Cost and Performance Baseline for Fossil Energy Plants – Volume 2 Coal to Synthetic Natural Gas and Ammonia

Cost and Performance Baseline for Fossil Energy Plants – Volume 2

Coal to Synthetic Natural Gas and AmmoniaU.S. Department of Energy

National Energy Technology LaboratoryJuly 2011

2

Coal to SNG Study, July 2011

Disclaimer

This presentation was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.

3


Objective

• Determine cost and performance estimates of near-term commercial offerings for the production of synthetic natural gas (SNG) and ammonia both with and without CO2 sequestration.– Consistent design requirements– Up-to-date performance and capital cost

estimates– Technologies built now and deployed in the near

term• Provides baseline costs and performance

– Comparison of study natural gas and ammonia prices with current market prices

4


Study Matrix

Products ST Cond.(psig/°F/°F)

Coal Type

Coal Drying Gasifier

Technology OxidantAcid Gas Removal/

CO2 Separation / Sulfur Recovery

CO2

Capture1

SNG 1800/1050/1000

Illinois No.6

Conven-tional Siemens 99 mol%

O2

Selexol / Selexol / Claus 90%

Montana Rosebud

PRBWTA Siemens 99 mol%

O2


North Dakota Lignite

WTA Siemens 99 mol% O2


SNG/ NH3

1800/1050/1000

Illinois No.6

Conven-tional Siemens 99 mol%

O2


PRB– Powder River BasinWTA – Fluidized bed dryer with integrated waste heat recovery (German)

1 There is CO2 capture in every case, but CO2 is sequestered only in the even numbered cases

5


Design Basis: Coal Type

Coal Ultimate Analysis (weight %)Illinois #6 Powder River Basin North Dakota Lignite

As Rec’d Dry As Rec’d Dry As Rec’d Dry

Moisture 11.12 0 25.77 0 36.08 0

Carbon 63.75 71.72 50.07 67.45 39.55 61.88

Hydrogen 4.50 5.06 3.38 4.56 2.74 4.29

Nitrogen 1.25 1.41 0.71 0.96 0.63 0.98

Chlorine 0.29 0.33 0.01 0.01 0 0

Sulfur 2.51 2.82 0.73 0.98 0.63 0.98

Ash 9.70 10.91 8.19 11.03 9.86 15.43

Oxygen (by difference) 6.88 7.75 11.14 15.01 10.51 16.44

Total 100 100 100 100 100 100

HHV (Btu/lb) 11,666 13,126 8,564 11,516 6,617 10,427

6


Economic Assumptions for First Year Cost of Production

First Year of Capital Expenditure 2007Economic Analysis Period 35 years

Dollars 2007Coal ($/MM Btu) Illinois No. 6 1.64 PRB 0.89 Lignite 0.83Capacity Factor (%) 90

5 Year Construction Period

High Risk

First Year Capital Charge Factor 24.49%

7


I

II

III

STUDY CATEGORY

Order of Magnitude Estimate (+/- >50% Accuracy)• Very little project-specific definition• Rough scaling of previous related but dissimilar analyses• “Back-of-the-envelope” analyses

Concept Screening (+/- 50% Accuracy)• Preliminary mass and energy balances • Modeling and simulation of major unit operations• Factored estimate based on previous similar analyses

Budget Estimate (+30% / -15% Accuracy)• Thorough mass and energy balances • Detailed process and economic modeling• Estimate based on vendor quotes, third-party EPC firms

Technical ApproachSystems Analyses Categorization

8


Technical Approach

1. Extensive Process Simulation (ASPEN) All major chemical processes and equipment are simulated Detailed mass and energy balances Performance calculations (auxiliary power, SNG/ammonia

production, gross/net power output)

2. Cost Estimation Inputs from process simulation (Flow Rates/Gas

Composition/Pressure/Temp.) Sources for cost estimation

WorleyParsons Vendor sources where available Follow DOE Analysis Guidelines

9


Study Assumptions

• Capacity Factor assumed to equal Availability at 90%– The addition of CO2 capture, compression, and sequestration

and an ammonia co-production facility was assumed not to impact the availability factor

• Methanation system was modeled using Haldor Topsoe’s high temperature TREMP™ process

• Ammonia reaction was modeled at 2,030 psia based on the Haldor Topsoe S-300 Ammonia Synthesis Loop

• In CO2 sequestration cases, CO2 was compressed to 2,200 psig, transported 50 miles, sequestered in a saline formation at a depth of 4,065 feet and monitored for 80 years

• CO2 transport, storage and monitoring (TS&M) costs were included in the first year cost of production (COP) for sequestration cases

10


SNG and SNG/Ammonia Plants

11


Siemens Gasifier

• SNG production is based on nominal thermal input of 500 megawatt-thermal (MWth) to the gasifier.

