On the integration of sequential supplementary firing in natural gas combined...
2016.12.14 DryFining Coal Gen presentation FINAL
1. Six years of operating
experience with DryFiningTM
fuel enhancement process
Sandra Broekema, Una Nowling, and Nenad Sarunac
14 December 2016
1
2. 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
4. •Coal is crushed to ¼ inch minus and fed to the first
stage of the FBD
The DryFining process: Stage 1
4 4
1
st
Stage
Dust
Collector
Dust Collector
Fan
Scrubbing
Box
2
nd
Stage
Feed Stream
(Crushed Wet Coal ) Dilution Air
Product Stream
Auger
Segregation Stream
3
rd
Stage
3 rd
Stage
Fluidizing
Air (Cold PA)
1 st
and 2 nd
Stage Fluidizing Air
(Heated Cold PA)
Moist Fluidizing Air & Elutriated Fines
Screw
Feeder
5. • Coal is dried in a fluidized bed using low-grade waste heat
from the power station
The DryFining process: Stage 2
5
5
1
st
Stage
Dust
Collector
Dust Collector
Fan
Scrubbing
Box
2
nd
Stage
Feed Stream
(Crushed Wet Coal ) Dilution Air
Product Stream
Auger
Segregation Stream
3
rd
Stage
3 rd
Stage
Fluidizing
Air (Cold PA)
1 st
and 2 nd
Stage Fluidizing Air
(Heated Cold PA)
Moist Fluidizing Air & Elutriated Fines
Screw
Feeder
6. • Dried coal is cooled slightly in the third stage before delivery
to the product coal belt and silos
The DryFining process: Stage 3
6
1
st
Stage
Dust
Collector
Dust Collector
Fan
Scrubbing
Box
2
nd
Stage
Feed Stream
(Crushed Wet Coal ) Dilution Air
Product Stream
Auger
Segregation Stream
3
rd
Stage
3 rd
Stage
Fluidizing
Air (Cold PA)
1 st
and 2 nd
Stage Fluidizing Air
(Heated Cold PA)
Moist Fluidizing Air & Elutriated Fines
Screw
Feeder
7. -600
-500
-400
-300
-200
-100
0
100
Y0 Y1 Y2 Y3 Y4 Y5 Y6 Y7 Y8 Y9 Y10Y11Y12Y13Y14Y15
CAPEX+OPEX
(US$Million)
Competitive technology CAPEX/OPEX side-by-side
Conventional
DryFining
Life cycle cost justification
7
T
A
B
L
E
2
1200 MW Capacity CAPEX and OPEX (million USD2007
)
Conventional AQCS DryFining
CAPEX OPEX CAPEX OPEX COST/Ton
Scrubber 104 1.8 O&M 240 3.1 $ 0.38
NOx SNCR 18 14 Savings (20.4) $ (2.41)
Hg COHPAC 138 4.5
TOTAL 260 20.3 TOTAL 240 (17.3) $ (2.03)
avoided annual expense net annual operational cost
7
8. 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 Hg
Reduced NOX
Reduced SO2
Reduced CO2
Reduce Fan & Mill Power
Reduced Maintenance
FuelSavings
Net Savings
DryFiningNet SavingsUSD/Ton
DryFining Power
DryFining Labor
DryFining Parts
8 8
9. •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
11. • 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
12. 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
13. 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
14. • Greater NPHR benefit as the PRB blend percentage increases
Coal blend sensitivity - NPHR
14
15. • Spray flow was reduced for both main and reheat steam, as
PRB content increased
Coal blend – steam generator impacts
15
16. • 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
17. • Dried PRB use could be increased to 60% by mass without any
derate. Additional generation was possible at all blend levels
over30%
Coal blend sensitivity – derate risk
17
18. • Annual CO2 emissions were reduced due to heat rate
improvement.
Coal blend sensitivity – CO2 emissions
18
19. • 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 Ebsilon
Professional (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
20. Properties of selected coals
Coal 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 27.00
H %, wt 2.40 3.31 4.50 2.66 1.90
S %, wt
1.04 0.37 2.51 0.14 0.80
O %, wt 8.53 11.87 6.88 13.58 10.30
N %, wt 0.64 0.70 1.12 0.63 0.30
H2O %, wt
40.00 30.24 11.12 40.76 55.80
Ash %, wt 11.72 5.33 9.99 2.03 3.90
HHV Btu/lb
6,147 8,340 11,670 6,937 4,457
LHV Btu/lb 5,603 7,722 11,143 6,269 3,704
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23. Case study 2: Net unit efficiency
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
5 10 15 20 25 30 35 40
NetUnitEfficiencyImprovement[%-point,HHV]
Total Coal Moisture Content, TM [%]
Indonesian Coal: Wara Subcritical
SC
USC
A-USC
SUBC with ICDS
SC with ICDS
USC with ICDS
A-USC
ICDS = LT Integrated Coal Drying System
Waste HeatWaste + Process Heat
Reference Plant
23
24. 300
350
400
450
500
550
600
650
5 10 15 20 25 30 35 40
CoalFlowRate[g/kWh-gross]
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
1
3
2
4
25. Case study 2: New build economics
A-USC Power Plant:
Fuel Powder River Basin (PRB)
Overnight Cost $2,933/MWh
1.00
1.05
1.10
1.15
1.20
1.25
5,000 7,000 9,000 11,000 13,000 15,000
RelativeCapitalCost
Coal Heating Value, Btu/lb HHV
EPRI, “MATERIALS FOR ADVANCED ULTRASUPERCRITICAL STEAM TURBINES”
Final Technical Report
Reporting Period: Oct.1, 2009 - Sep. 30, 2015
DOE Cooperative Agreement: DE-FE0000234
Ohio Coal Development Office Grant Agreement: D-05-02(B)
Holt N, G. Booras and D. Todd, The
Gasification Technologies Conference,
San Francisco, CA 2003.
25
26. Case study 2: Capital costs and savings
0
50
100
150
200
250
300
350
400
5 10 15 20 25 30
CapitalCostsandSavings[$/kW]
Reduction in Total Coal Moisture Content, DTM [%-point]
Indonesian: WaraCore System Cost, A-USC
Core System Cost, USC
Reduction in Plant Cost, A-USC
Reduction in Plant Cost, USC
CAPEX Savings, A-USC
CAPEX Savings, USC
NET CAPEX
Savings
A-USC
USC
Core System Cost
Reduction in
Plant Cost
USC
A-USC
A-USC
USC
Reference Plant
26
28. • 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
29. TECHNICAL CONTACTS
Una Nowling
Black & Veatch
Overland Park, KS USA
NowlingUC@bv.com
Nenad Sarunac
University of North Carolina
Charlotte, NC USA
nsarunac@uncc.edu
BUSINESS CONTACT
Sandra Broekema
Great River Energy
Minneapolis, MN USA
(612) 280-8689
sbroekema@GREnergy.com
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