Six years of operating experience with DryFiningTMfuel enhancement process

Sandra Broekema, Una Nowling, and Nenad Sarunac14 December 2016

1

Upgrading 1000 TPH lignite since 12/2009 Dries fuel from 38 down to 30 percent moisture by weight HHV increase 6200 to 6800 Btu/lb Net plant heat rate gain of 4.5% Emission reductions:

► SO2 by >40%► Mercury by 35 to 40%► NOx by 20% to 30%► CO2 by 4%

Coal Creek Station – 2 x 600 MW

Dryer house

Coal Creek Station

2

DryFining mass balance illustration

DryFine

3 3

• Coal is crushed to ¼ inch minus and fed to the first stage of the FBDThe DryFining process: Stage 1

4 4

1st Stage

Dust Collector

Dust Collector Fan

ScrubbingBox

2nd Stage

Feed Stream(Crushed Wet Coal ) Dilution Air

Product Stream

Auger

Segregation Stream

3rd Stage

3 rd StageFluidizing Air (Cold PA)

1 st and 2 nd Stage Fluidizing Air (Heated Cold PA)

Moist Fluidizing Air & Elutriated FinesScrewFeeder

• Coal is dried in a fluidized bed using low-grade waste heat from the power station

The DryFining process: Stage 2

5 5

1st Stage

Dust Collector

Dust Collector Fan

ScrubbingBox

2nd Stage

Feed Stream(Crushed Wet Coal ) Dilution Air

Product Stream

Auger

Segregation Stream

3rd Stage

3 rd StageFluidizing Air (Cold PA)

1 st and 2 nd Stage Fluidizing Air (Heated Cold PA)

Moist Fluidizing Air & Elutriated FinesScrewFeeder

• Dried coal is cooled slightly in the third stage before delivery to the product coal belt and silosThe DryFining process: Stage 3

6

1st Stage

Dust Collector

Dust Collector Fan

ScrubbingBox

2nd Stage

Feed Stream(Crushed Wet Coal ) Dilution Air

Product Stream

Auger

Segregation Stream

3rd Stage

3 rd StageFluidizing Air (Cold PA)

1 st and 2 nd Stage Fluidizing Air (Heated Cold PA)

Moist Fluidizing Air & Elutriated FinesScrewFeeder

-600-500-400-300-200-100

0100

Y0 Y1 Y2 Y3 Y4 Y5 Y6 Y7 Y8 Y9 Y10Y11Y12Y13Y14Y15

CAPEX

+ OPEX

(US

$ Millio

n)

Competitive technology CAPEX/OPEX side-by-side

ConventionalDryFining

Life cycle cost justification

7

TABLE2

1200 MW Capacity CAPEX and OPEX (million USD2007) Conventional AQCS DryFining

CAPEX OPEX CAPEX OPEX COST/TonScrubber 104 1.8 O&M 240 3.1 $ 0.38 NOx SNCR 18 14 Savings (20.4) $ (2.41)

Hg COHPAC 138 4.5TOTAL 260 20.3 TOTAL 240 (17.3) $ (2.03)avoided annual expense net annual operational cost

7

Net operational savings per ton of fuel

$(0.08)$(0.18)

$(0.12)$0.09

$0.17 $0.42

$0.53 $0.27 $0.28

$0.65 $2.03

$(0.50) $- $0.50 $1.00 $1.50 $2.00 $2.50

Reduced HgReduced NOXReduced SO2Reduced CO2

Reduce Fan & Mill PowerReduced Maintenance

Fuel SavingsNet Savings

DryFining Net Savings USD/Ton

DryFining PowerDryFining LaborDryFining Parts

8 8

•Reduced coal flow through the power block•Reduced flue gas production•Increased boiler efficiency•Reduced auxiliary power consumption•Improved net plant heat rate•Improved emissions control performance•Reduced carbon intensity

