Overview of Energy Life Cycle Analysis at NETLegon.cheme.cmu.edu/esi/docs/pdf/ESI_Seminar_04_25_2012.pdf · Overview of Energy Life Cycle Analysis at NETL (The Agenda) 1. LCA Definitions

Overview of Energy Life Cycle Analysis at NETL

Dr. Joe Marriott

Booz Allen Hamilton

April 25, 2012

Timothy J. Skone, P.E.

Office of Strategic Energy Analysis and Planning

2

MISSION Advancing energy options

to fuel our economy, strengthen our security, and

improve our environment

National Energy Technology Laboratory

Pittsburgh, PA

Morgantown,

WV

Albany,

OR

Fairbanks, AK

Sugar Land,

TX

West Virginia Pennsylvania Oregon

3

Overview of Energy Life Cycle Analysis at NETL (The Agenda)

1. LCA Definitions & Methods

2. NETL LCA Tools

– Power Life Cycle Analysis Tool (LCAT)

– Calculating Uncertainty in Biomass Emissions (CUBE)

– Upstream Life Cycle Emissions Dashboard

3. Life Cycle Analysis Studies

– Natural Gas Extraction, Delivery and Electricity Production

– Alternative Aviation Fuels

– Nuclear Power

– Wind Power with Gas Backup

– Cofiring Coal and Biomass for Power

4. Forthcoming Studies

1. Geothermal, Solar Thermal, Conventional Hydro

2. Dynamic Coal-Biomass Power with Emissions Control Options

4

Purpose of Energy Systems LCA Program

1. Produce Energy System LCAs – Inform and defend the Technology Programs – Baseline different energy system technologies – Understand technology strengths and weaknesses when

viewed from a life cycle perspective – Identify opportunities for R&D innovation

(through depth and transparency of analysis)

2. Improve LCA methods – Expand inventory – Characterize uncertainty and variability – Build flexible and dynamic models – Keep data collection and modeling current with state-of-

the-art LCA

3. Enhance interpretation and comparability of inventory results without losing depth and transparency

– Stochastic simulation of life cycle inventory – Tools to explore uncertainty and variability

NETL has a library of over 300 custom Unit

Processes, and dozens of models

to characterize energy systems

and address questions from

stakeholders

5

LCA: Definitions, Boundaries, Metrics

• Compilation and evaluation of inputs, outputs, and potential environmental impacts of a product or service throughout its life cycle, from raw material acquisition to final use and disposal

• The ability to compare different technologies depends on functional unit (denominator); e.g., for energy studies:

– 1 MWh of electricity delivered to end user

– 1 MJ of fuel combusted

• Greenhouse Gases – CO2, CH4, N2O, SF6

• Criteria Air Pollutants – NOX, SOX, CO, PM10, Pb

• Air Emissions Species of Interest – Hg, NH3, radionuclides

• Solid Waste • Raw Materials

– Energy Return on Investment (EROI)

• Water Use – Withdrawn water, consumption, water returned to source – Water Quality

• Land Use – Direct & indirect, Acres transformed, greenhouse gases

• Life Cycle Cost – Cost of Electricity (COE), Total Overnight Cost (TOC)

LC Stage #1

Raw Material

Acquisition

(RMA)

LC Stage #2

Raw Material

Transport

(RMT)

LC Stage #3

Energy Conversion

Facility

(ECF)

LC Stage #4

Product Transport

(PT)

LC Stage #5

End Use

Upstream, or Cradle-to Gate, Emissions Downstream Emissions

Converted to Carbon Dioxide equivalents using 2007 IPCC Global

Warming Potential (GWP)

GHG 20-year 100-year (Default)

500-year

CO2 1 1 1

CH4 72 25 7.6

N2O 289 298 153

SF6 16,300 22,800 32,600

6

LCA Basic Building Blocks: Unit Processes

The unit process describes how to scale collected environmental data to the reference flow

7

Life Cycle Process Flow

Unit processes are connected via their inputs and outputs and scaled to the functional unit

8

Power Life Cycle Analysis Tool (LCAT)

0

30

60

90

120

0.000

0.005

0.010

0.015

0.020

0

2

4

6

8

10

0

1,000

2,000

3,000

4,000

5,000

CAPITAL COST FIXED O&M VARIABLE O&M FUEL COST

2,446.56

Graph Table Master Sheet

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

0.0801

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

0.1059 0.0613 0.1048 0.0636 0.0904

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

1 2 3 4 5 60

0.05

0.1

0.15

0.2

$/

kW

h

IGCC IGCC CCS SCPC SCPC CCS NGCC CCSNGCC

Interest Rate (%) 0.00

Plant Life (years) 30.00

Discount Rate (%) 8.14 %

Heat Rate (Btu/kWh) 8,756

CO2 Tax 0.00 $/ton

CAPACITY FACTOR (%) 80

30.00

$/kW

Transmission Loss (%) 7

103.88 $/kW 0.0093 $/kWh 1.64 $/MMBtu

Without CCS

Environmental Performance Sensitivity AnalysisProduction Analysis Costs vs Emissions

