28329 Data

AXG-9-29432-01 document.xls

COMPARATIVE ANALYSIS OF ALTERNATIVE MEANS

for

REMOVING NONCONDENSABLE GASES

from

FLASHED-STEAM GEOTHERMAL POWER PLANTS

by Subcontractors :

Martin Vorum, P.E.

and

Eugene A. Fritzler, P.E.

Subcontract Number AXG-9-29432-01Under Prime Contract Number DE-AC36-98GO10337

for Contractor :

Midwest Research InstituteNational Renewable Energy Laboratory Division

1617 Cole BoulevardGolden, Colorado 80401

March 2000



for


from


by Subcontractors :

Martin Vorum, P.E.

and



for Contractor :



March 2000


TABLE OF CONTENTS

TITLE SUMMARY

1 1 Title & Contents (this worksheet)

2 2.1 User Guide Control button links to sections of spreadsheet

3 2.2 Bases&Input Technical and financial bases and assumptions of study

4 2.3 Flowsheets Case study process flowsheets -- mass and energy flows

5 2.4 CalcLogic Illustration of engineering calculation sequences

6 3.1 Main Case Summaries Consolidated plant operating data -- primary input to this spreadsheet

7 3.2 Sensitivity Case Summaries Consolidated plant operating data -- secondary input, special conditions

8 3.3 FigMerit Graphs Plots of figures of merit versus noncondensable gas values (primary data results)

9 3.3a Alt FigMerit Graphs Plots of figures of merit, using NPV results for economic analyses.

10 3.4a Auxiliary Graphs Plots of steam use by gas removal systems -- mass flow demand

11 3.4b % SteamUse Plots of steam use by gas removal systems -- percent of turbine feed rates

12 3.5 Issues Bar chart of qualitative advantages/disadvantages

13 4.1 Op's Details Calculated operational power plant performance profiles

14 4.2 EnFig Merit Engineering figure of merit calculations -- relative performance efficiency

15 4.3 $ FigMerit Economic figure of merit calculations -- Simple Payback Period

16 4.3a Alt $ FigMerit Economic figure of merit calculations -- Net Present Value results

17 4.3b Present Values Net Present Value calculation details

18 4.4 CostData Installation and unit costs of gas removal process systems

SEQ.NO.

WORK SHEET


19 5 SensiComp Comparison of sensitivity calculation results

Notes on worksheets:

There are two sets of calculations of economic figures of merit, and correspondingly two sets of plots of the figures of merit. The original figure of merit calculated the "simple payback period." This was deemed inadequate for detailed technology comparisons, so the "alternative economic figure of merit was added, which calculates net present values (NPV) for comparing gas removal options' economic benefits more precisely.

The payback period calculation was retained in the comparisons and brief discussion of the sensitivity cases.



for


from


by Subcontractors :

Martin Vorum, P.E.

and



for Contractor :



March 2000



for


from


by Subcontractors :

Martin Vorum, P.E.

and



for Contractor :



March 2000


TABLE OF CONTENTS

SUMMARY

Control button links to sections of spreadsheet

Technical and financial bases and assumptions of study

Case study process flowsheets -- mass and energy flows

Illustration of engineering calculation sequences

Consolidated plant operating data -- primary input to this spreadsheet

Consolidated plant operating data -- secondary input, special conditions

Plots of figures of merit versus noncondensable gas values (primary data results)

Plots of figures of merit, using NPV results for economic analyses.

Plots of steam use by gas removal systems -- mass flow demand

Plots of steam use by gas removal systems -- percent of turbine feed rates

Bar chart of qualitative advantages/disadvantages

Calculated operational power plant performance profiles

Engineering figure of merit calculations -- relative performance efficiency

Economic figure of merit calculations -- Simple Payback Period

Economic figure of merit calculations -- Net Present Value results

Net Present Value calculation details

Installation and unit costs of gas removal process systems


Comparison of sensitivity calculation results

Notes on worksheets:

There are two sets of calculations of economic figures of merit, and correspondingly two sets of plots of the figures of merit. The original figure of merit calculated the "simple payback period." This was deemed inadequate for detailed technology comparisons, so the "alternative economic figure of merit was added, which calculates net present values (NPV) for comparing gas removal options' economic benefits more precisely.

The payback period calculation was retained in the comparisons and brief discussion of the sensitivity cases.

Sheet 2.1 UserGuide

AXG-9-29432-01document.xls Page 2.9 10:22:18

04/18/2023

USERS' GUIDE

WORKSHEET TITLE SUMMARY

1 Title & Contents Title page and table of contents

2.2 Bases&Input Technical bases and assumptions of study

2.3 Flowsheets Case study process flowsheets

3.1 Main Case Summaries Consolidated case study results

3.2 Sensitivity Case Summaries Sensitivity Case Study Results

3.3 FigMerit Graphs Plots of case study results

4.1 Case Details (Op's Details) Project case studies: power plant data performance data

4.2 EnFig Merit Engineering figure of merit calculations

4.3 $ FigMerit Economic figure of merit calculations

4.4 Cost Data Costs of major equipment units

Shortcut Keys

The buttons below relocate the users' view to the indicated worksheet. Use these to quickly navigate the key sections of the spreadsheet. The corresponding worksheets also have "return" buttons to come back to this central directory.

Basis

Summaries

Charts

Case Details

Flow Sheets

EngFig Merit Calc

Capital Eq. Cost

Economic Mierit

Sensitiv ities

Title & Contents

Sheet 2.1 UserGuide

AXG-9-29432-01document.xls Page 2.10 10:22:18

04/18/2023

USERS' GUIDE

SUMMARY

Title page and table of contents

Technical bases and assumptions of study

Case study process flowsheets

Consolidated case study results

Sensitivity Case Study Results

Plots of case study results

Project case studies: power plant data performance data

Engineering figure of merit calculations

Economic figure of merit calculations

Costs of major equipment units

The buttons below relocate the users' view to the indicated worksheet. Use these to quickly navigate the key sections of the spreadsheet. The corresponding worksheets also have "return" buttons to come back to this central directory.

Sheet 2.2 Bases&Input

AXG-9-29432-01document.xls

2.2.11 10:22:1804/18/2023

SHADED CELLS ARE USER ADJUSTABLE

TECHNICAL AND FINANCIAL PERFORMANCE FACTORS

Annual Stream Factor 90% power plant percent of time on-line

Operating Cost Multipliers O&M Salvage Labor Load(a) (a) (b) (c)

steam jet ejector systems 5% 10% - 0%hybrid systems 5% 10% - 0%

turbocompressor systems 5% 10% - 0%biphase eductor systems 5% 10% - 0%

reboiler process 5% 10% - 0%

a -- as percent of installed capital costb -- equivalent worker(s) per system

Electricity Contract Price $ 0.040 per kilowatt-hour (basis for credit forsavings in gas-removal power losses)

Financial Analysis Variables

Annual Capital Discount Rate 10.00% (nominal)Annual Cost Inflation Rate 2.0% general inflation, e.g. wages, materials, equipment, etc.Annual Electricity Price Inflation 2.0% inflation (or deflation) of electricity contract priceAnalysis Term (years) 10 15 max. time frame for present value cash flowsDepreciation Term (years) 5 12 max. time frame for tax capture of depreciationDepreciation Method straight lineAnnual Tax Rates 34.0% re. net income after deducting expensesO&M Labor Rates (per hour) $ 30.00 fully loaded, applied to above labor multiplier

The NPV calcs compensate for difference in general inflation versus electricity price inflation.

Expenses

c -- as percent of gross revenue savings attributed to a system.

CALCULATION BASES AND INPUT VARIABLES

Plant Operations and Economic Factors

RETURN



2.2.12 10:22:1804/18/2023

Electrical GenerationPower Turbine Efficiency 75%

Generator Efficiency 95%Gross Plant Capacity 50 megawatts (MW)

Cooling Tower Specification15

Condenser Specification(direct-contact) 3

25

Produced Steam/Brine 15% steam quality, weight percent vapor

Vacuum Equipment EfficienciesSteam Jet Ejector 23%Turbocompressor 59.25% compressor = 79% expander 75%Biphase Eductor 10%

ADJUSTMENT FACTORS FOR CAPITAL COST ESTIMATES

Annual Escalation Factor 3% (re. date of source estimate)Bare-equipment Installation Factor

2.5 ejectors1.5 turbocompressors2.5 eductors1.5 reboiler system1.5 H2S treatment system

Power Law Exponential Factor 0.6 ejectorsfor Capital Cost Scaling 0.6 turbocompressors

based on differing capacities 0.6 eductors0.6 reboiler system0.6 H2S treatment system

SITE CONDITIONS

Site Elevation 4200 feetAtmospheric Pressure 640 mm. HgWet Bulb Temperature 60Dry Bulb Temperature 74Bases for calculating process equipment performance, as listed in Worksheets 3.1 and 3.2 -- these are offline calcs. used as input here.

oF , air/water approach temperature

oF , hotwell vapor/water approach temperatureoF , cooling water temperature rise

o F.o F.

These three factors are used to adapt equipment cost estimates from different times to current values; to estimate total installed costs from bare equipment costs; and to ratio costs for a quoted capacity to a higher or lower value for this study: [i.e. Log (capacity ratio) x 0.6 = log (price ratio) ]

multiplier to convert bare equipment costs to installed system costs.

RETURN



2.2.13 10:22:1804/18/2023

general inflation, e.g. wages, materials, equipment, etc.

AXG-9-29432-01document.xls Page 2.3.14 10:22:18

04/18/2023

auxiliarysteam

Production Fluidsturbine/generator set

flash pressure primary control valve separator

Spent BrineStage 1 &

main Stage 2condenser Ejectors

makeupwater

condensate &cooling water

blowdown cooling towerfeed pumps

COMMON : CONDENSERS AND VACUUM GAS REMOVAL

steam & gases

Power & Utilities = 50 MW grossGeothermal

Resource Production and

Gathering Systems

Vacuum & Heat

Rejection Systems

Produced Fluid Flash

Separator

Electrical Generation

Systems

System Boundary for Mass / Energy Balances for Noncondensable Gas Removal

brine / steam from wells and

gathering system

treatment and

reinjection

Figure 1 Base-Case Flowsheet

Removal of Noncondensable Gases from Geothermal Power PlantVacuum Transport of Gross Turbine Feed Stream through Condensers

Using Two-Stage Steam Jet Ejector Battery

cooling tower

condensertop right

evaporativelosses

inter/after condensers

COMMON: flash, turbine/generator, brine reinjection


04/18/2023

steam / gas flow path Note, utility power also covers emission control, and brine/condensate handling.

Figure 4 Energy and Mass Flow

For Analysis of Performance and Economics of Noncondensable Gas Removal From Geothermal Electric Generating Systems

steam & gases

Effective Net Product = X MW

Geothermal Resource

Production and Gathering Systems

Vacuum & Heat

Rejection Systems

Produced Fluid Flash

Separator

Electrical Generation

Systems

Utility Support Systems

spent brine


04/18/2023

Stage 1 &Stage 2Ejectors

gas abatement(e.g. for H2S)

COMMON : CONDENSERS AND VACUUM GAS REMOVAL

Vacuum & Heat

Rejection Systems

Emissions Control

Systems

Vent

otherutilities

cooling water from

tower

Figure 1 Base-Case Flowsheet

Removal of Noncondensable Gases from Geothermal Power PlantVacuum Transport of Gross Turbine Feed Stream through Condensers

Using Two-Stage Steam Jet Ejector Battery

inter/after condensers

Vent to Atmosphere


04/18/2023

produced fluids brine flow path

energy path steam / gas flow path

Figure 4 Energy and Mass Flow

For Analysis of Performance and Economics of Noncondensable Gas Removal From Geothermal Electric Generating Systems

Effective Net Product = X MW

Brine/Condensate Conditioning

Systems

Reinjection Systems

Vacuum & Heat

Rejection Systems

Emissions Control

Systems


04/18/2023

RETURN

RETURN


04/18/2023

RETURN


04/18/2023

FIGURE 5a -- CALCULATION LOGIC SCHEMES

OVERALL FLOWSHEET MASS & ENERGY BALANCES

ASSUME CALCULATE

Calculate vapor/liquid split and phase

properties

Calculate condenser conditions

Calculate turbine outlet conditions

Calculate gross steam, gas flow to meet power output duty

Calculate gross flows within condenser and at exit

Calculate condenser heat duties

Define turbine inlet conditions

Calculate vacuum compressor discharge

conditions

Calculate vacuum compressor power requirements, motive steam (as appropriate)

Calculate gross flows within intercondenser and at exit

Calculate intercondenser heat duties

Calculate intercondenser conditions

Assume ambient conditions for cooling tower COS

Assume gross turbine generator set power output (I.e. 50 MW)

Assume ratios for vacuum compressor stages

Assume gathering system net bulk feed conditions at generator

plant battery limits


04/18/2023

FIGURE 5b -- CALCULATION LOGIC SCHEMES

CONDENSER TEMPERATURE, PRESSURE, MASS BALANCE

ASSUME CALCULATE

not balancedbalanced

not balanced

Assume ambient temperature, pressure, humidity

Assume CW approach to Tw to get min. CW temp.

Assume CW temp. rise (delta-Tcw)

Assume approach between "hot" CW and condensing

turbine effluent

Assume percent steam condensed (L/V)

Assume total pressure (Pi)

Assume pH

Check heat duty re. condenser capacity

Calculate wet bulb temp., Tw

Calculate Tcwlow

Calculate Tcwhot

Calculate vapor temp. , T3, and steam partial

pressure, Ps3 in hotwell

Calculate gas partial pressure, Pgas

Calculate liquid compositions.