Benefits of advanced beneficiation

9

EPRI VISTA conceptual case studies

10

• A 665 MW (gross) sub-critical boiler, designed for NAPP/CAPP coal, currently burning 30 percent PRB coal• Estimated 180 MW derate if 100 percent PRB was burned

• Due to mill grinding and mill drying capability, both directly impacted by the coal moisture content• Modeled PRB coal moisture reduction from 23.9 percent to 15.9 percent via DryFining• Result: 59 MW derate with 100 percent PRB, gain 121 MW• Goals:

• Estimate O&M cost differences• Estimate maximum PRB coal use potential

Case study 1: 665 MW PRB retrofit

11

Case study 1: estimated CAPEX

12

Estimated CAPEX for DryFining retrofit of 665 MW PRB DryFining modules including fluidizing air fans, internal heating coils, dust collector & stub stack $9,000,000 External heat exchangers $2,250,000 Controls $1,000,000 Air Jig $187,500 Crusher $495,000 Sub-total equipment (FOB factory) $12,932,500 Installation (80% factor) $10,346,000 Engineering, License & Contingency $10,223,663 Total installed cost (+/- 30%) $33,500,000

Case study 1: O&M cost savings

13

Potential O&M cost reductions for 665 MW Retrofit PRB Power Station Impacts Reduced annual coal burn (tonnes per year) 202,440 Reduced auxiliary power/station service (GWh/year) 8.72 Improved unit availability (GWh/year) 34.51 Recovered unit capacity (GWh/year) 427.33 Cost impacts (replacement generation cost of $30/MWh and delivered coal cost of $62/tonne) Differential annual maintenance $162,000 Differential annual coal burn rate $12,551,280 Differential annual auxiliary power $261,600 Improved annual unit availability $1,035,300 Recovered annual unit capacity $12,819,900 Total annual savings $26,830,080

• Greater NPHR benefit as the PRB blend percentage increasesCoal blend sensitivity - NPHR

14

• Spray flow was reduced for both main and reheat steam, as PRB content increased

Coal blend – steam generator impacts

15

• Mill equivalent forced outage hours decreased significantly with dried PRB use, due to reduced fuel burn rate and reduced moisture content.

Coal blend sensitivity – mill EFOR

16

• Dried PRB use could be increased to 60% by mass without any derate. Additional generation was possible at all blend levels over 30%

Coal blend sensitivity – derate risk

17

• Annual CO2 emissions were reduced due to heat rate improvement.

Coal blend sensitivity – CO2 emissions

18

• A 860 MW (gross) reference plant operating on Indonesian WARA• Modelled Indonesian WARA coal moisture reduction from 40 percent to 25 percent using using Proates (boiler) and EbsilonProfessional (steam turbine cycle) • Goals:

• Thermal integration to estimate moisture removal achievable• Calculate net unit efficiency across various power cycles• Estimate impact on new build CAPEX with and without DryFining

Case study 2: 860 MW reference plant

19

Properties of selected coalsCoal Units ND lignite

Sub-bituminous(Wyoming PRB)Bituminous (hard) coal (Illinois No.6)

Indonesian (Wara)German brown coal (Niederlausitz)

C %, wt 35.68 48.18 63.75 40.20 27.00H %, wt 2.40 3.31 4.50 2.66 1.90S %, wt 1.04 0.37 2.51 0.14 0.80O %, wt 8.53 11.87 6.88 13.58 10.30N %, wt 0.64 0.70 1.12 0.63 0.30H2O %, wt 40.00 30.24 11.12 40.76 55.80Ash %, wt 11.72 5.33 9.99 2.03 3.90HHV Btu/lb 6,147 8,340 11,670 6,937 4,457LHV Btu/lb 5,603 7,722 11,143 6,269 3,70420

21

Case study 2: HHV vs. coal moisture

Case study 2: Net unit efficiency

33.8

35.6

38.8

41.9

36.6

38.6

41.9

45.3

36.4

38.4

41.8

45.1

3233343536373839404142434445464748

Subcritical Supercritical USC A-USC

Net U

nit Ef

ficien

cy [%

-HHV]

