility was the only game in town

• Neighboring utilities functioned more as colleagues than competitors

• Utilities gradually interconnected their systems so by 1970 transmission lines crisscrossed North America, with voltages up to 765 kV

• Economies of scale keep resulted in decreasing rates, so most every one was happy



History, cont’d -- 1970’s• 1970’s brought inflation, increased fossil-fuel

prices, calls for conservation and growing environmental concerns

• Increasing rates replaced decreasing ones• As a result, U.S. Congress passed Public Utilities

Regulator Policies Act (PURPA) in 1978, which mandated utilities must purchase power from independent generators located in their service territory (modified 2005)

• PURPA introduced some competition, but its implementation varied greatly by state



PURPA and Renewable Energy• PURPA, through favorable contracts, caused the growth

of a large amount of renewable energy in the 1980’s (about 12,000 MW of wind, geothermal, small scale hydro, biomass, and solar thermal)– These were known as “qualifying facilities” (QFs)– California added about 6000 MW of QF capacity during the

1980’s, including 1600 MW of wind, 2700 MW of geothermal, and 1200 MW of biomass

– By the 1990’s the ten-year QFs contracts written at rates of $60/MWh in 1980’s, and they were no longer profitable at the $30/MWh 1990 values so many sites were retired or abandoned



Electricity Prices, 1990-2007

Source: EIA, annual energy review, 2007

Total USA solar/pv energy production was essentially flat from 1990 to 2005 (0.06 quad vs. 0.065)

Total wind generation stayed flat during 1990’s (around 0.03) but is now growing (0.32 in 2007; solar/pv is 0.08 in 2007)



History, cont’d – 1990’s & 2000’s• Major opening of industry to competition occurred

as a result of National Energy Policy Act of 1992• This act mandated that utilities provide

“nondiscriminatory” access to the high voltage transmission

• Goal was to set up true competition in generation • Result over the last few years has been a dramatic

restructuring of electric utility industry (for better or worse!)

• Energy Bill 2005 repealed PUHCA; modified PURPA



State Variation in Electric Rates



Historical Electricity Use

Source: EIA, annual energy review, 2008

• Total USA solar/pv energy production was essentially flat from 1990 to 2005 (0.06 quad vs. 0.065)

• Total wind generation stayed flat during 1990’s (around 0.03) but is now growing (0.32 in 2007; solar/pv is 0.08 in 2007)

• In 2008, largest sources of renewable energy in descending order: hydroelectric, wood, biofuels, wind, waste, geothermal, solar/PV

http://www.eia.doe.gov/aer/pdf/aer.pdf



Historical Electricity Generation

• In 2008, fossil fuels (coal, petroleum, and natural gas) accounted for 71% of all net generation

• Nuclear contributed 20%• Renewable energy resources contributed 9% • In 2008, 67% of the renewable energy came from conventional

hydroelectric powerSource: EIA, annual energy review, 2008



The California-Enron Effect

Source : http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html

RI

AK

electricityrestructuring

delayedrestructuring

no activity suspendedrestructuring

WA

OR

NV

CA

ID

MT

WY

UT

AZ

CO

NM

TX

OK

KS

NE

SD

ND MN

IA

WI

MOIL IN OH

KYTN

MSLA

AL GA

FL

SCNC

WVA VA

PANY

VT ME

MINHMA

CTNJ

DEMD

AR

HI

DC



August 14th, 2003 Blackout

https://reports.energy.gov/

Read the blackout report:



Source: http://www.dsireusa.org/

Renewable Portfolio Standards (September 2009)

State renewable portfolio standard

State renewable portfolio goal

Solar water heating eligible *† Extra credit for solar or customer-sited renewables

Includes separate tier of non-renewable alternative resources

WA: 15% by 2020*

CA: 20% by 2010

☼ NV: 25% by 2025*

☼ AZ: 15% by 2025

☼ NM: 20% by 2020 (IOUs)10% by 2020 (co-ops)

HI: 40% by 2030

☼ Minimum solar or customer-sited requirement

TX: 5,880 MW by 2015

UT: 20% by 2025*

☼ CO: 20% by 2020 (IOUs)10% by 2020 (co-ops & large munis)*

MT: 15% by 2015

ND: 10% by 2015

SD: 10% by 2015

IA: 105 MW

MN: 25% by 2025(Xcel: 30% by 2020)

☼ MO: 15% by 2021

WI: Varies by utility; 10% by 2015 goal

MI: 10% + 1,100 MW by 2015*

☼ OH: 25% by 2025†

ME: 30% by 2000New RE: 10% by 2017

☼ NH: 23.8% by 2025

☼ MA: 15% by 2020+ 1% annual increase(Class I Renewables)

RI: 16% by 2020

CT: 23% by 2020

☼ NY: 24% by 2015

☼ NJ: 22.5% by 2021

☼ PA: 18% by 2020†

☼ MD: 20% by 2022

☼ DE: 20% by 2019*

☼ DC: 20% by 2020

VA: 15% by 2025*

☼ NC: 12.5% by 2021 (IOUs)10% by 2018 (co-ops & munis)