Check mole balance

Check ion balance


And etc. for next-stage vacuum compressors and related after-condensers


04/18/2023

balanced

not balancedbalancedGo to turbine

back-pressure calc.

Check heat duty re. condenser capacity


04/18/2023

FIGURE 5a -- CALCULATION LOGIC SCHEMES

OVERALL FLOWSHEET MASS & ENERGY BALANCES

Calculate condenser conditions

Calculate gross steam, gas flow to meet power output duty

Calculate gross flows within condenser and at exit

Calculate vacuum compressor power requirements, motive steam (as appropriate)


Calculate intercondenser conditions


04/18/2023

FIGURE 5b -- CALCULATION LOGIC SCHEMES

CONDENSER TEMPERATURE, PRESSURE, MASS BALANCE


And etc. for next-stage vacuum compressors and related after-condensers


04/18/2023

Sheet 3.1 Main Case Summaries


Page 3.1.26 10:22:1804/18/2023

HIGH TEMPERATURE , HIGH GAS

Summary of Case Data

Process Data Case Description

Deg F

Geothermal Fluid Delivered lbs/hr

Bulk Plant Feed Noncondensable Gases ppmw, incoming fluid wt basis

Flashed Steam Composition ppmv to turbine inlet (mole basis)

plant inlet pressure Psia

Deg F

Total Flash Pressure Psia

Steam delivered to Turbine lb/hr (after deducts listed)

NCG Through Turbine lb/hr

in HG

Temperature Deg. F

Generator Output kW

Condenser & Vacuum Systems Motive Gas Requirements

Parasitic losses Eductor

Parasitic electrical load(CW pumps, CT fans, Eductor brine repressure pumps) kW

Net kW Generator Output after deducting gas removal (only) parasitic losses

HIGH TEMPERATURE, MID GAS



Deg F





Deg F


Steam delivered to Turbine lb/hr


in HG

Temperature Deg. F

Plant Flash Inlet Temperature

Process Units: Flash Temperature

Turbine Exhaust Pressure




RETURN

A B

1

2

3

4

5

6

7

8

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Page 3.1.27 10:22:1804/18/2023

Generator Output kW





A B

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41

42



Page 3.1.28 10:22:1804/18/2023

HIGH TEMPERATURE, LOW GAS



Deg F





Deg F




in HG

Temperature Deg. F

Generator Output kW





LOW TEMPERATURE, LOW GAS



Deg F





Deg F




in HG

Temperature Deg. F

Generator Output kW







A B

43

44

45

46

47

48

49

50

51

52

53

54

55

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58

59

60

61

62

63

64

65

66

67

68

69

70

71

72

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74

75

76

77

78

79



Page 3.1.29 10:22:1804/18/2023





A B

80

81

82

83

84



Page 3.1.30 10:22:1804/18/2023

LOW TEMPERATURE, MID GAS



Deg F





Deg F




in HG

Temperature Deg. F

Generator Output kW





LOW TEMPERATURE, HIGH GAS



Deg F





Deg F




in HG

Temperature Deg. F

Generator Output kW







A B

85

86

87

88

89

90

91

92

93

94

95

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97

98

99

100

101

102

103

104

105

106

107

108

109

110

111

112

113

114

115

116

117

118

119

120

121



Page 3.1.31 10:22:1804/18/2023





A B

122

123

124

125

126



Page 3.1.32 10:22:1804/18/2023

LOW TEMPERATURE, VERY HIGH GAS



Deg F





Deg F




in HG

Temperature Deg. F

Generator Output kW





HIGH TEMPERATURE, VERY HIGH GAS



Deg F





Deg F




in HG

Temperature Deg. F

Generator Output kW







A B

127

128

129

130

131

132

133

134

135

136

137

138

139

140

141

142

143

144

145

146

147

148

149

150

151

152

153

154

155

156

157

158

159

160

161

162

163



Page 3.1.33 10:22:1804/18/2023





A B

164

165

166

167

168



Page 3.1.34 10:22:1804/18/2023

MAIN CASE GROUP 1HIGH TEMPERATURE, HIGH GAS, 60 DEG WET BULB

550 550 550

2,290,750 2,290,750 2,290,750

48,772 48,772 48,772

49,917 49,917 49,917

1,176.82 1,176.82 1,176.82

333.81 333.81 333.81

114.35 114.35 114.35

858,240 707,107 741,446

110,224 90,814 95,224

3.42 3.43 3.42

117.62 117.62 117.62

50,003 41,198 43,198lb/hr steam & gas 0 170,543 116,794

Biphase Eductor lb-brine from flash tank

Performance NCG load met by flashing brine

Parasitic electrical load(CW pumps, CT fans, Eductor brine repressure pumps) kW 3,023 2,726

Net kW Generator Output after deducting gas removal (only) parasitic losses 50,003 38,175 40,473

MAIN CASE GROUP 2HIGH TEMPERATURE, MID GAS, 60 DEG WET BULB

550 550 550

2,287,887 2,287,887 2,287,887

28,967 28,967 28,967

29,934 29,934 29,934

1,124.01 1,124.01 1,124.01

334.21 334.21 334.21

112.56 112.56 112.56

866,559 774,844 797,486

65,365 58,447 60,155

3.42 3.42 3.42

118.41 118.41 118.41

Base Case -- Power Steam Load

Estimate

With 2 stage SJAE with Interstage Direct Contact Condensers

Turbo Compressor

(3-stage)


Estimate


Turbo Compressor

(3-stage)

See reboiler summary data at far right.


RETURN

C D E F

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

C3

Martin Vorum: this worksheet contains process data calculated offline from this spreadhseet. These data are used in the subsequent worksheets of this spreadsheet to derive power system performance and economic comparisons. The data in this worksheet profiles the performance of a "Base Case" and 5 alternative gas removal cases. The Base Case is calculated to determine how much flashed steam at the stated conditions (T, P, gas load) is needed to generate 50 MW electrical power. This reflects only power turbine steam consumption, and the gross plant feed mass flows remain constant at this level in all comparative cases. The Base Case, with deductions for running a 2-Stage steam jet ejector battery, is the reference case for all performance and economic analyses. The five cases list the steam delivered to the power turbine and the levels of steam and electrical power consumption for the parasitic utility function of removing noncondensable gases. This includes variations in the energy to pump cooling water, for example. Therefore, the gross turbine power output vaires from case to case.



Page 3.1.35 10:22:1804/18/2023

49,999 44,707 46,014lb/hr steam & gas 0 98,633 69,073





C D E F

37

38

39

40

41

42



Page 3.1.36 10:22:1804/18/2023

MAIN CASE GROUP 3HIGH TEMPERATURE, LOW GAS, 60 DEG WET BULB

550 550 550

2,283,558 2,283,558 2,283,558

9,567 9,567 9,567

9,980 9,980 9,980

1,071.58 1,071.58 1,071.58

334.51 334.51 334.51

110.72 110.72 110.72

874,234 846,255 852,964

21,541 20,852 21,017

3.40 3.40 3.40

119.02 119.02 119.02

49,998 48,398 48,782lb/hr steam & gas 0 28,669 21,271





MAIN CASE GROUP 4LOW TEMPERATURE, LOW GAS, 60 DEG WET BULB

350 350 350

5,418,282 5,418,282 5,418,282

6,486 6,486 6,486

10,034 10,034 10,034

136.97 136.97 136.97

234.51 234.51 234.51

22.84 22.84 22.84

1,410,706 1,295,622 1,355,292

34,952 32,100 33,579

3.40 3.40 3.40

119.02 119.02 119.02

50,000 45,921 48,036


Estimate


Turbo Compressor

(3-stage)


Estimate


Turbo Compressor

(3-stage)



C D E F

43

44

45

46

47

48

49

50

51

52

53

54

55

56

57

58

59

60

61

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63

64

65

66

67

68

69

70

71

72

73

74

75

76

77

78

79



Page 3.1.37 10:22:1804/18/2023

lb/hr steam & gas 0 117,936 55,415





C D E F

80

81

82

83

84



Page 3.1.38 10:22:1804/18/2023

MAIN CASE GROUP 5

350 350 350

5,395,099 5,395,099 5,395,099

19,748 19,748 19,748

30,065 30,065 30,065

141.59 141.59 141.59

234.23 234.23 234.23

23.19 23.19 23.19

1,398,657 1,036,288 1,218,217

105,976 78,519 92,304

3.42 3.42 3.42

118.46 118.46 118.46

49,998 37,045 43,548lb/hr steam & gas 0 389,825 180,440





MAIN CASE GROUP 6LOW TEMPERATURE, HIGH GAS, 60 DEG WET BULB

350 350 350

5,364,701 5,364,701 5,364,701

33,425 33,425 33,425

50,053 50,053 50,053146.16 146.16 146.16

233.85 233.85 233.85

23.52 23.52 23.52

1,384,975 835,315 1,080,100

178,383 107,587 139,115

3.42 3.43 3.42

117.71 117.71 117.71

49,997 30,155 38,991


Estimate


Turbo Compressor

(3-stage)


Estimate


Turbo Compressor

(3-stage)



C D E F

85

86

87

88

89

90

91

92

93

94

95

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98

99

100

101

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103

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Page 3.1.39 10:22:1804/18/2023

lb/hr steam & gas 0 620,455 304,875





C D E F

122

123

124

125

126



Page 3.1.40 10:22:1804/18/2023

MAIN CASE GROUP 7LOW TEMPERATURE, VERY HIGH GAS, 60 DEG WET BULB

350.00 350.00 350.00

5,200,748.50 5,200,748.50 5,200,748.50

108,542.25 108,542.25 108,542.25

149,179.67 149,179.67 149,179.67

170.17 170.17 170.17

231.78 231.78 231.78

25.26 25.26 25.26

1,310,988.74 280,813.79 417,116.45

561,889.48 120,356.73 178,776.02

3.43 3.43 3.43

113.55 113.55 113.55

49,938.61 10,696.85 15,888.94 lb/hr steam & gas - 1,480,017.55 893,872.29

Biphase Eductor lb-brine from fla

Performance NCG load met by

Parasitic electrical load(CW pumps, CT fans, Eductor brine repressure pumps) kW 5,193.86 4,650.57

Net kW Generator Output after deducting gas removal (only) parasitic losses 49,938.61 5,502.99 11,238.36

MAIN CASE GROUP 8HIGH TEMPERATURE, VERY HIGH GAS, 60 DEG WET BULB

550 550 550

2,297,151 2,297,151 2,297,151

99,665 99,665 99,665

99,557 99,557 99,557

1,316 1,316 1,316

333 333 333

119 119 119

836,338 561,822 603,645

226,036 151,843 163,146

3.43 3.43 3.43

115 115 115

49,993 33,583 36,083


Estimate


Turbo Compressor

(3-stage)


Estimate


Turbo Compressor

(3-stage)



C D E F

127

128

129

130

131

132

133

134

135

136

137

138

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140

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152

153

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Page 3.1.41 10:22:1804/18/2023

lb/hr steam & gas 0 348,709 232,693





C D E F

164

165

166

167

168



Page 3.1.42 10:22:1804/18/2023

CASE 5-aHIGH TEMPERATURE, HIGH GAS, 60 DEG WET BULB

550 550 550

2,290,750 2,290,750 2,290,750

48,772 48,772 48,772

49,917 49,917 49,917

1,176.82 1,176.82 1,176.82

333.81 333.81 333.81

114.35 114.35 114.35

748,118 723,874 732,403

2,198 92,967 94062.59

3.27 3.42 3.42

117.90 117.62 117.62

39,697 42,175 42,6722103 134,366 141,998

lb/hr 1,320,785

lb/hr 21,418

2,335 3,116 2,755

37,362 39,059 39,916

CASE 5-CHIGH TEMPERATURE, MID GAS, 60 DEG WET BULB

550 550 550

2,287,887 2,287,887 2,287,887

28,967 28,967 28,967

29,934 29,934 29,934

1,124.01 1,124.01 1,124.01

334.21 334.21 334.21

112.56 112.56 112.56

801,262 803,735 791,147

1,305 60,626 59676

3.26 3.42 3.42

117.92 118.41 118.41

Reboiler with 2-stage SJAE

Two Phase Eductor with supplemental SJAE, as needed

3-stage Hybrid System : 2 x SJAE plus 1 x turbocomp.