NGCCIGCC SCPC EXPC USCPC GEN II-III Nuclear WIND USER 1 USER 2

With CCS Both

CO2 Control CostsEconomics Finance

GEN III+ Nuclear

• Interactive comparison tool (PowerSim) which gives users access to key financial and environmental results and parameters from detailed power LCAs

• Ongoing partnership between NETL and Sandia National Laboratory

Included

Technologies: o IGCC

o IGCC/ccs

o EXPC

o EXPC/ccs

o EXPC/ccs + RP

o SCPC

o SCPC/ccs

o NGCC

o NGCC/ccs

o Onshore Wind

o Gen III+ Nuclear

Sliders allow user to control assumptions and see results update in real time

9

-35.8 -25.9 -61.3 -93.4

-1,400

-1,050

-700

-350

0

350

700

CRP Forest Pasture Row Crops




Hybrid Poplar Switchgrass Corn Stover Forest Residue

Gre

en

ho

use

Gas

Em

issi

on

s, 3

0-y

r A

vg.

(g C

O₂e

/MJ

Loca

l Bio

mas

s D

eliv

ere

d)

Cornbelt Lake States Pacific Southeast NETL Modeled Value

Calculating Uncertainty in Biomass Emissions (CUBE)

GHG Emissions are highly dependent on underlying assumptions such as land type and yield; NETL study values for biomass GHG emissions are generally conservative

• Allows users to explore the uncertainty and variability of greenhouse gas emissions from various biomass types in an Analytica-based tool

• Collaboration between NETL and RAND

10

Upstream Dashboard: Input Sheet

Populates values for feedstocks & transportation

modes based on user selection

Converts results based on user selected output units &

GWP time horizon factors

Dashboard allows users to easily add upstream life cycle environmental information to their process of interest such as a coal plant or refinery

– Ability for user adjusted parameter values

– User chooses which portions of life cycles to include

– Implemented in Excel

11

The Upstream Dashboard

Chart shows total life cycle CO₂e based on calculated results

Dashboard controls

Table results auto-update based on

parameter values above

12

Boundaries for Natural Gas Life Cycle Cradle-to-grave

– 1 MWh of electricity delivered to the end customer

– Compared 12 different fuel/baseload plant combinations

(6 natural gas, 6 coal)

Cradle-to-gate

– 1 MMBtu of domestic fuel delivered to large end user

– Compared 13 fuel sources/mixes

(10 natural gas, 3 coal)

Pipeline

Operation (Energy and Combustion Emissions)

Plant Operation

Plant

Construction

Pipeline

Construction

Trunkline

Operation

Switchyard and Trunkline

Construction

Transmission &

Distribution

Raw Material Acquisition

Raw Material Transport

Energy Conversion Facility

Product Transport

CCUS Operation

CCUS Construction

Gas CentrifugalCompressor

Valve FugitiveEmissions

Dehydration

Acid GasRemoval

Reciprocating

Compressor

Electric

Centrifugal

Compressor

Liquids

UnloadingVenting/Flaring

WorkoversVenting/Flaring

Other Point

Source EmissionsVenting/Flaring

Other Fugitive

Emissions

Venting/Flaring

Venting/Flaring

Well

Construction

Well

CompletionVenting/Flaring

Other Point

Source EmissionsVenting/Flaring

Other Fugitive

Emissions

Valve Fugitive

Emissions

Venting/Flaring

Venting/Flaring

Raw Material Extraction Raw Material Processing

Diesel

Steel

Concrete

Surface Water

for

Hydrofracking (Marcellus Only)

Transport of Water by Truck

(Marcellus Only)

Flowback Water Treated at a

WWTP(Marcellus Only)

Diethanolamine

Steel

Concrete

Electricity

Cast Iron

Steel

Concrete

Electricity

Pipeline

Operation (Fugitive

Methane)

Flowback Water Treated by

Crystallization(Marcellus Only)

Diesel

Electricity

Water Withdrawal and

Discharge During Well Operation

Aluminum

Diesel

End Use

(Assume 100%Efficient)