VT: (1) RE meets any increase in retail sales by 2012;

(2) 20% RE & CHP by 2017

29 states & DChave an RPS

5 states have goals

KS: 20% by 2020

☼ OR: 25% by 2025 (large utilities)*5% - 10% by 2025 (smaller utilities)

☼ IL: 25% by 2025



Impact of 2009 Stimulus Bill on Renewable Energy

• American Recovery and Reinvestment Act (ARRA)• The 2009 stimulus bill contained several provisions

related to renewable energy– $32 billion to enhance the electric power grid– A three year extension to renewable production tax credits – About $40 billion for energy efficiency in various forms– $2 billion for advanced battery manufacturing

• Also a lot of synchrophasor-related ARRA projects– http://www.naspi.org/meetings/workgroup/workgroup.stm– Synchrophasors and renewable energy integration are related



Power System Structure

• All power systems have three major components: Load, Generation, and Transmission/Distribution.

• Load: Consumes electric power• Generation: Creates electric power.• Transmission/Distribution: Transmits electric

power from generation to load.• A key constraint is since electricity can’t be

effectively stored, at any moment in time the net generation must equal the net load plus losses



2007 USA Electric Energy FlowNote, Electricity is “Refined” Energy

Source: EIA 2007 Annual Energy ReviewProfessor O. A. Mohammed, EEL5285 Lecture Notes, Spring 2017


2008 USA Electric Energy Flow

Source: EIA 2008 Annual Energy ReviewNote- this graphic does NOT show losses



LOADS

• Can range in size from less than one watt to 10’s of MW

• Loads are usually aggregated for system analysis • The aggregate load changes with time, with strong

daily, weekly and seasonal cycles– Load variation is very location dependent



Loads- Household Consumption

Source: EIA 2008 Annual Energy Review



Example: Daily Variation for CA



Example: Weekly Variation



Example: Annual System Load

0

5000

10000

15000

20000

250001

518

1035

1552

2069

2586

3103

3620

4137

4654

5171

5688

6205

6722

7239

7756

8273

Hour of Year

MW

Loa

d



Load Duration Curve• A very common way of representing the annual load is

to sort the one hour values, from highest to lowest. This representation is known as a “load duration curve.”

6000

5000

4000

3000

2000

1000

0

DEM

AN

D (M

W)

0 1000 HRS 7000 8760

Load duration curve tells how much generation is needed



GENERATION

• Large plants predominate, with sizes up to about 1500 MW.

• Coal is most common source (56%), followed by nuclear (21%), hydro (10%) and gas (10%).

• New construction is mostly natural gas, with economics highly dependent upon the gas price

• Generated at about 20 kV for large plants



New Generation by Fuel Type(USA 1990 to 2030, GW)

Source: EIA Annual Energy Outlook 2007



Basic Gas Turbine Efficiency

Compressor

Fuel100%

Fresh air

Combustion chamber

Turbine

Exhaustgases 67%

Generator

ACPower 33%

1150 oC

550 oC

Brayton Cycle: Working fluid is always a gas

Most common fuel is natural gas

Maximum Efficiency550 2731 42%

1150 273

Typical efficiency is around 30 to 35%



Gas Turbine

Source: Masters



Combined Heat and Power

Compressor

Fuel100%

Fresh air

Combustion chamber

Turbine

Exhaust gases

Generator

ACPower 33%

Heat recovery steamgenerator (HRSG)

Water pump

Feedwater

Exhaust 14%

Steam 53%

Process heat

Absorption cooling

Space & water heating

Overall Thermal Efficiency = 33% (Electricity) + 53% (Heat) = 86%



Combined Cycle Power Plants

Efficiencies of up to 60% can be achieved, with even higher values when the steam is used for heating



Determining operating costs• In determining whether to build a plant, both the fixed

costs and the operating (variable) costs need to be considered.

• Once a plant is build, then the decision of whether or not to operate the plant depends only upon the variable costs

• Variable costs are often broken down into the fuel costs and the O&M costs (operations and maintenance)

• Fuel costs are usually specified as a fuel cost, in $/Mbtu, times the heat rate, in MBtu/MWh– Heat rate = 3.412 MBtu/MWh/efficiency– Example, a 33% efficient plant has a heat rate of 10.24



Heat Rate• Fuel costs are usually specified as a fuel cost, in

$/Mbtu, times the heat rate, in MBtu/MWh– Heat rate = 3.412 MBtu/MWh/efficiency– Example, a 33% efficient plant has a heat rate of

10.24 Mbtu/MWh– About 1055 Joules = 1 Btu– 3600 kJ in a kWh

• The heat rate is an average value that can change as the output of a power plant varies.