RETURN

G H I

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36



Page 3.1.43 10:22:1804/18/2023

42,335 46,374 45,6481239 62,824 81,100

lb/hr 1,355,055

lb/hr 23,399

2,513 3,394 2,764

39,821 42,980 42,884

G H I

37

38

39

40

41

42



Page 3.1.44 10:22:1804/18/2023

CASE 5-DHIGH TEMPERATURE, LOW GAS, 60 DEG WET BULB

550 550 550

2,283,558 2,283,558 2,283,558

9,567 9,567 9,567

9,980 9,980 9,980

1,071.58 1,071.58 1,071.58

334.51 334.51 334.51

110.72 110.72 110.72

852,714 874,234 851,642

431 21,541 20985

3.26 3.40 3.40

117.94 119.02 119.02

44,849 49,998 48,706410 0 23,149

lb/hr 1,215,153

lb/hr 21,541

2,686 3,515 2,765

42,163 46,483 45,942

CASE 6 repeat LOW TEMPERATURE, LOW GAS, 60 DEG WET BULB

350 350 350

5,418,282 5,418,282 5,418,282

6,486 6,486 6,486

10,034 10,034 10,034

136.97 136.97 136.97

234.51 234.51 234.51

22.84 22.84 22.84

1,374,334 1,314,122 1,340,848

698 32,559 33,221

3.26 3.40 3.40

117.94 119.02 119.02

41,755 46,577 47,524







G H I

43

44

45

46

47

48

49

50

51

52

53

54

55

56

57

58

59

60

61

62

63

64

65

66

67

68

69

70

71

72

73

74

75

76

77

78

79



Page 3.1.45 10:22:1804/18/2023

2,119 96,584 71,589

lb/hr 3,972,435

lb/hr 6,270

4,699 5,258 4,831

37,056 41,318 42,693

G H I

80

81

82

83

84



Page 3.1.46 10:22:1804/18/2023

CASE 6 BLOW TEMPERATURE, MID GAS, 60 DEG WET BULB

350 350 350

5,395,099 5,395,099 5,395,099

19,748 19,748 19,748

30,065 30,065 30,065

141.59 141.59 141.59

234.23 234.23 234.23

23.19 23.19 23.19

1,288,512 1,035,273 1,165,938

2,109 78,442 88342.97

3.27 3.42 3.42

117.93 118.46 118.46

39,437 37,008 41,679 6,289 363,385 250,352

lb/hr 3,889,902

lb/hr 5,249

4,406 4,209 4,835

35,031 32,800 36,845

CASE 6 CLOW TEMPERATURE, HIGH GAS, 60 DEG WET BULB

350 350 350

5,364,701 5,364,701 5,364,701

33,425 33,425 33,425

50,053 50,053 50,053146.16 146.16 146.16

233.85 233.85 233.85

23.52 23.52 23.52

1,199,735 808,703 996,005

3,537 104,160 128284

3.27 3.42 3.42

117.91 117.71 117.71

36,970 29,194 35,955







G H I

85

86

87

88

89

90

91

92

93

94

95

96

97

98

99

100

101

102

103

104

105

106

107

108

109

110

111

112

113

114

115

116

117

118

119

120

121



Page 3.1.47 10:22:1804/18/2023

10,425 576,272 439,068

lb/hr 3,800,413

lb/hr 4,234

4,103 3,334 4,835

32,867 25,860 31,121

G H I

122

123

124

125

126



Page 3.1.48 10:22:1804/18/2023

CASE 10d re-runLOW TEMPERATURE, VERY HIGH GAS, 60 DEG WET BULB

350.00 350.00 350

5,200,748.50 5,200,748.50 5,200,749

108,542.25 108,542.25 108,542

149,179.67 149,179.67 149,180

170.17 170.17 170.17

231.78 231.78 231.78

25.26 25.26 25.26

740,112.23 211,632.91 351,789

10,938.87 90,579.38 151605.27

3.35 3.43 3.43

118.68 113.55 113.55

23,395.22 8,061.59 13,406 20,224.82 1,099,650.83 1,372,214

lb/hr 3,325,258.83

lb/hr 1,154.51

2,477.01 926.89 4,686

20,918.21 7,134.70 8,720

CASE 10cHIGH TEMPERATURE, VERY HIGH GAS, 60 DEG WET BULB

550 550 550

2,297,151 2,297,151 2,297,151

99,665 99,665 99,665

99,557 99,557 99,557

1,316 1,316 1,316

333 333 333

119 119 119

609,385 539,248 593,384

4,481 145,742 160373.16

3.31 3.43 3.43

118 115 115

32,600 32,234 35,470



3-stage Hybrid System : 2 x SJAE plus 1 x turbocomp. REPLACEMENT MARCH 30




G H I

127

128

129

130

131

132

133

134

135

136

137

138

139

140

141

142

143

144

145

146

147

148

149

150

151

152

153

154

155

156

157

158

159

160

161

162

163



Page 3.1.49 10:22:1804/18/2023

5438 297,090 308,617

lb/hr 1,231,868

lb/hr 16,376

1,871 2,386 2,730

30,730 29,848 32,740

G H I

164

165

166

167

168



Page 3.1.50 10:22:1804/18/2023

HIGH TEMPERATURE, HIGH GAS MAIN CASE GROUP 1

Summary of Reboiler Rates

1 Clean steam, gas flow at net 50 MW basis : 750,316

(turbine feed steam)

2 Vent stream at 50 MW basis : 215,433

(reboiler waste -- vent to atm., treat or reinject)

3 Sum of above is flashed steam feed to reboiler : 965,749

4 Vacuum drive gas (flashed steam) at 50 MW basis : 2,103

5 Brine/steam/gas plant feed at 50 MW basis : 2,289,303

6 Cooling water system motor loads at 50 MW basis : 2,333

FYI, general flow increase ratio versus base case is : 0.999

(note, this also includes slight mass/energy

balance closure discrepancies)

HIGH TEMPERATURE, MID GAS MAIN CASE GROUP 2









RETURN

J K L M N O P

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36



Page 3.1.51 10:22:1804/18/2023





J K L M N O P

37

38

39

40

41

42



Page 3.1.52 10:22:1804/18/2023

HIGH TEMPERATURE, LOW GAS MAIN CASE GROUP 3







4 Vacuum drive gas (flashed steam) at 50 MW basis : 410






LOW TEMPERATURE, LOW GAS MAIN CASE GROUP 4


1 Clean steam, gas flow at net 50 MW basis : 1,375,032




3 Sum of above is flashed steam feed to reboiler : 1,443,433



J K L M N O P

43

44

45

46

47

48

49

50

51

52

53

54

55

56

57

58

59

60

61

62

63

64

65

66

67

68

69

70

71

72

73

74

75

76

77

78

79



Page 3.1.53 10:22:1804/18/2023





J K L M N O P

80

81

82

83

84



Page 3.1.54 10:22:1804/18/2023

LOW TEMPERATURE, MID GAS MAIN CASE GROUP 5













LOW TEMPERATURE, HIGH GAS MAIN CASE GROUP 6









J K L M N O P

85

86

87

88

89

90

91

92

93

94

95

96

97

98

99

100

101

102

103

104

105

106

107

108

109

110

111

112

113

114

115

116

117

118

119

120

121



Page 3.1.55 10:22:1804/18/2023





J K L M N O P

122

123

124

125

126



Page 3.1.56 10:22:1804/18/2023


` Summary of Reboiler Rates



2 Vent stream at 50 MW basis : 1,072,009


















J K L M N O P

127

128

129

130

131

132

133

134

135

136

137

138

139

140

141

142

143

144

145

146

147

148

149

150

151

152

153

154

155

156

157

158

159

160

161

162

163



Page 3.1.57 10:22:1804/18/2023





J K L M N O P

164

165

166

167

168



Page 3.1.58 10:22:1804/18/2023


lb / hr

lb / hr

lb / hr

lb / hr

lb / hr

kW


lb / hr

lb / hr

lb / hr

lb / hr

lb / hr

RETURN

Q R

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36



Page 3.1.59 10:22:1804/18/2023

kW

Q R

37

38

39

40

41

42



Page 3.1.60 10:22:1804/18/2023


lb / hr

lb / hr

lb / hr

lb / hr

lb / hr

kW


lb / hr

lb / hr

lb / hr

lb / hr

lb / hr

Q R

43

44

45

46

47

48

49

50

51

52

53

54

55

56

57

58

59

60

61

62

63

64

65

66

67

68

69

70

71

72

73

74

75

76

77

78

79



Page 3.1.61 10:22:1804/18/2023

kW

Q R

80

81

82

83

84



Page 3.1.62 10:22:1804/18/2023


lb / hr

lb / hr

lb / hr

lb / hr

lb / hr

kW


lb / hr

lb / hr

lb / hr

lb / hr

lb / hr

Q R

85

86

87

88

89

90

91

92

93

94

95

96

97

98

99

100

101

102

103

104

105

106

107

108

109

110

111

112

113

114

115

116

117

118

119

120

121



Page 3.1.63 10:22:1804/18/2023

kW

Q R

122

123

124

125

126



Page 3.1.64 10:22:1804/18/2023


lb / hr

lb / hr

lb / hr

lb / hr

lb / hr

kW


lb / hr

lb / hr

lb / hr

lb / hr

lb / hr

Q R

127

128

129

130

131

132

133

134

135

136

137

138

139

140

141

142

143

144

145

146

147

148

149

150

151

152

153

154

155

156

157

158

159

160

161

162

163



Page 3.1.65 10:22:1804/18/2023

kW

Q R

164

165

166

167

168

Sheet 3.2 Sensitivity Case Summaries


Page 3.2.66 10:22:1804/18/2023

SENSITIVITY GROUP S - 1 -- HIGH TEMPERATURE , HIGH GAS

LOW EFFICIENCY EJECTORS

Summary of Case Data CASE 3 Repeat


Deg F




Plant inlet pressure Psia

Deg F




in HG

Temperature Deg. F

Generator Output kW

Condenser & Vacuum Systems Motive Gas Requirements Lb/hr Steam and Gas



Net kw after Parasitic losses

SENSITIVITY GROUP S - 2 -- LOW TEMPERATURE, LOW GAS

LOW EFFICIENCY EJECTORS


Process Data Case Description Case 8 repeat

Deg F





Deg F




in HG

Temperature Deg. F

Generator Output kW 2.931E-04













C3

Martin Vorum: this worksheet lists offline calculation results for several test cases to examine variations of key parameters from the Main Case data sets. These parameters were chosen to show, for example, the sensitivities of power plant performance to humidity and efficiencies of ejectors or eductors. The results and further explanation are given in worksheet 5 (SensiComp).



Page 3.2.67 10:22:1804/18/2023

SENSITIVITY GROUP S - 3 -- HIGH TEMPERATURE, MID GAS 80 DEG. WET BULB

HIGH WET BULB COMPARISON


Process Data Case Description CASE 5 b

Deg F





Deg F




in HG

Temperature Deg. F






SENSITIVITY GROUP S - 4 -- LOW TEMPERATURE, LOW GAS 80 DEG. WET BULB

HIGH WET BULB COMPARISON



Deg F





Deg F




in HG

Temperature Deg. F
















Page 3.2.68 10:22:1804/18/2023

SENSITIVITY GROUP S - 5 -- HIGH TEMPERATURE, HIGH GAS 60 DEG. WET BULB LAST STAGE 23 %



Deg F





Deg F




in HG

Temperature Deg. F


Condenser & Vacuum Systems Motive Gas Requirements lb/hr




SENSITIVITY GROUP S - 6 -- LOW TEMPERATURE, LOW GAS 60 DEG. WET BULB LAST STAGE 23 %

3-STAGE STEAM JET (INSTEAD OF 2-STAGE)



Deg F





Deg F




in HG

Temperature Deg. F






3-STAGE STEAM JET (INSTEAD OF 2-STAGE)