EndUse

13

Onshore vs. Shale GHG Emission Profiles

Cra

dle

-to

-Gat

e

Pip

elin

e Fu

giti

ve E

mis

sio

ns

Pip

elin

e C

om

pre

sso

rs

Pip

elin

e C

on

stru

ctio

n

Co

mp

ress

ors

Val

ve F

ugi

tive

Em

issi

on

s

Oth

er P

oin

t So

urc

e Em

issi

on

s

Oth

er F

ugi

tive

Em

issi

on

s

Deh

ydra

tio

n

Aci

d G

as R

emo

val

Val

ve F

ugi

tive

Em

issi

on

s

Oth

er P

oin

t So

urc

e Em

issi

on

s

Oth

er F

ugi

tive

Em

issi

on

s

Wo

rko

vers

Wel

l Co

mp

leti

on

Wel

l Co

nst

ruct

ion

Processing Extraction

RMT RMA

CO₂ CH₄ N₂O

0

5

10

15

20

25

30

35

40

45

50

Cra

dle

-to

-Gat

e

Pip

elin

e Fu

giti

ve E

mis

sio

ns

Pip

elin

e C

om

pre

sso

rs

Pip

elin

e C

on

stru

ctio

n

Co

mp

ress

ors

Val

ve F

ugi

tive

Em

issi

on

s

Oth

er P

oin

t So

urc

e Em

issi

on

s

Oth

er F

ugi

tive

Em

issi

on

s

Deh

ydra

tio

n

Aci

d G

as R

emo

val

Val

ve F

ugi

tive

Em

issi

on

s

Oth

er P

oin

t So

urc

e Em

issi

on

s

Oth

er F

ugi

tive

Em

issi

on

s

Wo

rko

vers

Liq

uid

Un

load

ing

Wel

l Co

mp

leti

on

Wel

l Co

nst

ruct

ion

Processing Extraction

RMT RMA

Gre

en

ho

use

Gas

Em

issi

on

s (l

bs

CO

₂e/M

MB

tu) CO₂ CH₄ N₂O

Onshore Gas (34.2 lbs CO₂e/MMBtu)

Carbon dioxide equivalents calculated using 2007 IPCC 100-year GWP

Shale Gas (32.5 lbs CO₂e/MMBtu)

13% of Natural Gas Extracted from the Earth is Consumed for Fuel Use, Flared,

or Emitted to the Atmosphere (point source or fugitive)

Of this, 70% is Used to Power Equipment

14

Onshore vs. Shale GHG Emission Profiles Sensitivity of Model Result to Changes in Parameter Values

Percentages above are relative to a unit change in parameter value; all parameters are changed by the same amount, allowing comparison of the magnitude of change to the result across all parameters.

Example: A 10% increase in Onshore Production Rate from 66 Mcf/day to 73 Mcf/day would result in a 4.5% (10% of 45%) decrease in cradle-to-gate emissions, from 34.2 to 32.6 lbs CO2e/MMBtu.

-2%

2%

3%

4%

9%

16%

20%

-34%

45%

45%

-45%

-60% -40% -20% 0% 20% 40% 60%

Processing Flare Rate (100%)

Well Depth (6,529 ft.)

Other Fugitives, Processing (0.03 lbs CH₄/Mcf)

Other Fugitives, Extraction (0.043 lbs CH₄/Mcf)

Pneum. Vent. Rate, Extraction (0.11 lbs CH₄/Mcf)

Pipeline Fugitive Rate (0.0003 lbs CH₄/Mcf-mi.)

Pipeline Distance (604 miles)

Extraction Flare Rate (51%)

Liquid Unloading Vent Rate (23.5 Mcf/episode)

Liquid Unloading Freq. (930 episodes/well)

Production Rate (66 Mcf/day)

3%

4%

-6%

-6%

10%

10%

17%

21%

33%

33%

-42%

-60% -40% -20% 0% 20% 40% 60%

Other Fugitives, Processing (0.03 lbs CH₄/Mcf)

Other Fugitives, Extraction (0.043 lbs CH₄/Mcf)

Extraction Flare Rate (15%)

Processing Flare Rate (100%)

Pneum. Vent. Rate, Extraction (0.11 lbs CH₄/Mcf)

Completion Vent. Rate (11,647 Mcf/episode)

Pipeline Fugitive Rate (0.0003 lbs CH₄/Mcf-mi.)

Pipeline Distance (604 miles)

Workover Vent. Rate (11,643 Mcf/episode)

Workover Frequency (3.5 Episodes/well/yr)

Production Rate (274 Mcf/day)


Onshore Gas (34.2 lbs CO₂e/MMBtu)

Shale Gas (32.5 lbs CO₂e/MMBtu)

15

2,475 2,493

2,112 2,127

1,140 1,179 1,162 1,100

1,687

506 611

386

0

500

1,000

1,500

2,000

2,500

3,000

Flee

t B

asel

oad

EXP

C

IGC

C

SCP

C

Flee

t B

asel

oad

Flee

t B

asel

oad

Flee

t B

asel

oad

NG

CC

GTS

C

IGC

C

SCP

C

NG

CC

Average Illinois No. 6 Conv. UnConv. Average With Carbon Capture

Coal Natural Gas

Gre

en

ho

use

Gas

Em

issi

on

s (l

bs

CO

₂e/M

Wh

)

Fuel Acquisition Fuel Transport Power Plant T&D

Comparison of Power Generation Technology Life Cycle GHG Footprints

1,162

1,556

2,475

2,661

28.4

68.6

12.3

30.1

0

20

40

60

80

100

0

600

1,200

1,800

2,400

3,000

10

0-y

r

20

-yr

10

0-y

r

20

-yr

10

0-y

r

20

-yr

10

0-y

r

20

-yr

Natural Gas Coal Natural Gas Coal

Fleet Baseload Power Extraction & Delivery

lbs

CO

₂e/M

MB

tu

lbs

CO

₂e/M

Wh

Upstream GHG emissions are greater for natural gas than coal; full life cycle emissions are larger for coal

than natural gas

Source of natural gas or coal has little effect on full life cycle emissions for GHGs