• Actual gasifier thermal input varies according to the type of coal feed and ranges from 506 to 550 MWth.

• Heat Recovery includes a partial quench followed by a syngas cooler (This configuration is not currently a commercial offering by Siemens, but is planned for future coal-to-SNG projects)

Source: Siemens

12


Coal

OxygenGasifierSiemens

Water Gas Shift

Cryogenic ASU

Steam

2-Stage Selexol

ClausPlant

Sulfur

CO2 Comp.

CO2

Steam

Methanation Reactors

Syngas Cooler/Quench

Water Scrubber

COSHydrolysis

Mercury Removal

SNG Purification

SNG Comp.

SNG for Export

Cases 2, 6 and 8 onlyCoal

Dryer

SNG Plant with CO2 Capture (Sequestration in Cases 2,6, and 8*)

Emission Controls:SOx: Selexol AGR removal of sulfur to < 6 ppmv H2S in syngas

Claus plant with tail gas recycle for ~99.8% overall S recoveryHg: Activated carbon beds for ~95% removalSteam Turbine: 302 - 311 MW (Steam is produced primarily from syngas

cooler and methanation process, but is not shown in BFD)Steam Conditions: 1800 psig/1050°F/1000°F

*Note: Cases 5thru 8 do not have a COS hydrolysis reactor in the bypass stream

13


Steam

Coal

OxygenGasifier*Siemens

Water Gas Shift

Cryogenic ASU

Steam

2-Stage Selexol

ClausPlant

Sulfur

CO2 Comp.

CO2

Steam

Methanation Reactors

Syngas Cooler/Quench

Water Scrubber

COSHydrolysis

Mercury Removal

SNG Purification

SNG Comp.

SNG for Export

Water Gas Shift

Mercury Removal

2-Stage Selexol PSA

Purge Nitrogen

Ammonia Production

Ammonia Product

Coal Dryer

Case 4 Only

Reaction Nitrogen

SNG/Ammonia Plant with CO2 Capture (Sequestration in Case 4)

14


Performance Results

Illinois No. 6Illinois No. 6

NH3 Co-production

PRB ND Lignite

CO2 Sequestration NO YES NO YES NO YES NO YES

Gross Power (MW) 308 311 292 292 302 302 306 311

Net Power (MW) 92 49 29 -24 54 2 46 -3SNG Production (Bscf/yr)1 57 56 42 42 55 55 52 52

NH3 Production (TPD) N/A N/A 2,204 2,204 N/A N/A N/A N/A

Conversion Eff. (%)2 61.4 61.3 61.5 61.4 63.1 63.1 61.5 61.5

SNG HHV (Btu/scf) 964 964 964 964 973 973 970 969

1 Assumes capacity factor of 90%2 Conversion efficiency is HHVSNG/HHVcoal for SNG only cases and (HHVSNG + HHVNH3)/HHVcoal for co-production cases

15


Economic Results

Illinois No. 6Illinois No. 6

NH3 Co-production

PRB ND Lignite

CO2 Sequestration NO YES NO YES NO YES NO YES

TOC, $MM1 3,235 3,313 3,742 3,830 3,354 3,442 3,504 3,595

Capital FY COP ($/MMBtu) 14.58 14.94 11.90 12.25 15.34 15.76 17.13 17.59

Fixed FY COP ($/MMBtu) 1.76 1.79 1.41 1.45 1.84 1.86 2.03 2.06

Variable FY COP ($/MMBtu) 1.03 1.04 0.79 0.82 1.02 1.03 1.18 1.18

Fuel FY COP ($/MMBtu) 2.67 2.67 1.89 1.89 1.41 1.41 1.34 1.35Electricity FY COP ($/MMBtu) -0.77 -0.41 -0.17 0.15 -0.46 -0.02 -0.42 0.03

CO2 TS&M FY COP ($/MMBtu) 0.00 0.91 0.00 1.29 0.00 0.96 0.00 1.03

Total FY COP2 ($/MMBtu) 19.27 20.95 15.82 17.85 19.15 21.01 21.27 23.24

Ammonia FY COP ($/ton) N/A N/A 799 828 N/A N/A N/A N/AFY CO2 Avoided Cost, $/ton N/A 16.65 N/A 13.47 N/A 16.79 N/A 16.57

1 Total Overnight Cost (Includes Total Plant Cost plus preproduction costs, inventory capital, financing costs, and other owner’s costs)2 90% capacity factor and 24.49% first year capital charge factor