Page 3.2.69 10:22:1804/18/2023

CASE 3 - R Sensitivity 2

Base Case Reboiler

550 550 550 550 550

2,290,750 2,290,750 2,290,750 2,290,750 2,290,750

48,772 48,772 48,772 48,772 48,772

49,917 49,917 49,917 49,917 49,917

1177 1177 1177 1177 1177

334 334 334 334 334

114 114 114 114 114

858,240 639,792 741,446 748,118 661,680

110,224 82,168 95,224 2,198 84,979

3.42 3.43 3.42 3.27 3.42

118 118 118 118 118

50,003 37,276 43,198 39,697 38,551

0 246,503 116,794 2103 196,560

Biphase eductor lb-brine from flash tank lb/hr 1,320,785

Performance ncg load met by flashing brine lb/hr 19,459

3,051 2,726 2335 2,814

50,003 34,225 40,473 37,362 35,737

SENSITIVITY GROUP S - 2 -- LOW TEMPERATURE, LOW GAS CASE 8 R

Base Case Reboiler

350 350 350 350 350

5,418,029 5,418,029 5,418,029 5,418,029 5,418,029

6,497 6,497 6,497 6,497 6,497

10,052 10,052 10,052 10,052 10,052

137 137 137 137 137

235 235 235 235 235

23 23 23 23 23

1,410,636 1,243,056 1,355,115 1,374,201 1,268,218

35,012 30,852 33,634 699 31,477

3.40 3.40 3.40 3.26 3.40

119 119 119 118 119

49,998 44,058 48,030 41,750 44,950

0 171,739 55,520 2123 142,418



5,332 4,790 4,698 5,071

49,998 38,726 43,240 37,052 39,879

With 2 stage SJAE with Interstage

Direct Contact Condensers

Turbo Compressor

Two Phase Eductor



Turbo Compressor

Two Phase Eductor



Page 3.2.70 10:22:1804/18/2023

SENSITIVITY GROUP S - 3 -- HIGH TEMPERATURE, MID GAS 80 DEG. WET BULB CASE 5 B

Base Case Reboiler

550 550 550 550 550

2,504,984 2,504,984 2,504,984 2,504,984 2,504,984

28,940 28,940 28,940 28,940 28,940

30,437 30,437 30,437 30,437 30,437

1124 1124 1124 1124 1124

344 344 344 344 344

128 128 128 128 128

929,413 844,996 860,720 858,426 879,194

71,320 64,842 66,049 1,425 67,466

5.71 5.72 5.71 5.41 6

137 137 137 137 137

50,026 45,482 46,329 42,062 47,323

0 90,895 68,693 1093 50,220



3246 2922 2696 3799

50,026 42,236 43,407 39,367 43,524

SENSITIVITY GROUP S - 4 -- LOW TEMPERATURE, LOW GAS 80 DEG. WET BULB CASE 9 R

Base Case Reboiler

350 350 350 350 350

6,250,550 6,250,550 6,250,550 6,250,550 6,250,550

6,357 6,357 6,357 6,357 6,357

10,148 10,148 10,148 10,148 10,148

137 137 137 137 137

244 244 244 244 244

27 27 27 27 27

1,575,301 1,479,062 1,517,857 1,535,015 1,506,476

39,477 37,065 38,037 789 37,752

5.66 5.66 5.66 5.41 5.66

138 138 138 137 138

50,000 46,945 48,176 41,045 47,815

0 98,650 57,444 1599 68,825



5950 5349 5251 6259

50,000 40,996 42,827 35,794 41,557


Turbo Compressor

Two Phase Eductor



Turbo Compressor

Two Phase Eductor



Page 3.2.71 10:22:1804/18/2023

SENSITIVITY GROUP S - 5 -- HIGH TEMPERATURE, HIGH GAS 60 DEG. WET BULB LAST STAGE 23 % CASE 1 R Sensitivity 1

Base Case Reboiler

550 550 550 550 550

2,288,428 2,288,428 2,288,428 2,288,428 2,288,428

48,134 48,134 48,134 48,134 48,134

49,281 49,281 49,281 49,281 49,281

1175 1175 1175 1175 1175

334 334 334 334 334

114 114 114 114 114

857,673 709,467 742,503 749,107 726,536

108,675 89,896 94,082 2,168 92,059

3.42 3.43 3.42 3.27 3.42

118 118 118 118 118

49,954 41,322 43,246 39,736 42,316

0 166,985 115,170 2,064 131,136

1,320,605

21,462

3,016 2,722 2,338 3,010

49,954 38,306 40,524 37,397 39,307

SENSITIVITY GROUP S - 6 -- LOW TEMPERATURE, LOW GAS 60 DEG. WET BULB LAST STAGE 23 % CASE 7 R

LOW TEMPERATURE, LOW GAS, 60 DEG WET BULB 23%23%23%

Base Case Reboiler

350 350 350 350 350

5,418,030 5,418,030 5,418,030 5,418,030 5,418,030

6,497 6,497 6,497 6,497 6,497

10,051 10,051 10,051 10,051 10,051

137 137 137 137 137

235 235 235 235 235

23 23 23 23 23

1,410,636 1,329,437 1,355,118 1,374,203 1,342,419

35,011 32,995 33,633 699 33,318

3.40 3.40 3.40 3.26 3.40

119 119 119 118 119

49,998 47,120 48,030 41,751 47,580

0 83,214 55,518 2123 68,217

3,972,194

6,269

5309 4790 4698 5348

49,998 41,810 43,241 37,052 42,232



Turbo Compressor

Two Phase Eductor



Turbo Compressor

Two Phase Eductor



Page 3.2.72 10:22:1804/18/2023

CASE 3 - R Sensitivity 2

HIGH TEMPERATURE, HIGH GAS, 60 DEG WET BULB 15% SJAE EFF

550 Summary of Reboiler Rates

2,290,750

48,772 1 Clean steam, gas flow at net 50 MW basis :

49,917 (turbine feed steam)

1177 2 Vent stream at 50 MW basis :

334 (reboiler waste -- vent to atm., treat or reinject)

114 3 Sum of above is flashed steam feed to reboiler :

686,007

88,104 4 Vacuum drive gas (flashed steam) at 50 MW basis :

3.42

118 5 Brine/steam/gas plant feed at 50 MW basis :

39,968

194,353 6 Cooling water system motor loads at 50 MW basis :

FYI, general flow increase ratio versus base case is :


2,768 balance closure discrepancies)

37,200

CASE 8 R

LOW TEMPERATURE, LOW GAS, 60 DEG WET BULB .15 SJAE EFF


5,418,029






1,311,285


3.40


46,476



4,837

41,640

With 3 Stage Hybrid System




Page 3.2.73 10:22:1804/18/2023

CASE 5 B

HIGH TEMPERATURE, MID GAS, 80 DEG F. WET BULB


2,504,984






856,364


5.71


46,094



2967

43,128

CASE 9 R

LOW TEMPERATURE, LOW GAS,80 DEG WET BULB 23%23%79%


6,250,550






1,507,188


5.66


47,838



5405

42,433





Page 3.2.74 10:22:1804/18/2023

CASE 1 R Sensitivity 1

HIGH TEMPERATURE, HIGH GAS, 60 DEG WET BULB 23%23%23%


2,288,428






732,614


3.42


42,670



2,756

39,914

CASE 7 R




5,418,030






1,340,669


3.40


47,518



4830

42,688





Page 3.2.75 10:22:1804/18/2023

HIGH TEMPERATURE, HIGH GAS, 60 DEG WET BULB 15% SJAE EFF


750,316 lb / hr

215,433 lb / hr

965,749 lb / hr

2,103 lb / hr

2,289,303 lb / hr

2,333 kW

0.999

LOW TEMPERATURE, LOW GAS, 60 DEG WET BULB .15 SJAE EFF


1,374,901 lb / hr

68,517 lb / hr

1,443,418 lb / hr

2,123 lb / hr

5,417,628 lb / hr

4,698 kW

1.000

RETURN



Page 3.2.76 10:22:1804/18/2023

HIGH TEMPERATURE, MID GAS, 80 DEG F. WET BULB


859,851 lb / hr

139,609 lb / hr

999,460 lb / hr

1,093 lb / hr

2,504,534 lb / hr

2,695 kW

1.000

LOW TEMPERATURE, LOW GAS,80 DEG WET BULB 23%23%79%


1,535,803 lb / hr

77,294 lb / hr

1,613,097 lb / hr

1,599 lb / hr

6,250,236 lb / hr

5,251 kW

1.000

RETURN



Page 3.2.77 10:22:1804/18/2023

HIGH TEMPERATURE, HIGH GAS, 60 DEG WET BULB 23%23%23%


751,275 lb / hr

212,418 lb / hr

963,692 lb / hr

2,064 lb / hr

2,287,028 lb / hr

2,337 kW

0.999



1,374,902 lb / hr

68,515 lb / hr

1,443,417 lb / hr

2,123 lb / hr

5,417,630 lb / hr

4,698 kW

1.000

RETURN


04/18/2023

Plot Data -- Engineering and Economic Figures of Merit versus Noncondensable Gas Levels

Case Group Descriptions Case Discriminators X AXIS Y AXISPlant Feed Temperatures Noncondensable Technical Figure of Merit

Gas Levels inPower Turbine

Feed Steam

Flash Flash Outlet part per millionInlet to Turbine by volume

ppmv

2-StageSteam Jet

SystemRatios of Technology Productivities

High temperature, Very high gas 550 334 99,600 1.00High temperature, High gas 49,900 1.00High temperature, Mid gas 29,900 1.00High temperature, Low gas 10,000 1.00

Low temperature, Low gas 350 234 10,000 1.00Low temperature, Mid gas 30,100 1.00Low temperature, High gas 50,100 1.00Low temperature, Very high gas 149,200 1.00

oF oF

Ratio of net plant power output for each gas removal option, divided by corresponding net power from a base case system employing 2-stage steam jet ejectors for gas removal. Net power derived by deducting power duty for gas removal. All other in-plant utilities assumed equal and outside of this balance.

Values less than 1 indicate technology consumes more power than 2-stage ejector system for gas removal.

Values greater than 1 indicate alternative technology consumes proportionally less power than 2-stage ejector system.


04/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,0000.00

0.40

0.80

1.20

1.60

2.00

2.40

2.80

3.20

3.60

4.00

4.40

FIGURE 70LOW TEMPERATURE CASES -- TECHNICAL FIGURE OF MERIT

3-Stage TurboLinear (3-Stage Turbo)ReboilerLinear (Reboiler)Biphase EductorLinear (Biphase Eductor)Hybrid -- Ejector & TurboLinear (Hybrid -- Ejector & Turbo)

NCG in Flashed Steam (ppmv)

Net

Pla

nt

Po

wer

Pro

du

ctiv

ity

Ver

sus

a 2-

Sta

ge

Eje

cto

r S

yste

m

Base Case reference at 1.00


04/18/2023

10,000 30,100 50,100 149,2000

100

200

300

400

500

600

FIGURE 80LOW TEMPERATURE CASES -- ECONOMIC FIGURE OF MERIT

3-Stage Turbo

Reboiler

Biphase Eductor

Hybrid -- Ejector & Turbo


Sim

ple

Payb

ack P

eri

od

fo

r R

etr

ofi

t G

as R

em

oval In

sta

llati

on

s

2-stage ejector system is basis for comparison for retrofit gas removal system options. Therefore, an ejector system has no payback period.

0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15

1.20

1.25

FIGURE 90HIGH TEMPERATURE CASES -- TECHNICAL FIGURE OF MERIT

2-Stage Ejectors 3-Stage Turbo Reboiler Biphase Eductor



Ne

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04/18/2023

99,600 49,900 29,900 10,000-10

-5

0

5

10

15

20

25

30

35

40

FIGURE 100HIGH TEMPERATURE CASES -- ECONOMIC FIGURE OF MERIT

3-Stage Turbo Reboiler Biphase Eductor Hybrid -- Ejector & Turbo


Sim

ple

Payb

ack

Perio

d fo

r R

etro

fit G

as R

emov

al In

stal

latio

ns

A 2-stage ejector system is the basis for comparison for retrofit gas removal sys-tem options. Therefore, an ejector sys-tem has no payback period.

Negative payback periods indicate the alter-native gas removal technology actually loses money compared to a steam jet ejector sys-tem -- payback is unattainable.

0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15

1.20

1.25





Ne

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Pro

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04/18/2023

99,600 49,900 29,900 10,000-10

-5

0

5

10

15

20

25

30

35

40




Sim

ple

Payb

ack

Perio

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etro

fit G

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latio

ns




04/18/2023


Y AXIS Y AXISTechnical Figure of Merit Technical Figure of Merit

3-Stage Reboiler Biphase Hybrid -- 2-Stage 3-Stage Reboiler BiphaseTurbocomp. System Eductor 3rd Stage Steam Jet Turbocomp. System Eductor

System System Turbocomp. System System SystemRatios of Technology Productivities Simple Payback Periods (years)

Figure 90 Figure 1001.09 1.01 0.98 1.07 N/A 30.51 86.48 -6.301.06 1.01 1.02 1.05 N/A 8.4 -100.9 13.51.04 1.01 1.03 1.03 N/A 5.4 -38.7 7.61.01 1.00 1.02 1.01 N/A 11.4 -23.3 7.7

Figure 70 Figure 801.07 1.07 1.02 1.05 N/A 2.6 15.3 539.11.22 1.26 1.03 1.16 N/A 2.3 3.3 32.51.38 1.48 1.04 1.25 N/A 3.7 2.1 33.32.04 4.28 1.29 1.59 N/A 107.3 1.0 6.8



Values greater than 1 indicate alternative technology consumes proportionally less power than 2-stage ejector system.

Ratio of capital costs of gas removal alternatives to their net savings as the value of avoided gas removal energy. Basis of energy savings is the gas removal duty for the 2-stage steam jet ejector system. This yields a simple payback period value as years to recover capital costs for each gas removal alternative.

Negative values indicate alternative gas removal system costs more to operate than a 2-stage ejector system -- payback will not happen based on energy savings.

RETURN


04/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,0000.00

0.40

0.80

1.20

1.60

2.00

2.40

2.80

3.20

3.60

4.00

4.40




Net

Pla

nt

Po

wer

Pro

du

ctiv

ity

Ver

sus

a 2-

Sta

ge

Eje

cto

r S

yste

m



04/18/2023

10,000 30,100 50,100 149,2000

100

200

300

400

500

600


3-Stage Turbo

Reboiler

Biphase Eductor



Sim

ple

Payb

ack P

eri

od

fo

r R

etr

ofi

t G

as R

em

oval In

sta

llati

on

s


0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15

1.20

1.25





Ne

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lan

t P

ow

er

Pro

du

cti

vit

y

Ve

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s a

2-S

tag

e E

jec

tor

Sy

ste

m


04/18/2023

99,600 49,900 29,900 10,000-10

-5

0

5

10

15

20

25

30

35

40




Sim

ple

Payb

ack

Perio

d fo

r R

etro

fit G

as R

emov

al In

stal

latio

ns



0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15

1.20

1.25





Ne

t P

lan

t P

ow

er

Pro

du

cti

vit

y

Ve

rsu

s a

2-S

tag

e E

jec

tor

Sy

ste

m


04/18/2023

99,600 49,900 29,900 10,000-10

-5

0

5

10

15

20

25

30

35

40




Sim

ple

Payb

ack

Perio

d fo

r R

etro

fit G

as R

emov

al In

stal

latio

ns




04/18/2023


Y AXISTechnical Figure of Merit

Hybrid -- 3rd Stage

Turbocomp.Simple Payback Periods (years)

4.482.11.51.5

0.90.71.29.9

Ratio of capital costs of gas removal alternatives to their net savings as the value of avoided gas removal energy. Basis of energy savings is the gas removal duty for the 2-stage steam jet ejector system. This yields a simple payback period value as years to recover capital costs for each gas removal alternative.

Negative values indicate alternative gas removal system costs more to operate than a 2-stage ejector system -- payback will not happen based on energy savings.