• Do Example 3.5, material balance



Historical and Forecasted Heat Rates

http://www.npc.org/Study_Topic_Papers/4-DTG-ElectricEfficiency.pdf



Fixed Charge Rate (FCR)• The capital costs for a power plant can be annualized by

multiplying the total amount by a value known as the fixed charge rate (FCR)

• The FCR accounts for fixed costs such as interest on loans, returns to investors, fixed operation and maintenance costs, and taxes.

• The FCR varies with interest rates, and is now below 10%.

• For comparison this value is often expressed as$/yr-kW



Annualized Operating Costs

• The operating costs can also be annualized by including the number of hours a plant is actually operated

• Assuming full output the value is

Variable ($/yr-kW) = [Fuel($/Btu) * Heat rate (Btu/kWh) + O&M($/Kwh)]*(operating hours/hours in year)



Coal Plant Example• Assume capital costs of $4 billion for a 1600 MW coal

plant with a FCR of 10% and operation time of 8000 hours per year. Assume a heat rate of 10 Mbtu/MWh, fuel costs of 1.5 $/Mbtu, and variable O&M of $4.3/MWh. What is annualized cost per kWh?

Fixed Cost($/kW) = $4 billion/1.6 million kW=2500 $/kWAnnualized capital cost = $250/kW-yrAnnualized operating cost = (1.5*10+4.3)*8000/1000

= $154.4/kW-yrCost = $(250 + 154.4)/kW-yr/(8000h/yr) = $0.051/kWh



Capacity Factor (CF)

• The term capacity factor (CF) is used to provide a measure of how much energy a plant actually produces compared to the amount assuming it ran at rated capacity for the entire year

CF = Actual yearly energy output/(Rated Power * 8760)

• The CF varies widely between generation technologies,



Generator Capacity Factors

Source: EIA Electric Power Annual, 2007

The capacity factor for solar is usually less than 25% (sometimes substantially less), while for wind it is usually between 20 to 40%). A lower capacity factor means a higher cost per kWh



One-line Diagrams

• Most power systems are balanced three phase systems.

• A balanced three phase system can be modeled as a single (or one) line.

• One-lines show the major power system components, such as generators, loads, transmission lines.

• Components join together at a bus.



PowerWorld Simulator Three Bus System

Bus 2 Bus 1

Bus 3Home Area

204 MW102 MVR

150 MW

150 MW 37 MVR

116 MVR

102 MW 51 MVR

1.00 PU

-20 MW 4 MVR

20 MW -4 MVR

-34 MW 10 MVR

34 MW-10 MVR

14 MW -4 MVR

-14 MW 4 MVR

1.00 PU

1.00 PU

106 MW 0 MVR

100 MWAGC ONAVR ON

AGC ONAVR ON

Load withgreenarrows indicatingamountof MWflow

Usedto controloutput ofgenerator Direction of arrow is used to indicate

direction of real power (MW) flow

Note thepower balance ateach bus



Power Balance Constraints

• Power flow refers to how the power is moving through the system.

• At all times in the simulation the total power flowing into any bus MUST be zero!

• This is know as Kirchhoff’s law. And it can not be repealed or modified.

• Power is lost in the transmission system.



Basic Power Flow Control

• Opening a circuit breaker causes the power flow to instantaneously (nearly) change.

• No other way to directly control power flow in a transmission line.

• By changing generation we can indirectly change this flow.



Transmission Line Limits

• Power flow in transmission line is limited by heating considerations.

• Losses (I2 R) can heat up the line, causing it to sag.

• Each line has a limit; Simulator does not allow you to continually exceed this limit. Many utilities use winter/summer limits.



Overloaded Transmission Line



Interconnected Operation• Power systems are interconnected. Most of

North America east of the Rockies is one system, with most of Texas and Quebec being exceptions

• Interconnections are divided into smaller portions, called balancing authority areas (previously called control areas)



Balancing Authority (BA) Areas

• Transmission lines that join two areas are known as tie-lines.

• The net power out of an area is the sum of the flow on its tie-lines.

• The flow out of an area is equal to

total gen - total load - total losses = tie-flow



Area Control Error (ACE)• The area control error is the difference

between the actual flow out of an area, and the scheduled flow.

• Ideally the ACE should always be zero.• Because the load is constantly changing, each

utility must constantly change its generation to “chase” the ACE.



Automatic Generation Control• BAs use automatic generation control (AGC)

to automatically change their generation to keep their ACE close to zero.

• Usually the BA control center calculates ACE based upon tie-line flows; then the AGC module sends control signals out to the generators every couple seconds.



Three Bus Case on AGC

Bus 2 Bus 1

Bus 3Home Area

266 MW133 MVR

150 MW

250 MW34 MVR

166 MVR

133 MW 67 MVR

1.00 PU

-40 MW 8 MVR

40 MW -8 MVR

-77 MW 25 MVR

78 MW-21 MVR

39 MW-11 MVR

-39 MW 12 MVR

1.00 PU

1.00 PU

101 MW 5 MVR

100 MWAGC ONAVR ON

AGC ONAVR ON


Clean, Green Coal

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