16


Environmental Performance Comparison

17


Criteria Pollutant Emissions for All Cases

0.027

0.000

0.023

0.001

0.022

0.000

0.024

0.000

0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

0.000

0.005

0.010

0.015

0.020

0.025

0.030

Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8

SNG Only SNG and Ammonia SNG Only SNG Only

Emiss

ions

, lb/

MM

Btu

(bas

ed o

n Th

erm

al In

put) SO2

Particulate

Illinois No. 6 Powder River Basin North Dakota Lignite

18


Mercury Emissions for All Cases

5.71E-07 5.71E-07 5.71E-07 5.71E-07

3.51E-07 3.51E-07

5.60E-07 5.60E-07

0.0E+00

1.0E-07

2.0E-07

3.0E-07

4.0E-07

5.0E-07

6.0E-07

7.0E-07



Emiss

ions

, lb/

MM

Btu

(bas

ed o

n Th

erm

al In

put)

Hg Illinois No. 6 Powder River Basin North Dakota Lignite

19


CO2 Emissions for All Cases

128

5

147

10

140

1

147

10

20

40

60

80

100

120

140

160

180



Emiss

ions

, lb/

MM

Btu

(bas

ed o

n Th

erm

al In

put)

CO2 Illinois No. 6 Powder River Basin North Dakota Lignite

20


Raw Water Withdrawal and Consumption Comparison

21


Raw Water Withdrawal and Consumption

7.1 7.17.5 7.5

4.9

5.5

4.4

5.1

1.5 1.5 1.5 1.51.1 1.2 1.1 1.2

5.7 5.76.0 6.0

3.8

4.3

3.4

3.9

0

1

2

3

4

5

6

7

8

9

10



Wat

er, g

pm x

1,00

0

Water WithdrawalProcess DischargeWater Consumption


22


Economic Results for All Cases

23


CO2 Avoided Costs

16.65

13.47

16.79 16.57

0

5

10

15

20

25

30

SNG Illinois 6 SNG/NH3Illinois 6

SNG PRB SNG Lignite

Firs

t Yea

r CO

2Av

oide

d Co

st ($

/ton

)

CO2 Avoided Cost

24


Plant Cost Comparison

1,939 1,9882,271 2,325

2,024 2,079 2,120 2,179

180 185213 218

188 193 197 202385 396

440 452

403 415 421 434125 125

125 125

126 126 126 126607 620

694 710

613 629 640 6543,235 3,313

3,742 3,830

3,354 3,442 3,504 3,5953,886 3,979

4,495 4,600

4,029 4,134 4,209 4,318

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC

SNG Illinois 6 SNG Illinois 6 w/ Capture

SNG/NH3Illinois 6

SNG/NH3 Illinois 6 w/ Capture

SNG PRB SNG PRB w/ Capture

SNG Lignite SNG Lignite w/ Capture

Capi

tal C

ost,

$1,0

00,0

00

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost

Powder River Basin North Dakota LigniteIllinois No. 6

25


Cost of Production Comparison

14.58 14.9411.90 12.25

15.34 15.76

17.13 17.59

1.76 1.79

1.41 1.45

1.84 1.862.03 2.06

1.03 1.04

0.79 0.82

1.02 1.03

1.18 1.18

2.67 2.67

1.89 1.89

1.41 1.411.34 1.35

0.91

1.29

0.96

1.03

19.2720.95

15.82

17.85

19.1521.01 21.27

23.24

14.20

8.38

4.40

-5

0

5

10

15

20

25

30

35

40

SNG Illinois 6 SNG Illinois 6 w/ Capture

SNG/NH3Illinois 6

SNG/NH3 Illinois 6 w/ Capture

SNG PRB SNG PRB w/ Capture

SNG Lignite SNG Lignite w/ Capture

FYCO

P, $

/MM

Btu

CO2 TS&M CostsFuel CostsVariable CostsFixed CostsCapital CostsElectricity Revenue/CostEIA projected average price for 2035EIA projected average price for 2020Henry Hub price (Jun-29-2011)


26


Highlights

27


NETL Viewpoint

• Most up-to-date performance and costs currently available in public literature

• Establishes baseline performance and cost estimates for current state of technology

• Reduced costs are required to improve competitiveness of coal-to-SNG processes– In today’s market and regulatory environment – Also in a carbon constrained scenario

• Ammonia co-production provides the most attractive SNG prices

28


Result Highlights: Efficiency & Capital Cost• HHV Conversion Efficiencies

– Illinois No. 6: 61.3% to 61.5%– Powder River Basin: 63.1%*– North Dakota Lignite: 61.5%