RETURN

RETURN


04/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,0000.00

0.40

0.80

1.20

1.60

2.00

2.40

2.80

3.20

3.60

4.00

4.40




Net

Pla

nt

Po

wer

Pro

du

ctiv

ity

Ver

sus

a 2-

Sta

ge

Eje

cto

r S

yste

m


RETURN


04/18/2023

10,000 30,100 50,100 149,2000

100

200

300

400

500

600


3-Stage Turbo

Reboiler

Biphase Eductor



Sim

ple

Payb

ack P

eri

od

fo

r R

etr

ofi

t G

as R

em

oval In

sta

llati

on

s


0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15

1.20

1.25





Ne

t P

lan

t P

ow

er

Pro

du

cti

vit

y

Ve

rsu

s a

2-S

tag

e E

jec

tor

Sy

ste

m


04/18/2023

99,600 49,900 29,900 10,000-10

-5

0

5

10

15

20

25

30

35

40




Sim

ple

Payb

ack

Perio

d fo

r R

etro

fit G

as R

emov

al In

stal

latio

ns



0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15

1.20

1.25





Ne

t P

lan

t P

ow

er

Pro

du

cti

vit

y

Ve

rsu

s a

2-S

tag

e E

jec

tor

Sy

ste

m


04/18/2023

99,600 49,900 29,900 10,000-10

-5

0

5

10

15

20

25

30

35

40




Sim

ple

Payb

ack

Perio

d fo

r R

etro

fit G

as R

emov

al In

stal

latio

ns



AXG-9-29432-01]document.xls

Page 3.3a.93 10:22:2004/18/2023

Plot Data : Engineering and Economic Figures of Merit versus Noncondensable Gas Levels

Case Group Descriptions Case Discriminators X AXIS Y AXISPlant Feed Temperatures Noncondensable Technical Figure of Merit

Gas Levels inPower Turbine

Feed Steam

Flash Flash Outlet part per millionInlet to Turbine by volume

ppmv

2-StageSteam Jet

SystemRatios of Technology Productivities

High temperature, Very high gas 550 334 99,600 1.00High temperature, High gas 49,900 1.00High temperature, Mid gas 29,900 1.00High temperature, Low gas 10,000 1.00

Low temperature, Low gas 350 235 10,000 1.00Low temperature, Mid gas 30,100 1.00Low temperature, High gas 50,100 1.00Low temperature, Very high gas 149,200 1.00

oF oF



Values greater than 1 indicate alternative technology consumes proportionally less power than 2-stage ejector system for gas removal.


Page 3.3a.94 10:22:2004/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00


2-Stage Ejectors

3-Stage Turbo

Reboiler

Biphase Eductor



Ne

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Pro

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Page 3.3a.95 10:22:2004/18/2023

CALCULATION BASES :Nominal Discount Rate =

Project life at time of estimated NPV :Contract Price of Electricity =

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

($ 35,000,000)

($ 30,000,000)

($ 25,000,000)

($ 20,000,000)

($ 15,000,000)

($ 10,000,000)

($ 5,000,000)

$ 0

$ 5,000,000

$ 10,000,000

$ 15,000,000

$ 20,000,000

$ 25,000,000

$ 30,000,000


3-Stage Turbo

Reboiler

Biphase Eductor



Ne

t P

res

en

t V

alu

es


Page 3.3a.96 10:22:2004/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15


2-Stage Ejectors

3-Stage Turbo

Reboiler

Biphase Eductor



Ne

t P

lan

t P

ow

er

Pro

du

cti

vit

y

Vers

us

a 2

-Sta

ge E

jec

tor

Sys

tem


Page 3.3a.97 10:22:2004/18/2023

CALCULATION BASES :Nominal Discount Rate = 10.0%

Project life at time of estimated NPV : 10

0 20,000 40,000 60,000 80,000 100,000 120,000

-$ 10,000,000

-$ 9,000,000

-$ 8,000,000

-$ 7,000,000

-$ 6,000,000

-$ 5,000,000

-$ 4,000,000

-$ 3,000,000

-$ 2,000,000

-$ 1,000,000

$ 0

$ 1,000,000

$ 2,000,000

$ 3,000,000


3-Stage Turbo Reboiler

Biphase Eductor Hybrid -- Ejector & Turbo


Net

Pre

sen

t V

alu

es


Page 3.3a.98 10:22:2004/18/2023

Contract Price of Electricity = $ 0.040


Page 3.3a.99 10:22:2004/18/2023


Y AXIS Y AXISTechnical Figure of Merit Economic Figure of Merit

3-Stage Reboiler Biphase Hybrid -- 2-Stage 3-Stage Reboiler BiphaseTurbocomp. System Eductor 3rd Stage Steam Jet Turbocomp. System Eductor

System System Turbocomp. System System SystemRatios of Technology Productivities Net Present Value at Time + 10

Applied Price of Electricity = $ 0.0400 1.09 1.01 0.98 1.07 N/A $ (8,310,000) $ (3,910,000) $ (3,150,000)1.06 1.01 1.02 1.05 N/A $ (1,540,000) $ (4,590,000) $ (980,000)1.04 1.01 1.03 1.03 N/A $ (130,000) $ (5,040,000) $ (400,000)1.01 1.00 1.02 1.01 N/A $ (800,000) $ (5,510,000) $ (550,000)High-Temperature Cases High-Temperature Cases

1.07 1.07 1.02 1.05 N/A $ 1,690,000 $ (3,910,000) $ (3,280,000)1.22 1.26 1.03 1.16 N/A $ 5,180,000 $ 4,000,000 $ (2,690,000)1.38 1.48 1.04 1.25 N/A $ 3,740,000 $ 9,440,000 $ (2,660,000)2.04 4.28 1.29 1.59 N/A $ (26,300,000) $ 20,070,000 $ (1,560,000)Low-Temperature Cases Low-Temperature Cases



Values greater than 1 indicate alternative technology consumes proportionally less power than 2-stage ejector system for gas removal.

The economic figure of merit for each technology in these charts is the net present value (NPV) of the revenues versus the costs for installation and operation of the alternative. Revenues are attributed based on energy savings, which are estimated as the difference between the utility demand for the alternative gas removal system compared to that of a 2-stage steam jet ejector system for the same power plant.

Positive NPV values indicate the alternative gas removal system will yield a return on investment. Negative values mean the conversion to and operation of the alternative will lose money compared to retaining a steam jet ejector system for gas removal. The values plotted below for NPV are at a fixed point in time listed below the margin of the figures. By changing the year selected, the returns on investments can be shown after varying period of operating time.


Page 3.3a.100 10:22:2004/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00


2-Stage Ejectors

3-Stage Turbo

Reboiler

Biphase Eductor



Ne

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lan

t P

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Pro

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Ve

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s a

2-S

tag

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Page 3.3a.101 10:22:2004/18/2023

10.0% General Inflation = 2.0%10 years Electricity price escalation : 2.0%

$ 0.040 per kWh Tax Rate = 34.0%

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

($ 35,000,000)

($ 30,000,000)

($ 25,000,000)

($ 20,000,000)

($ 15,000,000)

($ 10,000,000)

($ 5,000,000)

$ 0

$ 5,000,000

$ 10,000,000

$ 15,000,000

$ 20,000,000

$ 25,000,000

$ 30,000,000


3-Stage Turbo

Reboiler

Biphase Eductor



Ne

t P

res

en

t V

alu

es


Page 3.3a.102 10:22:2004/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15


2-Stage Ejectors

3-Stage Turbo

Reboiler

Biphase Eductor



Ne

t P

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t P

ow

er

Pro

du

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vit

y

Vers

us

a 2

-Sta

ge E

jec

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Sys

tem


Page 3.3a.103 10:22:2004/18/2023

General Inflation = 2.0%years Electricity price escalation : 2.0%

0 20,000 40,000 60,000 80,000 100,000 120,000

-$ 10,000,000

-$ 9,000,000

-$ 8,000,000

-$ 7,000,000

-$ 6,000,000

-$ 5,000,000

-$ 4,000,000

-$ 3,000,000

-$ 2,000,000

-$ 1,000,000

$ 0

$ 1,000,000

$ 2,000,000

$ 3,000,000





Net

Pre

sen

t V

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Page 3.3a.104 10:22:2004/18/2023

per kWh Tax Rate = 34.0%


Page 3.3a.105 10:22:2004/18/2023


Y AXISEconomic Figure of Merit

Hybrid -- 3rd Stage

Turbocomp.years per kWh $ 60,000 $ 1,250,000 $ 1,100,000 $ 510,000

$ 2,350,000 $ 6,040,000 $ 6,510,000 $ (3,790,000)

The economic figure of merit for each technology in these charts is the net present value (NPV) of the revenues versus the costs for installation and operation of the alternative. Revenues are attributed based on energy savings, which are estimated as the difference between the utility demand for the alternative gas removal system compared to that of a 2-stage steam jet ejector system for the same power plant.

Positive NPV values indicate the alternative gas removal system will yield a return on investment. Negative values mean the conversion to and operation of the alternative will lose money compared to retaining a steam jet ejector system for gas removal. The values plotted below for NPV are at a fixed point in time listed below the margin of the figures. By changing the year selected, the returns on investments can be shown after varying period of operating time.


Page 3.3a.106 10:22:2004/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00


2-Stage Ejectors

3-Stage Turbo

Reboiler

Biphase Eductor



Ne

t P

lan

t P

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er

Pro

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vit

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Ve

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s a

2-S

tag

e E

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Sy

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m


Page 3.3a.107 10:22:2004/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

($ 35,000,000)

($ 30,000,000)

($ 25,000,000)

($ 20,000,000)

($ 15,000,000)

($ 10,000,000)

($ 5,000,000)

$ 0

$ 5,000,000

$ 10,000,000

$ 15,000,000

$ 20,000,000

$ 25,000,000

$ 30,000,000


3-Stage Turbo

Reboiler

Biphase Eductor



Ne

t P

res

en

t V

alu

es


Page 3.3a.108 10:22:2004/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000

0.95

1.00

1.05

1.10

1.15


2-Stage Ejectors

3-Stage Turbo

Reboiler

Biphase Eductor



Ne

t P

lan

t P

ow

er

Pro

du

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vit

y

Vers

us

a 2

-Sta

ge E

jec

tor

Sys

tem


Page 3.3a.109 10:22:2004/18/2023

0 20,000 40,000 60,000 80,000 100,000 120,000

-$ 10,000,000

-$ 9,000,000

-$ 8,000,000

-$ 7,000,000

-$ 6,000,000

-$ 5,000,000

-$ 4,000,000

-$ 3,000,000

-$ 2,000,000

-$ 1,000,000

$ 0

$ 1,000,000

$ 2,000,000

$ 3,000,000





Net

Pre

sen

t V

alu

es

Sheet 3.4a AuxGraphs


Page 3.4.110 10:22:2004/18/2023

PLOT DRIVE STEAM DEMAND NEEDED TO OPERATE NONCONDENSABLE GAS REMOVAL SYSTEMS

Case Discriminators Case No. Gas Levels Drive Steam to Gas Removalppmv Base Case3-St. Turbo Reboiler Biphase Hybrid

high temp x-hi gas 8 99,557 348,709 232,693 5,438 297,090 308,617high gas 1 49,917 170,543 116,794 2,103 134,366 141,998mid gas 2 29,934 98,633 69,073 1,239 62,824 81,100low gas 3 9,980 28,669 21,271 410 0 23,149

low temp low gas 4 10,034 117,936 55,415 2,119 96,584 71,589mid gas 5 30,065 389,825 180,440 6,289 363,385 250,352high gas 6 50,053 620,455 304,875 10,425 576,272 439,068x-hi gas 7 149,180 1,480,018 893,872 20,225 1,099,651 1,372,214

0.0E+00 2.0E+04 4.0E+04 6.0E+04 8.0E+04 1.0E+05 1.2E+05 1.4E+05 1.6E+050E+00

1E+06

2E+06

Demand For Drive Steam For Gas RemovalAll Temperature Cases

Column E

Column F

Column G

Column H

Column I

Column E

Column F

Column G

Column H

Column I

NonCondensable Gas Levels in Flashed Steam (ppmv)

Dri

ve S

team

Req

uir

ed

(lb

/hr)



Page 3.4.111 10:22:2004/18/2023

0.0E+00 2.0E+04 4.0E+04 6.0E+04 8.0E+04 1.0E+05 1.2E+05

0.0E+00

1.0E+05

2.0E+05

3.0E+05

4.0E+05

Demand For Drive Steam For Gas RemovalHigh Temperature Cases

Column E

Column F

Column G

Column H

Column I


Dri

ve

Ste

am

Re

qu

ire

d (

lb/h

r)

0.0E+00 2.0E+04 4.0E+04 6.0E+04 8.0E+04 1.0E+05 1.2E+05 1.4E+05 1.6E+05

0.0E+00

2.0E+05

4.0E+05

6.0E+05

8.0E+05

1.0E+06

1.2E+06

1.4E+06

1.6E+06

Demand For Drive Steam For Gas RemovalLow Temperature Cases

Column E

Column F

Column G

Column H

Column I


Dri

ve

Ste

am

Re

qu

ire

d (

lb/h

r)



Page 3.4.112 10:22:2004/18/2023

PLOT DRIVE STEAM DEMAND NEEDED TO OPERATE NONCONDENSABLE GAS REMOVAL SYSTEMS

0.0E+00 2.0E+04 4.0E+04 6.0E+04 8.0E+04 1.0E+05 1.2E+05 1.4E+05 1.6E+050E+00

1E+06

2E+06

Demand For Drive Steam For Gas RemovalAll Temperature Cases

Column E

Column F

Column G

Column H

Column I

Column E

Column F

Column G

Column H

Column I


Dri

ve S

team

Req

uir

ed

(lb

/hr)

This worksheet plots the mass flowrates of drive steam needed to achieve noncondensable gas removal from the power plant when the power turbine is being fed sufficient flashed steam to produce 50 MW of power. For the reboiler systems, this does not account for the vent gas stream discarded from the power process.

See also the adjacent "% SteamUse" plots of the relative rates of consumption of pure steam. That worksheet does account for reboiler vent stream losses.