16

High Level Process Flow for Alternative Jet Fuel Raw Material Acquisition

(RMA)Raw Material Transport

(RMT)Energy Conversion (EC) Product Transport (PT) End Use (EU)

Montana Rosebud Coal Mining

Southern Pine Biomass Production

Land Use Change

Rail Transport of Coal

Truck Transport of Biomass

Torrefaction of Biomass

Truck Transport of Torrefied Biomass

Carbon Management: Enhanced Oil Recovery

Pipeline Transport of CO2

CBTL Facility (F-T Jet Fuel Production)6 Scenarios:0% Biomass

10% Green Biomass20% Green Biomass

10% Torrefied Biomass20% Torrefied Biomass

10% Green Biomass, Separate Gasifiers

Pipeline Transport of F-T Jet Fuel

Pipeline Transport of Blended Jet Fuel

Blending50% F-T Jet Fuel

50% Conv. Jet Fuel(by vol)

Petroleum Refinery (2005 US Average)

Crude Oil Transport (2005 US Average)

Crude Oil Extraction (2005 US Average)

Aircraft Operation (Blended Jet Fuel

Combustion)

Scenarios 4, 5 OnlyScenarios 4, 5 Only

System Boundary

Scenarios 2-6 OnlyScenarios 2-6 Only

Existing & Emerging GHG Emissions Regulations

– Section 526, Energy Independence and Security Act (EISA) of 2007:

Life Cycle GHG emissions for

alternative fuels contracted by a

Federal agency other than for

research and testing must be less

than or equal to life cycle

emissions from conventional fuel

from conventional sources

– Other existing and emerging federal/state regulations: US EPA Renewable Fuels Standard; CA Low Carbon Fuel Standard, etc.

17

Underlying Data Based on Detailed Mass and Energy Balance of an F-T Process

Coal

Handling

Coal Milling

Drying

TRIG

Gasifier

Raw Shift

COS Hyd

Heat Recovery Hg2-Stage

SelexolSulfur

Polish

Claus

CO2 Purification

& Compression

Sour Water

Stripper

COT

PRB Coal

ASU

Gas Turbine

Steam Turbine

HRSG

Cooling Tower

FT Synthesis

Raw Product

Separation

CO2 Removal

Wax SeparatorDistillation

Hydrocracking/

Hydrotreating

Hydrotreating

Distillation

Air

Cryogenic

Separation

Autothermal

Reformer

PSA

~

~

Condenser

O2

CO2

Wax

H2FT Jet

FT Naphtha

FT Diesel

N2

Power

Power

Sulfur

H2

H2

Syngas,Light HC

CW Make-up

Air

Air

StackLPG

H2

CW

FTRecycle

FT Recycle

Steam

Ash

to WWTP

CO2 to Seq

Fuel Gas

To Fired Heaters

Fired HeatersAir

1 2

6

to Hydrotreater

to FT Recycle

to Gas Turbine

9

14

15

7

8

12

13

18

16

17

19

20

21

22

23

11

10

H2SBiomass

Handling

Biomass

Prep &

Drying

Raw Biomass

3 4

18

70

80

90

100

110

Disp. Energy Comb. Disp. Energy Comb. Disp. Energy Comb. Disp. Energy Comb. Disp. Energy Comb. Disp. Energy Comb.

0% Biomass 10% Biomass, Chipped 10% Biomass, Chipped, Separate Gasifiers

10% Biomass, Torrefied 20% Biomass, Chipped 20% Biomass, Torrefied

Gre

en

ho

use

Gas

Em

issi

on

s (g

CO

₂e/M

J)

Conventional Jet Fuel Baseline, 87.4 g CO₂e/MJ

Overall CBTL Jet Results, with 90% Capture and CO₂-EOR

$0

$50

$100

$150

$200

$/bbl $/bbl $/bbl $/bbl $/bbl $/bbl

0% Biomass 10% Biomass, Chipped 20% Biomass, Chipped 10% Biomass, Torrefied 20% Biomass, Torrefied 10% Biomass, Chipped, Separate Gasifiers

Cru

de

Oil

Equ

iv.

Re

qu

ire

d S

elli

ng

Pri

ce

Method for allocating impacts of co-products drive GHG results

19

Underlying Detail Allows for Detailed Results with Sensitivity and Uncertainty

0.01

0.01

0.01

-0.02

0.03

0.07

-0.17

0.19

0.21

0.47

0.82

-0.40 -0.20 0.00 0.20 0.40 0.60 0.80 1.00

Biomass Truck Distance (Farm to CBTL or Farm to Torrefaction)

CO₂ Pipe Loss Rate

Chip Type

Blended Jet Alt Transport Scenario

Blended Jet Pipe Length

CO₂ Pipe Distance

Biomass Yield

Coal Mine Methane

Indirect Land Use

Rail Distance

CBTL Plant Operations Scenario

Coefficient Value

81.9 0.0

72.7 0.1

7.1 0.1 0.0 0.1

2.6 0.8

0.0 0.0 0.0 0.2 0.1

-2.5 0.5

-5 5 15 25 35 45 55 65 75 85

Total Greenhouse Gas Emissions

Airplane Operation (Fuel Use)