• Total Overnight Cost without Sequestration (MM$):– Illinois No. 6 SNG: $3,235– Illinois No. 6 SNG/NH3: $3,742– Powder River Basin SNG: $3,354– North Dakota Lignite SNG: $3,504

• Total Overnight Cost with Sequestration (MM$):– Illinois No. 6 SNG: $3,313– Illinois No. 6 SNG/NH3: $3,830– Powder River Basin SNG: $3,442– North Dakota Lignite SNG: $3,595

*PRB has the highest conversion efficiency of 63.1% primarily due to the low nitrogen and high oxygen content in the design fuel, which enables the SNG product to have a relatively lower concentration of inerts.

29


Results Highlights: FY COP

• FY COP ($/MMBtu) without Capture:– Illinois No. 6 SNG: 19.27– Illinois No. 6 SNG and NH3: 15.82 (NH3 = $799/ton)– Powder River Basin SNG: 19.15– North Dakota Lignite SNG: 21.27

• FY COP ($/MMBtu) with Capture:– Illinois No. 6 SNG: 20.95– Illinois No. 6 SNG and NH3: 17.85 (NH3 = $828/ton)– Powder River Basin SNG: 21.01– North Dakota Lignite SNG: 23.24

30


Summary Table for All Cases

31


Summary TablePERFORMANCE Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8CO2 Sequestration No Yes No Yes No Yes No Yes

SNG Production (Bscf/year)1 57 56 42 42 55 55 52 52Ammonia Production (TPD)1 N/A N/A 2,204 2,204 N/A N/A N/A N/AHHV Conversion Efficiency, % 61.4% 61.3% 61.5% 61.4% 63.1% 63.1% 61.5% 61.5%Gross Power Output (kWe) 308,000 310,600 292,300 292,300 302,000 302,000 305,800 310,500Auxiliary Power Requirement (kWe) 216,350 262,090 263,600 316,030 247,570 300,190 259,740 313,930Net Power Output (kWe) 91,650 48,510 28,700 -23,730 54,430 1,810 46,060 -3,430Coal Flowrate (lb/hr) 964,752 964,752 964,000 964,000 1,259,331 1,259,331 1,564,932 1,564,932HHV Thermal Input (kW th) 3,298,455 3,298,455 3,295,885 3,295,885 3,160,745 3,160,745 3,034,796 3,034,796Raw Water Withdrawal (gpm) 7,169 7,123 7,434 7,458 4,853 5,509 4,421 5,131Process Water Discharge (gpm) 1,462 1,451 1,455 1,461 1,071 1,218 1,071 1,230Raw Water Consumption (gpm) 5,708 5,672 5,979 5,997 3,783 4,291 3,350 3,901CO2 Emissions (lb/MMBtu)2 128 5 147 10 140 0.7 147 0.9

SO2 Emissions (lb/MMBtu)2 0.0274 0.0003 0.0229 0.0006 0.0218 0.0000 0.0239 0.0000

NOx Emissions (lb/MMBtu)2 Negligible Negligible Negligible Negligible Negligible Negligible Negligible NegligiblePM Emissions (lb/MMBtu)2 0.007 0.007 0.007 0.007 0.007 0.007 0.007 0.007Hg Emissions (lb/MMBtu)2 5.71E-07 5.71E-07 5.71E-07 5.71E-07 3.51E-07 3.51E-07 5.60E-07 5.60E-07COSTTotal Plant Cost ($ x 1,000) 2,628,754 2,692,997 3,048,463 3,119,611 2,741,044 2,813,258 2,864,478 2,941,335Total Overnight Cost ($ x 1,000) 3,235,262 3,312,740 3,742,411 3,829,817 3,354,442 3,442,310 3,504,262 3,595,468 Bare Erected Cost ($ x 1,000) 1,938,987 1,987,745 2,270,675 2,324,594 2,023,833 2,078,723 2,120,358 2,178,744 Home Office Expense ($ x 1,000) 180,084 184,716 213,101 218,235 187,854 193,059 196,659 202,203 Process Contingency ($ x 1,000) 125,003 124,952 124,890 124,877 126,177 126,063 126,234 126,189 Project Contingency ($ x 1,000) 384,680 395,583 439,797 451,906 403,179 415,413 421,228 434,199 Owner's Costs ($ x 1,000) 606,508 619,743 693,948 710,206 613,398 629,053 639,784 654,134Total As-spent Capital ($ x 1,000) 3,885,549 3,978,601 4,494,636 4,599,610 4,028,684 4,134,215 4,208,619 4,318,158SNG FYCOP ($/MMBtu)1 19.27 20.95 15.82 17.85 19.15 21.01 21.27 23.24 CO 2 TS&M Costs 0.00 0.91 0.00 1.29 0.00 0.96 0.00 1.03 Fuel Costs 2.67 2.67 1.89 1.89 1.41 1.41 1.34 1.35 Variable Costs 1.03 1.04 0.79 0.82 1.02 1.03 1.18 1.18 Fixed Costs 1.76 1.79 1.41 1.45 1.84 1.86 2.03 2.06 Electricity Costs -0.77 -0.41 -0.17 0.15 -0.46 -0.02 -0.42 0.03 Capital Costs 14.58 14.94 11.90 12.25 15.34 15.76 17.13 17.59Ammonia FYCOP3 ($/ton) - - 799 828 - - - -1 Based on a capacity factor of 90 percent for all cases2 Based on coal thermal input3 Ammonia price is correlated to historic natural gas costs