Page 3.4.113 10:22:2004/18/2023

0.0E+00 2.0E+04 4.0E+04 6.0E+04 8.0E+04 1.0E+05 1.2E+05

0.0E+00

1.0E+05

2.0E+05

3.0E+05

4.0E+05

Demand For Drive Steam For Gas RemovalHigh Temperature Cases

Column E

Column F

Column G

Column H

Column I


Dri

ve

Ste

am

Re

qu

ire

d (

lb/h

r)

0.0E+00 2.0E+04 4.0E+04 6.0E+04 8.0E+04 1.0E+05 1.2E+05 1.4E+05 1.6E+05

0.0E+00

2.0E+05

4.0E+05

6.0E+05

8.0E+05

1.0E+06

1.2E+06

1.4E+06

1.6E+06

Demand For Drive Steam For Gas RemovalLow Temperature Cases

Column E

Column F

Column G

Column H

Column I


Dri

ve

Ste

am

Re

qu

ire

d (

lb/h

r)

3.4b % SteamUse


3.4b.114 04/18/202310:22:20

flashed steam gas & steam feed rates composition

CASE ppmv gas H2O mass gas mass std. Flashed

ID fraction fraction steam gas

lb/hr lb/hrHIGH TEMPERATURE CASES, HIGH GAS

B-1 base case 49,900 0.886 0.114 858,000 110,000 total = 968,000

B1.1 3-st. turbo 49,900 0.886 0.114 858,000 110,000

B1.2 reboiler 49,900 0.886 0.114 xx xx

B1.3 eductor 49,900 0.886 0.114 858,000 110,000

B1.4 hybrid 49,900 0.886 0.114 858,000 110,000


CASE ppmv gas H2O mass gas mass std. Flashed

ID fraction fraction steam gas

lb/hr lb/hr

HIGH TEMPERATURE CASES, MEDIUM GASB-2 base case 29,900 0.930 0.070 867,000 65,000

total = 932,000

B2.1 3-st. turbo 29,900 0.930 0.070 867,000 65,000

B2.2 reboiler 29,900 0.930 0.070 xx xx

B2.3 eductor 29,900 0.930 0.070 867,000 65,000

B2.4 hybrid 29,900 0.930 0.070 867,000 65,000


CASE ppmv gas H2O mass gas mass std. FlashedID fraction fraction steam gas

lb/hr lb/hr

HIGH TEMPERATURE CASES, LOW GASB-3 base case 10,000 0.976 0.024 874,000 22,000

total = 896,000

B3.1 3-st. turbo 10,000 0.976 0.024 874,000 22,000

3.4b % SteamUse


3.4b.115 04/18/202310:22:20

B3.2 reboiler 10,000 0.976 0.024 xx xx

B3.3 eductor 10,000 0.976 0.024 874,000 22,000

B3.4 hybrid 10,000 0.976 0.024 874,000 22,000

3.4b % SteamUse


3.4b.116 04/18/202310:22:20



lb/hr lb/hr

LOW TEMPERATURE CASES, LOW GASB-4 base case 10,000 0.976 0.024 1,411,000 35,000

total = 1,446,000

B4.1 3-st. turbo 10,000 0.976 0.024 1,411,000 35,000

B4.2 reboiler 10,000 0.976 0.024 xx xx

B4.3 eductor 10,000 0.976 0.024 1,411,000 35,000

B4.4 hybrid 10,000 0.976 0.024 1,411,000 35,000 - -



lb/hr lb/hr

LOW TEMPERATURE CASES, MEDIUM GASB-5 base case 30,100 0.929 0.071 1,399,000 106,000

total = 1,505,000

B5.1 3-st. turbo 30,100 0.929 0.071 1,399,000 106,000

B5.2 reboiler 30,100 0.929 0.071 xx xx

B5.3 eductor 30,100 0.929 0.071 1,399,000 106,000

B5.4 hybrid 30,100 0.929 0.071 1,399,000 106,000



lb/hr lb/hr

LOW TEMPERATURE CASES, HIGH GASB-6 base case 50,100 0.886 0.114 1,385,000 178,000

total = 1,563,000

B6.1 3-st. turbo 50,100 0.886 0.114 1,385,000 178,000

B6.2 reboiler 50,100 0.886 0.114 xx xx

3.4b % SteamUse


3.4b.117 04/18/202310:22:20

B6.3 eductor 50,100 0.886 0.114 1,385,000 178,000

B6.4 hybrid 50,100 0.886 0.114 1,385,000 178,000

3.4b % SteamUse


3.4b.118 04/18/202310:22:20



lb/hr lb/hr

LOW TEMPERATURE CASES, VERY HIGH GASB-7 base case 149,200 0.700 0.300 1,311,000 562,000

total = 1,873,000

B7.1 3-st. turbo 149,200 0.700 0.300 1,311,000 562,000

B7.2 reboiler 149,200 0.700 0.300 xx xx

B7.3 eductor 149,200 0.700 0.300 1,311,000 562,000

B7.4 hybrid 149,200 0.700 0.300 1,311,000 562,000



lb/hr lb/hr

HIGH TEMPERATURE CASES, VERY HIGH GASB-8 base case 99,600 0.787 0.213 836,000 226,000

total = 1,062,000

B8.1 3-st. turbo 99,600 0.787 0.213 836,000 226,000

B8.2 reboiler 99,600 0.787 0.213 xx xx

B8.3 eductor 99,600 0.787 0.213 836,000 226,000

B8.4 hybrid 99,600 0.787 0.213 836,000 226,000

PLOT DATAX AXIS Y AXIS

BASE 3-STAGE REBOILER EDUCTORgas CASE TURBOloads Percent Pure Steam to Gas Removal Power

(ppmv) (total steam use for all gas removal duty, including reboiler vent gas)

hi temp 10,000 3.2% 2.4% 2.4% 0.00% 29,900 10.6% 7.4% 7.5% 6.7% 49,900 17.6% 12.1% 12.8% 13.9% 99,600 32.8% 21.9% 27.0% 28.0%

low temp 10,000 8.2% 3.8% 2.6% 6.7%

3.4b % SteamUse


3.4b.119 04/18/202310:22:20

30,100 25.9% 12.0% 7.9% 24.2% 50,100 39.7% 19.5% 13.3% 36.8% 149,200 79.0% 47.7% 43.1% 58.7%

3.4b % SteamUse


3.4b.120 04/18/202310:22:20

- 2 0 ,0 0 0 4 0 ,0 0 0 6 0 ,0 0 0 8 0 ,0 0 0 1 0 0 ,0 0 0 1 2 0 ,0 0 0

0 .0 %

5 .0 %

1 0 .0 %

1 5 .0 %

2 0 .0 %

2 5 .0 %

3 0 .0 %

3 5 .0 %

High Temperature Cases: Steam Used for Gas Removal

base case 2-stage ejector Column E reboiler + 2-st. ejector

3-stage biphase eductor hybrid turbo/2-st. ejector

Ga s Con c e ntra tion s in Ste a m, p pmv

% s

tea

m to

ga

s re

mo

va

l po

we

r(a

s p

ure

ste

am

)

- 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

Low Temperature Cases: Steam Used for Gas Removal

base case 2-stage ejector Column E

reboiler + 2-st. ejector 3-stage biphase eductor

hybrid turbo/2-st. ejector

Gas Concentrations in Steam, ppmv

% s

tea

m t

o g

as

re

mo

va

l p

ow

er

(as

pu

re s

tea

m)

3.4b % SteamUse


3.4b.121 04/18/202310:22:20

- 2 0 ,0 0 0 4 0 ,0 0 0 6 0 ,0 0 0 8 0 ,0 0 0 1 0 0 ,0 0 0 1 2 0 ,0 0 0

0 .0 %

5 .0 %

1 0 .0 %

1 5 .0 %

2 0 .0 %

2 5 .0 %

3 0 .0 %

3 5 .0 %





% s

tea

m to

ga

s re

mo

va

l po

we

r(a

s p

ure

ste

am

)

3.4b % SteamUse


3.4b.122 04/18/202310:22:20

gas & steam feed rates steam to vacuum flow to reboiler vent

reboiler feed

steam gas gas steam

lb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr(pure steam) (pure steam)

xx xx 151,000 17.6% 171,000 = raw gas + steam

xx xx 104,000 12.1% 117,000

858,000 110,000 2,000 0.2% 108,000 98.1% 108,000 total = 968,000 2,000 = raw gas + steam 216,000 = raw steam + gas

xx xx 119,000 13.9% 134,000

xx xx 126,000 14.7% 142,000


reboiler feed

steam gas gas steam

lb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr


xx xx 64,000 7.4% 69,000

867,000 65,000 1,000 0.1% 64,000 98.0% 64,000 total = 932,000 1,000 = raw gas + steam 128,000 = raw steam + gas

xx xx 58,000 6.7% 63,000

xx xx 75,000 8.7% 81,000


reboiler feedsteam gas gas steamlb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr


xx xx 21,000 2.4%

K5

Martin Vorum: this worksheet is to examine the relative distribution of flashed steam to power production after deductions for gas removal duties.

3.4b % SteamUse


3.4b.123 04/18/202310:22:20

21,000

874,000 22,000 - 0.0% 21,000 97.3% 21,000 total = 896,000 - = raw gas + steam 42,000 = raw steam + gas

xx xx - 0.0% -

xx xx 23,000 2.6% 23,000

3.4b % SteamUse


3.4b.124 04/18/202310:22:20




xx xx 54,000 3.8% 55,000

1,411,000 35,000 2,000 0.1% 34,000 97.6% 34,000 total = 1,446,000 2,000 = raw gas + steam 68,000 = raw steam + gas

xx xx 94,000 6.7% 97,000

xx xx 70,000 5.0%xx xx 72,000




xx xx 168,000 12.0% 180,000


xx xx 338,000 24.2% 363,000

xx xx 233,000 16.7% 250,000




xx xx 270,000 19.5% 305,000


3.4b % SteamUse


3.4b.125 04/18/202310:22:20

xx xx 510,000 36.8% 576,000

xx xx 389,000 28.1% 439,000

3.4b % SteamUse


3.4b.126 04/18/202310:22:20



xx xx 1,036,000 79.0% 1,480,000 = raw gas + steam

xx xx 626,000 47.7% 894,000

1,311,000 562,000 14,000 1.1% 551,000 98.0% 551,000 total = 1,873,000 20,000 = raw gas + steam ### = raw steam + gas

xx xx 770,000 58.7% 1,100,000

xx xx 960,000 73.2% 1,372,000





836,000 226,000 4,000 0.5% 222,000 98.2% 222,000 total = 1,062,000 5,000 = raw gas + steam 444,000 = raw steam + gas



PLOT DATAY AXIS

HYBRID

Percent Pure Steam to Gas Removal Power(total steam use for all gas removal duty, including reboiler vent gas)

2.6%8.7%

14.7%29.1%

5.0%

This worksheet plots the percent of pure steam in the plant feed needed to achieve noncondensable gas removal from the power plant, when the power turbine is being fed sufficient flashed steam to produce 50 MW of power. The values and plots below do account for the reboiler losses of steam in the vent gas.

See also the adjacent "AuxGraphs" plots of the mass flowrates of consumption of bulk flashed steam. That worksheet accounts only for vacuum system gas demand for the reboiler cases.

3.4b % SteamUse


3.4b.127 04/18/202310:22:20

16.7%28.1%73.2%



3.4b % SteamUse


3.4b.128 04/18/202310:22:20

- 2 0 ,0 0 0 4 0 ,0 0 0 6 0 ,0 0 0 8 0 ,0 0 0 1 0 0 ,0 0 0 1 2 0 ,0 0 0

0 .0 %

5 .0 %

1 0 .0 %

1 5 .0 %

2 0 .0 %

2 5 .0 %

3 0 .0 %

3 5 .0 %





% s

tea

m to

ga

s re

mo

va

l po

we

r(a

s p

ure

ste

am

)

- 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%






% s

tea

m t

o g

as

re

mo

va

l p

ow

er

(as

pu

re s

tea

m)

3.4b % SteamUse


3.4b.129 04/18/202310:22:20

- 2 0 ,0 0 0 4 0 ,0 0 0 6 0 ,0 0 0 8 0 ,0 0 0 1 0 0 ,0 0 0 1 2 0 ,0 0 0

0 .0 %

5 .0 %

1 0 .0 %

1 5 .0 %

2 0 .0 %

2 5 .0 %

3 0 .0 %

3 5 .0 %





% s

tea

m to

ga

s re

mo

va

l po

we

r(a

s p

ure

ste

am

)

3.4b % SteamUse


3.4b.130 04/18/202310:22:20

flow to reboiler vent

steam

% of feed(pure steam)

normalized to flash

plant feed

12.6% 12.6%


steam

% of feed

normalized to flash

plant feed

7.4% 7.4%


steam% of feed

normalized to flash

3.4b % SteamUse


3.4b.131 04/18/202310:22:20

plant feed

2.4% 2.4%

3.4b % SteamUse


3.4b.132 04/18/202310:22:20


steam% of feed

normalized to flash

plant feed

2.4% 2.4%


steam% of feed

normalized to flash

plant feed

7.4% 7.4%


steam% of feed

normalized to flash

plant feed

12.6% 12.6%

3.4b % SteamUse


3.4b.133 04/18/202310:22:20

3.4b % SteamUse


3.4b.134 04/18/202310:22:20


steam% of feed

normalized to flash

plant feed

42.0% 42.0%


steam% of feed

normalized to flash

plant feed

26.6% 26.6%



3.4b % SteamUse


3.4b.135 04/18/202310:22:20



3.4b % SteamUse


3.4b.136 04/18/202310:22:20

- 2 0 ,0 0 0 4 0 ,0 0 0 6 0 ,0 0 0 8 0 ,0 0 0 1 0 0 ,0 0 0 1 2 0 ,0 0 0

0 .0 %

5 .0 %

1 0 .0 %

1 5 .0 %

2 0 .0 %

2 5 .0 %

3 0 .0 %

3 5 .0 %





% s

tea

m to

ga

s re

mo

va

l po

we

r(a

s p

ure

ste

am

)