Blending of F-T and Conv. Jet (includes Conv. Jet Fuel Profile)

CO₂-EOR Operation and CO₂ Storage

CBTL Plant Operations (includes CO₂ Compression)

Transport of Chipped or Torrefied Biomass to CBTL Plant

Biomass Transport to Torrefaction Facility

Biomass Direct Land Use Change

Coal Mining, Surface

Greenhouse Gas Emissions (g CO₂e / MJ)

CO₂ CH₄ N₂O SF₆

20

Life Cycle Boundaries for Nuclear Power

LC Stage #2 Raw Material

Transport

LC Stage #3 Energy Conversion

Facility

LC Stage #4 Product Transport

LC Stage #1 Raw Material Acquisition

Grid Transport of Electricity

Uranium Conversion

Gaseous Diffusion

Enrichment

Gaseous Centrifuge Enrichment

Fuel Rod Delivery

Existing Reactor

Technology

Uranium Underground Mining and

Milling

Uranium Solution Mining

Uranium Open Pit Mining and

Milling

Fuel Rod Fabrication

Gen III + Reactor

Technology

Study focuses on life cycle comparison of existing reactor technology currently installed in US with the Gen III+ reactor designs currently

under review at the NRC

21

Life Cycle GHG Profile for Existing and Gen III+ Nuclear Power in the United States

38.8

25.2

11.7 9.4

0

10

20

30

40

50

Existing Gen III+ Existing Gen III+

Diffusion Enrichment in the US Centrifuge Enrichment in the US

Gre

enh

ou

se G

as E

mis

sio

ns

(kg

CO

2e/

MW

h)

Uranium Enrichment Electricity T&D Power Plant Const and Decom Fuel Assembly Uranium Extraction Uranium Conversion Fuel Transport


Diffusion enrichment is leading contributor to GHG emissions in nuclear fuel cycle because of electricity

requirements of process

Switching from gaseous diffusion to centrifuge enrichment in US can lead to 60-70% reduction in

GHG emissions from fuel cycle depending on reactor type

22

Nuclear Power Life Cycle Cost Results

$53.7

$36.2

$94.1

$63.1

$150.7

$100.9

$0

$50

$100

$150

$200

$250

Existing Gen III+ Existing Gen III+ Existing Gen III+

Scenario A Scenario B Scenario C

Leve

lize

d C

ost

of

Ele

ctri

city

(2

00

8$

/MW

h)

Financial Parameter Input

Scenario A

Minimize

LCOE

Scenario B

Best Estimate

Scenario C

Maximize

LCOE

Debt Term (Years) 30 20 10

Interest Rate on Loan (%) 5% 8% 10%

Depreciation Period (Years) 7 10 20

Expected Rate of Return (%) 7% 15% 20%

Uncertainty bars represent range of LCOE for a given financial scenario based on range of LCC

plant operations parameters (capital costs, plant capacity, fuel costs, operating & maintenance

costs, and decommissioning costs)

Plant Operations Input Existing Gen III+

Min LCOE Best Est. LCOE Max LCOE Min LCOE Best Est. LCOE Max LCOE

Plant Capacity (MWe) 1,500 1,000 850 1,500 1,000 850

Unit Cost of Fuel ($/MMBtu) 0.29 0.67 1.08 0.17 0.40 0.63

Overnight Costs ($/kWe) 3,500 4,500 6,500 1,800 3,000 5,000

Fixed O&M ($/kWe/yr) 55 64 75 35 42 50

Variable O&M ($/kWh) 0.0047 0.0075 0.0100 0.0047 0.0075 0.0100

Decommissioning Costs (Million $) 350 600 1,000 350 600 1,000

23

Raw Material Transport

Raw Material

Acquisition


Land Preparation

Hybrid Poplar Cultivation

Hybrid Poplar Harvesting

Subcritical Cofire

Power Plant

Truck Transport

Switchyard and Trunkline Operation

Rail Transport

Illinois No. 6 Coal Mining

Biomass Grinding

Product Transport

End Use

Equipment Manufacturing

Diesel Production

Underground Mine

Construction

Equipment Manufacturing Diesel

Production

Diesel Production

Equipment Manufacturing

Diesel Production

Biomass Drying Biomass

Torrefaction

Transmission &

Distribution

End Use (Assume 100%

Efficient)

Natural Gas

Electricity

Power Plant Retrofit

Construction

Power Plant De-

commissioning

Natural Gas

Life Cycle Process Flow for Retrofit Cofire Power

24

302.23

0.91

283.45

0.00

7.80

1.89

4.59

0.09

0.06

0.05

1.20

0.05

-44.04

16.33

5.73

24.09

0.01

0.00

-100 -50 0 50 100 150 200 250 300 350 400

Total

Transmission & Distribution

Boiler Operations (Combustion)

Retrofit Construction

Biomass Drying

Natural Gas Extraction (Drying)