SNG OnlyRosebud PRB North Dakota LigniteIllinois No. 6 Coal

SNG Only SNG and Ammonia SNG Only

32


Fuel Quality

33


• The SNG produced in this study is at the low end of the acceptable quality range.– HHVs - 965-975 Btu/scf– Wobbe Indices -1,265-1,275– Inert concentrations - 3-4.5 %

• The primary reason for the lower quality product is the absence of higher hydrocarbons.

• The quality of the SNG produced in this study could be enhanced with minor impact on overall cost by the following…– Increase the oxygen purity from 99% to 99.5%.– Upgrade the PSA by increasing the bed depth or adding beds in

series.– Blend other gases into the pipeline to achieve a desired Wobbe

Index value.• Purity requirements will be dictated by location and fuel end

use.

SNG Fuel Quality

34


Sensitivity to Financing Scenario

35


Sensitivity to ROE

0

200

400

600

800

1000

1200

1400

0

5

10

15

20

25

30

35

40

45

50

5% 10% 15% 20% 25%

Amm

onia

LCO

P ($

/ton

)

SNG

FYCO

P ($

/MM

Btu)

Return on Equity

Case 8 SNG PriceCase 2 SNG PriceCase 6 SNG PriceCase 7 SNG PriceCase 1 SNG PriceCase 5 SNG PriceCase 4 SNG PriceCase 3 SNG PriceCase 4 Ammonia PriceCase 3 Ammonia Price

High Risk Fuels Projectwith ROE - 12%

First Year CCF - 0.1344

High Risk Fuels Project with ROE - 20%First Year CCF - 0.2449

Ammonia Price Curves

36


Favorable Financial Structure Economic Pathway

1. Modify financing structurea) Increase percentage of debt from 50%

to 70% and decrease interest on debt from 9.5% to 4.5%

b) Increase loan repayment term from 15 years to 30 years

c) Decrease capital expenditure period from 5 years to 4 years

2. Reduce capital cost escalation during the capital expenditure period from 3.6% to 0%

3. Reduce owner’s cost from 23% to 18%4. Reduce taxes and insurance in fixed O&M

costs from 2% to 0.4%5. Assume CO2 revenue value for enhanced

oil recovery of $10/tonne

20.04

15.1713.47

12.68 12.29 12.0111.23

10.31

16.56

12.6011.06

10.30 9.96 9.71 9.008.20

0

5

10

15

20

25

NETL Study Step 1a Step 1b Step 1c Step 2 Step 3 Step 4 Step 5

SNG

COP

$/M

MBt

u (e

xclu

ding

TS&

M c

osts

)SNG from Illinois 6 with CO2 Capture

SNG and Ammonia from Illinois 6 with CO2 Capture

37


Technology Maturity Economic Pathway

1. Modify financinga) Decrease interest on debt from 9.5%

to 4.5%b) Decrease required internal rate of

return on equity from 20% to 12%

2. Reduce capital cost by 22% to reflect FOAK to NOAK improvements

20.0418.54

12.21

10.31

16.5615.67

10.028.20

0

5

10

15

20

25

NETL Study Step 1a Step 1b Step 2

SNG

COP

$/M

MBt

u (e

xclu

ding

TS&

M c

osts

)SNG from Illinois 6 with CO2 Capture

SNG and Ammonia from Illinois 6 with CO2 Capture

Cost and Performance Baseline for Fossil Energy Plants – Volume 2 Coal to Synthetic Natural Gas and Ammonia

Documents

sng study

sng nh3180010501000illinois

o2selexol selexol claus90

united states government

study matrixproductsst

year cost of production

performance baseline

conventionalsiemens99