Indonesian Coal: WaraIndonesian, TM=41%Indonesian, TM=35%Indonesian, TM=30%Indonesian, TM=25%Indonesian, TM=20%Indonesian, TM=15%Indonesian, TM=10%Bituminous (Hard), TM=11%

Reference Plant

22

Case study 2: Net unit efficiency

0123456789

101112131415

5 10 15 20 25 30 35 40

Net U

nit Ef

ficien

cy Im

provem

ent [%

-point

, HHV

]

Total Coal Moisture Content, TM [%]

Indonesian Coal: Wara SubcriticalSCUSCA-USCSUBC with ICDSSC with ICDSUSC with ICDSA-USC

ICDS = LT Integrated Coal Drying System

Waste HeatWaste + Process Heat

Reference Plant

23

300

350

400

450

500

550

600

650

5 10 15 20 25 30 35 40

Coal F

low Ra

te [g/

kWh-g

ross]

Total Coal Moisture Content, TM [%]

Supercritical unit using dried Indonesian Wara

Case study 2: Coal flow rate change

ICDS = LT Integrated Coal Drying System

Efficiency improvement

Evaporated Coal Moisture

24

13

2

4

Case study 2: New build economicsA-USC Power Plant:Fuel Powder River Basin (PRB)Overnight Cost $2,933/MWh

1.00

1.05

1.10

1.15

1.20

1.25

5,000 7,000 9,000 11,000 13,000 15,000

Relat

ive Ca

pital C

ost

Coal Heating Value, Btu/lb HHV

EPRI, “MATERIALS FOR ADVANCED ULTRASUPERCRITICAL STEAM TURBINES”Final Technical ReportReporting Period: Oct.1, 2009 - Sep. 30, 2015DOE Cooperative Agreement: DE-FE0000234 Ohio Coal Development Office Grant Agreement: D-05-02(B)

Holt N, G. Booras and D. Todd, The Gasification Technologies Conference, San Francisco, CA 2003.

25

Case study 2: Capital costs and savings

0

50

100

150

200

250

300

350

400

5 10 15 20 25 30

Capit

al Cos

ts an

d Savi

ngs [

$/kW]

Reduction in Total Coal Moisture Content, DTM [%-point]

Indonesian: WaraCore System Cost, A-USCCore System Cost, USCReduction in Plant Cost, A-USCReduction in Plant Cost, USCCAPEX Savings, A-USCCAPEX Savings, USC

NET CAPEX Savings

A-USC

USC

Core System Cost

Reduction inPlant Cost

USC

A-USC

A-USC

USC

Reference Plant

26

Water recovery potential at 60 percent

50

100

150

200

250

300

350

400

5 10 15 20 25 30 35

Evap

orated

Coal M

oistur

e [klb

/hr]

Total Coal Moisture Content, TM [%]

Indonesian: WaraSubcriticalSCUSCA-USCCondensed, SubcriticalCondensed, SCCondensed, USCCondensed, A-USC

27

860 MW Reference Plant

60% Recovery

• Pulverized coal combustion will continue to play a significant role in power generation for the foreseeable future• Higher quality fuels increase efficiency and performance, especially in advanced power cycles • Advanced beneficiation, like DryFining, can deliver cost-effective fuel enhancement providing greater fuel flexibility, derate recovery and efficiency improvement• New construction is ideally suited to optimize the thermal integration to reduce both CAPEX and OPEX

Summary

28

TECHNICAL CONTACTSUna NowlingBlack & VeatchOverland Park, KS USA NowlingUC@bv.com

Nenad SarunacUniversity of North CarolinaCharlotte, NC USAnsarunac@uncc.edu

BUSINESS CONTACTSandra BroekemaGreat River EnergyMinneapolis, MN USA(612) 280-8689sbroekema@GREnergy.com

29