Biomass Grinding

Biomass Transport

Diesel Production

Truck & Trailer Manufacturing

Coal Transport

Locomotive Manufacturing

Cultivation

Direct Land Use Change

Indirect Land Use Change

Coal Mining

Direct Land Use Change

Indirect Land Use Change

Bio

mas

s Ill

. #6

B

iom

ass

Ill. #

6

ECF

RM

T R

MA

Greenhouse Gas Emissions (g CO₂e/MJ)

CO₂ CH₄ N₂O SF₆

GHG Drilldown: 20% Hybrid Poplar Cofire

• After CO₂ emissions from 33% efficient PC boiler, largest contribution to GHGs is CH₄

from Illinois No. 6 underground mining

• Sequestered CO₂ from cultivation is largely offset by land use change and methane from

coal mining

25

310

93

28

290

58

23

310

84

26

270

73

27

230

23

19

260

54

24

240

62

26

170

-40

9.2

220

20

19

94

72 80

67 74 65 59 60

-70% -91% -7% -81% -93% 0% -73% -91% -73% -90% -15% -91% -93% -4% -80% -91% -74% -89% -29% -117% -96% -8% -92% -92% 1.5% -22% -14% -27% -20% -29% -36% -35% -200

-100

0

100

200

300

400

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

CC

S

CC

US

CC

S

CC

US

CC

S

CC

US

CC

S

CC

US

Coal only Forest Residue 10% by Energy

Hybrid Poplar 10% by Energy





Illinois No. 6 Coal Only

Illinois No. 6 Coal Only

Switchgrass 10% by energy


PC, 550 MW, No Capture, 33% Eff. PC, 385 MW, CO₂ Capture, 22% Eff.

SCPC, 550 MW, No Capture, 39% Eff. SCPC, 550 MW, CO₂ Capture, 27% Eff.

CFB, 550 MW, No Capture, 43% Eff. CFB, 550 MW, CO₂ Capture, 34% Eff.

CTL, 109 MW Export Power

CTL, 397 MW Export Power

CBTL, FT Diesel 49

MW Export Power

CBTL, FT Diesel 319 MW Export

Power

Cofire Existing Plant Options Retire & Replace w/ New Powerplant Options Cogasification Options

Gre

enh

ou

se G

as E

mis

sio

ns

(g C

O₂e

/MJ)

Land use RMA RMT ECF T&D Use Net CO₂e


• Due to data limitations,

the ECF results for

CTL/CBTL include RMA

and RMT.

Life Cycle GHG Emissions of Cofiring Options

• Percent changes for cofiring cases are relative to no capture, coal

only case within each technology group

• Percent changes for CTL/CBTL cases are relative to petroleum

baseline (92.3 g CO₂e/MJ)

26

31

90

29 35

95

33

40

100

41

63

110

61 66

120

64

73

130

74 73

120

80 78

130

83 88

140

97

78

60

90

67

86

67

86

67

$0

$20

$40

$60

$80

$100

$120

$140

$160

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

No

Cap

ture

CC

S

CC

US

CC

S

CC

US

CC

S

CC

US

CC

S

CC

US

CC

S

CC

US







Coal Only Coal Only Switchgrass 10% by energy


PC, 550 MW, No Capture, 33% Eff. PC, 385 MW, CO₂ Capture, 22% Eff.

SCPC, 550 MW, No Capture, 39% Eff. SCPC, 550 MW, CO₂ Capture, 27% Eff.

CFB, 550 MW, No Capture, 43% Eff. CFB, 550 MW, CO₂ Capture, 34% Eff.

CTL Recycle (110 MW Export)

CTL Once-Through (397 MW Export)

CBTL Recycle (49 MW Export)

CBTL Once-Through (319 MW Export)


Co

st o

f El

ect

rici

ty o

r R

eq

uir

ed

Se

llin

g P

rice

($

/MW

h)


Cofire Plant Options: COE (Power) and Required Selling Price (Fuel)

100% coal, no-capture CTL RSP (not shown) is

$2.53/gallon ($72.7/MWh)

27

-219

-284

-22

-254 -289

-5

-228

-285

-46

-239

-285

-77

-289 -293

-56

-258 -288

-75

-250 -286

-138

-349

-303

-94

-292 -293

-500

-400

-300

-200

-100

0

CCS CCUS No Capture

CCS CCUS No Capture

CCS CCUS No Capture

CCS CCUS No Capture

CCS CCUS No Capture

CCS CCUS No Capture

CCS CCUS No Capture

CCS CCUS No Capture

CCS CCUS

0% Biomass Forest Residue 10% by Energy






PC, 550 MW, No Capture, 33% Eff.

PC, 385 MW,

CO₂ Capture, 22% Eff.

SCPC, 550 MW, No Capture, 39% Eff.

SCPC, 550 MW,


CFB, 550 MW, No Capture, 43% Eff.