- 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%






% s

tea

m t

o g

as

re

mo

va

l p

ow

er

(as

pu

re s

tea

m)

3.4b % SteamUse


3.4b.137 04/18/202310:22:21

- 2 0 ,0 0 0 4 0 ,0 0 0 6 0 ,0 0 0 8 0 ,0 0 0 1 0 0 ,0 0 0 1 2 0 ,0 0 0

0 .0 %

5 .0 %

1 0 .0 %

1 5 .0 %

2 0 .0 %

2 5 .0 %

3 0 .0 %

3 5 .0 %





% s

tea

m to

ga

s re

mo

va

l po

we

r(a

s p

ure

ste

am

)

Sheet 3.5 Issues


04/18/2023

SUBSYSTEMS COST ISSUES

geothermal source reservoir prolonged productivityproduction wells reduced replacementgathering system growth, durabilityall of above productivity/pressure loss

Power Plantpower turbine materials durability

productivity/efficiencycondensers materials durability

productivity/efficiencycooling towers fan power demand

c.w. pump power demandvacuum system materials durability

productivity/efficiencycapital and O&M costs

net plant electrical sales net revenues

Emissions Control (this is only a factor when required for plant permitting)

gas abatement process size

efficiency

product removal/disposaloperating suppliesmaterials durabilitypotential elimination of abatement process

FACILITY SECTIONS

Production Systems

ISSUES AFFECTING THE ECONOMICS OF GEOTHERMAL POWER SYSTEMS INFRASTRUCTURE

_______________________________________________________________________________

INFLUENCES OF THE CHOICE OF ALTERNATIVE METHODS FOR NONCONDENSABLE GAS REMOVAL

IN COMPARISON TO STEAM JET EJECTOR BASELINE SYSTEMS

Sheet 3.5 Issues


04/18/2023

Legend : clear cell -- no influence light shade -- moderate or indirect influence

Sheet 3.5 Issues


04/18/2023

GAS REMOVAL SYSTEMS

DOWNSTREAM VACUUM

overall facility service life baseline

frequency of new wells baseline

pipelines, controls, vessels baseline

reduced gross flow, pressure drop baseline

housing, rotors/blading baseline

power output baseline

shell and tubes baseline

reduced vapor load, higher heat transfer baseline

less cooling water flow baseline

less cooling water flow baseline

piping, vacuum drivers baseline

reduced steam use baseline

higher first cost, repairs, replacement baseline

increased output and/or reduced costs baseline

units smaller due to decreased throughput baseline

baseline

transport and disposal/sale baseline

lower quantities of makeup reagents baseline

pipelines, controls, vessels baseline

potential elimination of abatement process

AFFECTED COMPONENTS OR OPERATING FACTORS

Steam Jet Ejector

Turbo-Compressor

Biphase Eductor

operations at higher mass transfer, equilibrium driving forces


_______________________________________________________________________________



Sheet 3.5 Issues


04/18/2023

dark shade -- strong or direct influence

Sheet 3.5 Issues


04/18/2023

GAS REMOVAL SYSTEMS

UPSTREAM

Reboiler


_______________________________________________________________________________



Sheet 4.1 Op'sDetails


04/18/2023

OVERALL PLANT DEFINITION

CASE PARAMETERS AND TECHNOLOGY CONFIGURATION

MAIN CASE GROUP 1

B-1

B1.1

B1.2

B1.3

B1.4

Case No.

5 CASES : HIGH TEMPERATURE, HIGH PRESSURE, HIGH GAS

BASE CASE 1 -- single flash, condensing turbine, with 2-stage steam jet ejector vacuum system to remove noncondensable gases from main condenser. Target 50 MW gross power output from turbine/generator. Applied ca. 50,000 parts per million CO2 gas (mole basis, ppmv) in turbine feed steam. Production fluid delivered to flash at 550 oF.

ALTERNATE 1.1 -- replace ejector battery with 3-stage turbocompressor train. For costing, assume redundant ejector train as emergency backup. Other criteria as per Base Case.

ALTERNATE 1.2 -- a vertical-tube, falling film reboiler is installed after the flash separator, processing raw steam before its entry to the power turbine. Conventional steam jet ejectors handle the reduced gas load from the main condenser. Adjust the gross plant feed rate to maintain 50 MW production from the generator. Other criteria as per Base Case.

ALTERNATE 1.3 -- using the base case configuration, replace the steam jet ejectors with eductors for which the motive fluid is flashing, spent brine from the plant inlet flash tank. Other criteria as per Base Case.

ALTERNATE 1.4 -- modify the base case ejector train to a configuration with two stages of steam jet ejectors and a 3rd-stage turbocompressor. The ejectors will be at higher efficiency than in a net 2-stage system. A backup 3rd stage ejector is assumed. Other criteria as per Base Case.

RETURN



04/18/2023



Case No.

RETURN

MAIN CASE GROUP 2

B-2

B2.1 ALTERNATE 2.1 -- replace ejector battery with 3-stage turbocompressor train.

B2.2 ALTERNATE 2.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.

B2.3 ALTERNATE 2.3 -- replace the steam jet ejectors with biphase eductors.

B2.4 ALTERNATE 2.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.

5 CASES : HIGH TEMPERATURE, HIGH PRESSURE, MEDIUM GAS

BASE CASE 2 -- same as Base Case 1 but designating ca. 20,000 ppmv CO2 in turbine feed steam.



04/18/2023



Case No.

RETURN

MAIN CASE GROUP 3

B-3





5 CASES : HIGH TEMPERATURE, HIGH PRESSURE, LOW GAS

BASE CASE 2 -- same as Base Case 1 but designating ca. 10,000 ppmv CO2 in turbine feed steam.



04/18/2023



Case No.

RETURN

MAIN CASE GROUP 4

B-4





5 CASES : LOW TEMPERATURE, LOW PRESSURE, LOW GAS

BASE CASE 4 -- same as Base Case 1 but with production fluid delivered to flash at 350 oF.



04/18/2023



Case No.

RETURN

MAIN CASE GROUP 5

B-5





5 CASES : LOW TEMPERATURE, LOW PRESSURE, MEDIUM GAS




04/18/2023



Case No.

RETURN

PLACE HOLDER

MAIN CASE GROUP 6

B-6





5 CASES : LOW TEMPERATURE, LOW PRESSURE, HIGH GAS




04/18/2023



Case No.

RETURN

PLACE HOLDER

MAIN CASE GROUP 7

B-7





5 CASES : LOW TEMPERATURE, LOW PRESSURE, VERY HIGH GAS




04/18/2023



Case No.

RETURN

PLACE HOLDER

MAIN CASE GROUP 8

B-8





5 CASES : HIGH TEMPERATURE, HIGH PRESSURE, VERY HIGH GAS




04/18/2023



Case No.

RETURN

PLACE HOLDER

SENSITIVITY GROUP S-1 -- LOW EJECTOR EFFICIENCY

S-1

S1.1 ALTERNATE S1.1 -- replace ejector battery with 3-stage turbocompressor train.

S1.2 ALTERNATE S1.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.

S1.3 ALTERNATE S1.3 -- replace the steam jet ejectors with biphase eductors.

S1.4 ALTERNATE S1.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.

PLACE HOLDER


BASE CASE S1 -- same as Base Case 1 but with a 3-stage steam jet ejector system in place of the two stage system. Expect alternative technologies' prior advantages to be lessened.



04/18/2023



Case No.

RETURN

SENSITIVITY GROUP S-2 -- LOW EJECTOR EFFICIENCY

S-2





PLACE HOLDER


BASE CASE S2 -- same as Base Case 1 but with steam jet ejector efficiencies reduced from 23 % to 15 %. Expect alternative technologies" advantages to increase.



04/18/2023



Case No.

RETURN

S-3





PLACE HOLDER

SENSITIVITY GROUP S-3 -- 80 oF WET BULB TEMPERATURE

5 CASES : HIGH TEMPERATURE, HIGH PRESSURE, MID GAS

BASE CASE S3 -- same as Base Case1 but with a wet bulb temperature of 70 oF. Expect all parasitic steam loads to increase.



04/18/2023



Case No.

RETURN

S-4





PLACE HOLDER

SENSITIVITY GROUP S-4 -- 80 oF WET BULB TEMPERATURE


BASE CASE S4 -- same as Base Case 1 and Base Case S3, but with a wet bulb temperature of 80 oF. Expect all parasitic steam loads to increase.



04/18/2023



Case No.

RETURN

SENSITIVITY GROUP S-5 --

S-5





PLACE HOLDER


BASE CASE S5 -- same as Base Case 4 but with 3-stage steam jet ejector system in place of 2-stage system.



04/18/2023



Case No.

RETURN


S-6





PLACE HOLDER


BASE CASE S6 -- same as Base Case 4 but with steam jet ejector efficiencies reduced from 23 % to 15 %. Expect alternative technologies' advantages to increase.



04/18/2023



Case No.

RETURN


S-7





PLACE HOLDER


BASE CASE S7 -- same as Base Case 4 but with wet bulb temperature of 80 oF. Expect all parasitic steam loads to increase.



04/18/2023



Case No.

RETURN


S-8





PLACE HOLDER


BASE CASE S8 -- same as Base Case



04/18/2023



Case No.

RETURN


S-9






BASE CASE S9 -- same as Base Case, substituting a



04/18/2023

B-1

B1.1

B1.2

B1.3

B1.4

Case No.


P = PSIA

2,291,000 T = 550 48,800

P = 1,177

2,291,000 T = 550 48,800

P = 1176.8

2,289,000 T = 550 48,800

P = 1177

2,291,000 T = 550 48,800

P = 1177

2,291,000 T = 550 48,800

P = 1177

GROSS PLANT FEED (combined well flow to flash)

Combined Brine & Steam Flow

T = oF Combined Brine

& Steam Gas Conc'n.

lbs / hour (at 15% steam

quality)

parts per million by weight

(ppmw) as CO2



04/18/2023

Case No.

B-2

B2.1

B2.2

B2.3

B2.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

2,288,000 T = 550 29,000

P = 1,124

2,288,000 T = 550 29,000

P = 1124

2,287,000 T = 550 29,000

P = 1124

2,288,000 T = 550 29,000

P = 1124

2,288,000 T = 550 29,000

P = 1124



04/18/2023

Case No.

B-3

B3.1

B3.2

B3.3

B3.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

2,284,000 T = 550 9,600

P = 1,072

2,284,000 T = 550 9,600

P = 1072

2,284,000 T = 550 9,600

P = 1072

2,284,000 T = 550 9,600

P = 1072

2,284,000 T = 550 9,600

P = 1072



04/18/2023

Case No.

B-4

B4.1

B4.2

B4.3

B4.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

5,418,000 T = 350 6,500

P = 137

5,418,000 T = 350 6,500

P = 137

5,418,000 T = 350 6,500

P = 137

5,418,000 T = 350 6,500

P = 137

5,418,000 T = 350 6,500

P = 137



04/18/2023

Case No.

B-5

B5.1

B5.2

B5.3

B5.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

5,395,000 T = 350 19,700

P = 142

5,395,000 T = 350 19,700

P = 142

5,391,000 T = 350 19,700

P = 142

5,395,000 T = 350 19,700

P = 142

5,395,000 T = 350 19,700

P = 142



04/18/2023

Case No.

B-6

B6.1

B6.2

B6.3

B6.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

PLACE HOLDER PLACE HOLDER

5,365,000 T = 350 33,400

P = 146

5,365,000 T = 350 33,400

P = 146

5,354,000 T = 350 33,400

P = 146

5,365,000 T = 350 33,400

P = 146

5,365,000 T = 350 33,400

P = 146



04/18/2023

Case No.

B-7

B7.1

B7.2

B7.3

B7.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2PLACE HOLDER PLACE HOLDER

5,201,000 T = 350 108,500

P = 170

5,201,000 T = 350 108,500

P = 170

5,119,000 T = 350 108,500

P = 170

5,201,000 T = 350 108,500

P = 170

5,201,000 T = 350 108,500

P = 170



04/18/2023

Case No.

B-8

B8.1

B8.2

B8.3

B8.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2PLACE HOLDER PLACE HOLDER

2,297,000 T = 550 99,700

P = 1,316

2,297,000 T = 550 99,700

P = 1316

2,289,000 T = 550 99,700

P = 1316

2,297,000 T = 550 99,700

P = 1316

2,297,000 T = 550 99,700

P = 1316



04/18/2023

Case No.

S-1

S1.1

S1.2

S1.3

S1.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2


2,291,000 T = 550 48,800

P = 1,177

2,291,000 T = 550 48,800

P = 1177

2,289,000 T = 550 48,800

P = 1177

2,291,000 T = 550 48,800

P = 1177

2,291,000 T = 550 48,800

P = 1177




04/18/2023

Case No.

S-2

S2.1

S2.2

S2.3

S2.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

5,418,000 T = 350 6,500

P = 137

5,418,000 T = 350 6,500

P = 137

5,418,000 T = 350 6,500

P = 137

5,418,000 T = 350 6,500

P = 137

5,418,000 T = 350 6,500

P = 137




04/18/2023

Case No.

S-3

S3.1

S3.2

S3.3

S3.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

2,505,000 T = 550 28,900

P = 1,124

2,505,000 T = 550 28,900

P = 1124

2,505,000 T = 550 28,900

P = 1124

2,505,000 T = 550 28,900

P = 1124

2,505,000 T = 550 28,900

P = 1124




04/18/2023

Case No.