CFB, 550 MW,


Cofire Existing Power Plant Options Retire & Replace with New Power Plant Options

∆ L

C G

HG

Em

issi

on

s (

g C

O₂e

/MJ)

-70% -91% -7% -82% -93% -1% -73% -92% -25% -93% -94% -18% -83% -92% -24% -80% -92% -24% -80% -92% -44% -112% -97% -30% -94% -94%

$61.5

$0.7 $6.3

$66.3

$4.5 $11.6

$74.2

$12.4

$34.5

$85.9

$32.5 $37.2

$93.2

$35.4 $43.8

$103.0

$45.2 $44.2

$93.7

$51.3 $48.9

$98.5

$54.2 $59.3

$112.0

$67.8

$0

$40

$80

$120

∆ C

OE

($/

MW

h)

$71

$1

$72 $66

$4

$626

$82

$11

$188

$91

$29

$121 $81

$30

$198

$101

$40

$149

$95 $45

$89 $71 $45

$158

$97 $58

$0

$175

$350

$525

$700

Cofire Existing Power Plant Options Retire & Replace with New Power Plant Options

Co

st o

f LC

GH

G A

bat

emen

t (

$/sh

ort

to

n C

O₂e

)

Cost of Improving the Existing Coal Fleet

Abatement costs and percent changes relative to the U.S. fleet baseload coal plant, at $29/MWh and 312 g CO₂e/MJ

%

change

28

How does cofiring compare to other power technology options?

146

312

259

56

262

61

305

139

48

212

2 13 7

118

5 8 12

0

50

100

150

200

250

300

350

400

Gre

en

ho

use

Gas

Em

issi

on

s (g

CO

₂e/M

J)

Raw Material Acquisition Raw Material Transport Energy Conversion Facility

Product Transport Retro. PC, 10% FR CFB, 30% FR

$33 $29

$79 $105

$60

$103

$18

$65 $92 $101

$77

$268

$85 $93 $74 $86

$108

$0

$50

$100

$150

$200

$250

$300

Co

st o

f El

ect

rici

ty (

$/M

Wh

)

Capital Fuel Fixed O&M Variable O&M Retro. PC, 10% FR CFB, 30% FR

29

CFB

PC EXPC

Fleet Coal

Fleet Gas

Geothermal

GTSC

Hydro (Uprate)

IGCC

NGCC

Nuclear (Gen III+)

Wind (Offshore) Wind (Onshore)

-50

0

50

100

150

200

250

300

350

$0 $20 $40 $60 $80 $100 $120 $140 $160

Gre

en

ho

use

Gas

Em

issi

on

s (g

CO

₂e/M

J)

Cost of Electricity ($/MWh)

Life Cycle GHG Emissions versus Cost of Electricity

Base case power (no biomass or CCS/CCUS)

Coal-biomass cofiring cases

CCS/CCUS cases

30

CFB: 30% HP

CFB: 30% FR

PC: 10% FR

PC: 20% FR

PC: 10% HP

PC: 20% HP SCPC: 13% HP

SCPC: 13% FR

PC: 10% CS PC: 20% CS

PC: 10% SG

PC: 20% SG

-50

0

50

100

150

200

250

300

350

$0 $20 $40 $60 $80 $100 $120 $140 $160

Gre

en

ho

use

Gas

Em

issi

on

s (g

CO

₂e/M

J)





CCS/CCUS cases

31

CFB: 100% Coal CCS

CFB: 100% Coal CCUS

CFB: 30% HP CCS CFB: 30% HP CCUS

CFB: 30% FR CCS

CFB: 30% FR CCUS

PC: 100% Coal CCS

PC: 100% Coal CCUS

PC: 10% FR CCS

PC: 10% FR CCUS

PC: 10% HP CCS

PC: 10% HP CCUS SCPC: 13% HP CCS

SCPC: 13% HP CCUS SCPC: 13% FR CCS

SCPC: 13% FR CCUS

-50

0

50

100

150

200

250

300

350

$0 $20 $40 $60 $80 $100 $120 $140 $160

Gre

en

ho

use

Gas

e E

mis

sio

ns

(g C

O₂e

/MJ)





CCS/CCUS cases

32

-50

0

50

100

150

200

250

300

350

$0 $20 $40 $60 $80 $100 $120 $140 $160

Gre

en

ho

use

Gas

e E

mis

sio

ns

(g C

O₂e

/MJ)





CCS/CCUS cases

33

Modeling Structure of Wind Farm

Onshore Wind Farm Operation

Switchyard Trunkline

Construction

Steel Recycling

Copper Recycling

Domestic Turbine Component

Manufacturing

Foreign Turbine Component

Manufacturing

Aluminum Recycling

Landfill

Onshore Conventional

Wind Farm Construction

Onshore Conventional

Wind Farm Construction

Offshore Wind Farm

Construction

Offshore Wind Farm Operation

Key: Process or Material Flow Waste or Recycling flow

to LC Stage #4

Upstream stages for backup power are

accounted for in LC Stage #1 and LC Stage

#2 of model

34

GHG Emissions for Wind with Backup Power

20.3

15.0

-5

0

5

10

15

20

25

Conventional Wind Turbine

Advanced Wind Turbine

Gre

en

ho

use

Gas

Em

issi

on

s (k

g C

O₂e

/MW

h)

Recycling: Steel

Recycling: Copper

Recycling: Aluminum

Construction: Switchyard

Wind Farm Operation

Construction: Trunkline

Construction: Wind Farm

Electricity Transmission & Distribution

Negative GHG emissions represent displacement caused by recycling of manufacturing scrap and materials recovered from end-of-life management of turbines

• If availability of wind power is considered, environmental burdens of wind power must also account for backup power

– Nominal onshore wind farm capacity factor is 30%

• Two backup power sources were modeled:

– Average U.S. power mix – Load-following GTSC plant

20.3 15.0

532.9 531.3 506.7 505.1

0

200

400

600

800

1,000

Conv. Advanced Conv Advanced Conv Adv

Grid GTSC

Standalone Backup

Gre

en

ho

use

Gas

Em

issi

on

s

(kg

CO

₂e/M

Wh

)

LC GHG GTSC 2007 N.A. Grid Mix

35

Upcoming Work:

Dynamic Coal-Biomass Power with

Emissions Control Options

36

LC Stage #1 LC Stage #2 LC Stage #3

Raw Material Acquisition Raw Material Transport


Lignite

Sub-Bit (PRB)

Train

SRWC (Poplar)

Switchgrass

Truck Biomass Grinding

Biomass Drying

Biomass Torre.

Ultra-SCPC (Air Fired)

Ultra-SCPC (Oxy Fired)

SC CFB (Air Fired)

SC CFB (Oxy Fired)

CO2 Capture

Sequestration CO2 EOR

O2

CaCO3

NH3

No CO2 Capture

SCPC or SC CFB Plant

Const.

Cooling Tech.

Building a Dynamic Power Plant with Linear Programming

37

Ultra-Supercritical PC and Circulating Fluidized Bed (CFB) Cases

• Potential for hundreds of possible permutations, not including options for emissions control technology such as advanced scrubbers and filters

Coal type Lignite Sub-bit

Biomass % 0 10 20

Biomass Type Switchgrass SRWC (Poplar)

Torrefaction Yes No

Plant Type Ultra SC CFB

Combustion Oxy Air

Cooling Dry Wet-dry

CO₂ Capture 90 95 99

CCUS EOR Saline

38

Recently Published and Forthcoming Work www.netl.doe.gov/energy-analysis

• LCA of Natural Gas Extraction, Delivery and Electricity Production (1/12)

• LC GHG Analysis of Advanced Jet Propulsion Fuels: Fischer-Tropsch Based SPK-1 Case Study (12/11)

• Calculating Uncertainty in Biomass Emissions: Model and Documentation (11/11)

• LC GHG Inventory of Natural Gas Extraction, Delivery and Electricity Production (12/11)

• LCA: Ethanol from Biomass (8/11)

• LC GHG Analysis of Natural Gas Extraction & Delivery in the U.S. (5/11)

• Comparative Assessment of CO₂ Sequestration through EOR and Saline Aquifer (1/11)

• LCA: Power Studies Compilation (1/2011)

• LCA: Existing Pulverized Coal Power Plant (12/10)

• LCA: Integrated Gasification Combined Cycle Power Plant (12/10)

• LCA: Natural Gas Combined Cycle Power Plant (12/10)

• LCA: Supercritical Pulverized Coal Power Plant (12/10)

• Alternative Liquid Fuels Simulation Model (3/10)

• Balancing Climate Change, Energy Security, and Economic Sustainability: A LC Comparison of Diesel Fuel from Crude Oil and Domestic Coal and Biomass Resources (4/09)

• Framework and Guidance for Estimating GHG Footprints of Aviation Fuels (4/09)

• Evaluation of the Extraction, Transport and Refining of Imported Crude Oils and the Impact on LC GHG Emissions (3/09)

• Consideration of Crude Oil Source in Evaluating Transportation Fuel GHG Emissions (3/09)

• Affordable, Low-Carbon Diesel Fuel from Domestic Coal and Biomass (1/09)

• Development of Baseline Data and Analysis of LC GHG Emissions of Petroleum-Based Fuels (11/08)

Forthcoming

– Cofiring Coal & Biomass in the U.S.

– Technology Assessments

(Comb. LCA, LCC & Resource Projection)

• Nuclear

• Cofiring

• Wind

• Natural Gas

• Hydro

• Geothermal

• Solar Thermal

– Updated Baseline LCAs • NGCC

• IGCC

39

Contact Information

Timothy J. Skone, P.E. Lead General Engineer OSEAP - Planning Team (412) 386-4495

[email protected]

Robert James, PhD General Engineer OSEAP - Planning Team (304) 285-4309

[email protected]

Joe Marriott, PhD Lead Associate Booz Allen Hamilton (412) 386-7557

[email protected]

NETL www.netl.doe.gov

Office of Fossil Energy www.fe.doe.gov

Documents

Overview of Energy Life Cycle Analysis at NETLegon.cheme.cmu.edu/esi/docs/pdf/ESI_Seminar_04_25_2012.pdf · Overview of Energy Life Cycle Analysis at NETL (The Agenda) 1. LCA Definitions