S-4

S4.1

S4.2

S4.3

S4.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

6,251,000 T = 350 6,400

P = 137

6,251,000 T = 350 6,400

P = 137

6,250,000 T = 350 6,400

P = 137

6,251,000 T = 350 6,400

P = 137

6,251,000 T = 350 6,400

P = 137




04/18/2023

Case No.

S-5

S5.1

S5.2

S5.3

S5.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2

ALTERNATE S5.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.

ALTERNATE S5.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.




04/18/2023

Case No.

S-6

S6.1

S6.2

S6.3

S6.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2






04/18/2023

Case No.

S-7

S7.1

S7.2

S7.3

S7.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2






04/18/2023

Case No.

S-8

S8.1

S8.2

S8.3

S8.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2






04/18/2023

Case No.

S-9

S9.1

S9.2

S9.3

S9.4


P = PSIA




& Steam Gas Conc'n.


quality)


(ppmw) as CO2





04/18/2023

B-1

B1.1

B1.2

B1.3

B1.4

Case No.

FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND

Total Flow

lbs / hour lbs / hour lbs / hour

T 334 49,900 968,000 3.424 50.0 170,500 0

P 114

T 334 49,900 968,000 3.424 50.0 116,800 15,000

P 114 closure

T 334 49,900 968,000 3.265 50.0 2,100 215,433

P 114 750,000 = clean steam turbine feed reboiler vent

T 334 49,900 968,000 3.424 50.0 134,400 17,257

P 114 closure

T 334 49,900 968,000 3.424 50.0 142,000 0

P 114

STEAM TEMPERATURE,

PRESSURE, and GAS CONCENTRATION

TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS

Flash Conditions CO2 ppm

by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output

Total Flow (with gas)

oF, PSIAinches Hg

abs.Megawatt

s

In all cases, the "Net Sales Electricity" reflects only the reduction from gross unit capacity caused by deducting the "Auxiliary" demands. No other utilities are counted in the "Net."



04/18/2023

Case No.

B-2

B2.1

B2.2

B2.3

B2.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s

T 334 29,900 932,000 3.419 50.0 98,600 0

P 113

T 334 29,900 932,000 3.419 50.0 69,100 5,210

P 113 closure

T 334 29,900 932,000 3.264 50.0 1,200 127,917


T 334 29,900 932,000 3.419 50.0 62,800 4,739

P 113 closure

T 334 29,900 932,000 3.419 50.0 81,100 0

P 113




04/18/2023

Case No.

B-3

B3.1

B3.2

B3.3

B3.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s

T 335 10,000 896,000 3.398 50.0 28,700 0

P 111

T 335 10,000 896,000 3.398 50.0 21,300 524

P 111 closure

T 335 10,000 896,000 3.265 50.0 400 42,201


T 335 10,000 896,000 3.398 50.0 0 0

P 111 closure

T 335 10,000 896,000 3.398 50.0 23,100 0

P 111




04/18/2023

Case No.

B-4

B4.1

B4.2

B4.3

B4.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s

T 235 10,000 1,446,000 3.397 50.0 117,900 0

P 23

T 235 10,000 1,446,000 3.397 50.0 55,400 1,373

P 23 closure

T 235 10,000 1,446,000 3.265 50.0 2,100 68,400

P 23 1,375,000 = clean steam turbine feed reboiler vent

T 235 10,000 1,446,000 3.397 50.0 96,600 2,393

P 23 closure

T 235 10,000 1,446,000 3.397 50.0 71,600 0

P 23




04/18/2023

Case No.

B-5

B5.1

B5.2

B5.3

B5.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s

T 234 30,100 1,505,000 3.419 50.0 389,800 0

P 23

T 234 30,100 1,505,000 3.419 50.0 180,400 13,672

P 23 closure

T 234 30,100 1,505,000 3.265 50.0 6,300 206,704


T 234 30,100 1,505,000 3.419 50.0 363,380 27,534

P 23 closure

T 234 30,100 1,505,000 3.419 50.0 250,400 0

P 23




04/18/2023

Case No.

B-6

B6.1

B6.2

B6.3

B6.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s


T 234 50,100 1,563,000 3.424 50.0 620,500 0

P 24

T 234 50,100 1,563,000 3.424 50.0 304,900 39,267

P 24 closure

T 234 50,100 1,563,000 3.265 50.0 10,400 346,618


T 234 50,100 1,563,000 3.424 50.0 576,300 74,223

P 24 closure

T 234 50,100 1,563,000 3.424 50.0 439,100 0

P 24




04/18/2023

Case No.

B-7

B7.1

B7.2

B7.3

B7.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s


T 232 149,200 1,873,000 3.429 49.9 1,480,000 -8,310

P 25

T 232 149,200 1,873,000 3.429 49.9 893,900 383,113

P 25 closure

T 232 149,200 1,873,000 3.354 49.9 20,200 1,072,009


T 232 149,200 1,873,000 3.429 49.9 1,099,700 471,015

P 25 closure

T 232 149,200 1,873,000 3.429 49.9 1,372,200 -2,730

P 25




04/18/2023

Case No.

B-8

B8.1

B8.2

B8.3

B8.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s


T 333 99,600 1,062,000 3.428 50.0 348,700 0

P 119

T 333 99,600 1,062,000 3.428 50.0 232,700 62,890

P 119 closure

T 333 99,600 1,062,000 3.315 50.0 5,400 439,112


T 333 99,600 1,062,000 3.428 50.0 297,100 80,294

P 119 closure

T 333 99,600 1,062,000 3.428 50.0 308,600 0

P 119




04/18/2023

Case No.

S-1

S1.1

S1.2

S1.3

S1.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s


T 334 49,900 968,000.00 3.42 50.0 246,503 -464

P 114

T 334 49,900 968,000.00 3.42 50.0 116,794 14,536

P 114

T 334 49,900 968,000 3.27 50.0 2,103 215,433


T 334 49,900 968,000.00 3.42 50.0 196,560 24,781

P 114

T 334 49,900 968,000.00 3.42 50.0 194,353 -464

P 114





04/18/2023

Case No.

S-2

S2.1

S2.2

S2.3

S2.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s

T 235 10,100 1,446,000 3.40 50.0 171,739 353

P 23

T 235 10,100 1,446,000 3.40 50.0 55,520 1,731

P 23

T 235 10,100 1,446,000 3.26 50.0 2,123 68,517


T 235 10,100 1,446,000 3.40 50.0 142,418 3,887

P 23

T 235 10,100 1,446,000 3.40 50.0 101,817 353

P 23





04/18/2023

Case No.

S-3

S3.1

S3.2

S3.3

S3.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s

T 344 30,400 1,001,000 5.71 50.0 90,895 267

P 128

T 344 30,400 1,001,000 5.71 50.0 68,693 5,538

P 128

T 344 30,400 1,001,000 5.41 50.0 1,093 139,609


T 344 30,400 1,001,000 5.71 50.0 50,220 4,120

P 128

T 344 30,400 1,001,000 5.71 50.0 78,655 267

P 128





04/18/2023

Case No.

S-4

S4.1

S4.2

S4.3

S4.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s

T 244 10,100 1,615,000 5.66 50.0 98,650 223

P 27

T 244 10,100 1,615,000 5.66 50.0 57,444 1,662

P 27

T 244 10,100 1,615,000 5.41 50.0 1,599 77,294


T 244 10,100 1,615,000 5.66 50.0 68,825 1,947

P 27

T 244 10,100 1,615,000 5.66 50.0 69,820 223

P 27





04/18/2023

Case No.

S-5

S5.1

S5.2

S5.3

S5.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s





04/18/2023

Case No.

S-6

S6.1

S6.2

S6.3

S6.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s





04/18/2023

Case No.

S-7

S7.1

S7.2

S7.3

S7.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s





04/18/2023

Case No.

S-8

S8.1

S8.2

S8.3

S8.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s





04/18/2023

Case No.

S-9

S9.1

S9.2

S9.3

S9.4


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s




04/18/2023

Case No.


Total Flow


STEAM TEMPERATURE,


TOTAL FLOW

TURBINE BACK-

PRESSURE

UNIT CAPACIT

Y

STEAM TO

VACUUM DRIVERS

STEAM TO OTHER

SYSTEMS


by volume (ppmv) in

vapor phase

Steam + Gases

Gross Generator

Output


oF, PSIAinches Hg

abs.Megawatt

s



04/18/2023

B-1

B1.1

B1.2

B1.3

B1.4

Case No.

AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES

ELECTRICITY

Kilowatts Megawatts %

MAIN CASE

GROUP 1

3,020 38.2 23.7% base case

s-st. ejector

2,730 40.5 19.1% 3-st. turbo

2,330 38.6 22.9% reboiler

3,120 39.0 21.9% biphase

eductor

2,760 39.9 20.2% hybrid 2-st

ejector/3rd

stage turbo

POWER LOSS TO

GAS REMOVAL

AUXILIARY ELECTRICITY

CW pumps, CT fans, brine

repressurization

deducting only auxiliaries at

left

Percent of "Unit Capacity"

(at left)




04/18/2023

Case No.

B-2

B2.1

B2.2

B2.3

B2.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

MAIN CASE

GROUP 2

3,030 41.7 16.6% base case

s-st. ejector

2,740 43.3 13.5% 3-st. turbo

2,510 41.9 16.2% reboiler

3,390 43.0 14.0% biphase

eductor

2,760 42.9 14.2% hybrid 2-st

ejector/3rd

stage turbo




04/18/2023

Case No.

B-3

B3.1

B3.2

B3.3

B3.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

MAIN CASE

GROUP 3

3,020 45.4 9.2% base case

s-st. ejector

2,740 46.0 7.9% 3-st. turbo

2,690 45.4 9.2% reboiler

3,520 46.5 7.0% biphase

eductor

2,760 45.9 8.1% hybrid 2-st

ejector/3rd

stage turbo




04/18/2023

Case No.

B-4

B4.1

B4.2

B4.3

B4.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

MAIN CASE

GROUP 4

5,320 40.6 18.8% base case

s-st. ejector

4,790 43.2 13.5% 3-st. turbo

4,700 43.3 13.3% reboiler

5,260 41.3 17.4% biphase

eductor

4,830 42.7 14.6% hybrid 2-st

ejector/3rd

stage turbo




04/18/2023

Case No.

B-5

B5.1

B5.2

B5.3

B5.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

MAIN CASE

GROUP 5

5,340 31.7 36.6% base case

s-st. ejector

4,780 38.8 22.5% 3-st. turbo

4,400 39.9 20.3% reboiler

4,210 32.8 34.4% biphase

eductor

4,830 36.8 26.3% hybrid 2-st

ejector/3rd

stage turbo




04/18/2023

Case No.

B-6

B6.1

B6.2

B6.3

B6.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

PLACE HOLDER

MAIN CASE

GROUP 6

5,350 24.8 50.4% base case

s-st. ejector

4,760 34.2 31.5% 3-st. turbo

4,100 36.6 26.8% reboiler

3,330 25.9 48.3% biphase

eductor

4,830 31.1 37.8% hybrid 2-st

ejector/3rd

stage turbo




04/18/2023

Case No.

B-7

B7.1

B7.2

B7.3

B7.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

PLACE HOLDER

MAIN CASE

GROUP 7

5,190 5.5 89.0% base case

s-st. ejector

4,650 11.2 77.5% 3-st. turbo

2,440 23.6 52.7% reboiler

930 7.1 85.7% biphase

eductor

4,690 8.7 82.5% hybrid 2-st

ejector/3rd

stage turbo




04/18/2023

Case No.

B-8

B8.1

B8.2

B8.3

B8.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

PLACE HOLDER

MAIN CASE

GROUP 8

3,000 30.6 38.8% base case

s-st. ejector

2,700 33.4 33.2% 3-st. turbo

1,860 31.0 37.9% reboiler

2,390 29.8 40.3% biphase

eductor

2,730 32.7 34.5% hybrid 2-st

ejector/3rd

stage turbo




04/18/2023

Case No.

S-1

S1.1

S1.2

S1.3

S1.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

PLACE HOLDER

SENSITIVITY

GROUP S-1

3,051 34.2 31.5% base case

s-st. ejector

2,726 40.5 19.0% 3-st. turbo

2,333 38.6 22.9% reboiler

2,814 35.8 28.5% biphase

eductor

2,768 37.2 25.6% hybrid 2-st

ejector/3rd

stage turboPLACE HOLDER




04/18/2023

Case No.

S-2

S2.1

S2.2

S2.3

S2.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

SENSITIVITY

GROUP S-2

5,332 38.7 22.6% base case

s-st. ejector

4,790 43.2 13.5% 3-st. turbo

4,698 43.3 13.3% reboiler

5,071 39.9 20.3% biphase

eductor

4,837 41.6 16.7% hybrid 2-st

ejector/3rd





04/18/2023

Case No.

S-3

S3.1

S3.2

S3.3

S3.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

SENSITIVITY

GROUP S-3

3,246 42.2 15.6% base case

s-st. ejector

2,922 43.4 13.3% 3-st. turbo

2,695 41.7 16.7% reboiler

3,799 43.5 13.0% biphase

eductor

2,967 43.1 13.8% hybrid 2-st

ejector/3rd





04/18/2023

Case No.

S-4

S4.1

S4.2

S4.3

S4.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

SENSITIVITY

GROUP S-4

5,950 41.0 18.0% base case

s-st. ejector

5,349 42.8 14.4% 3-st. turbo

5,251 42.8 14.4% reboiler

6,259 41.5 16.9% biphase

eductor

5,405 42.4 15.1% hybrid 2-st

ejector/3rd





04/18/2023

Case No.

S-5

S5.1

S5.2

S5.3

S5.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

PLACE HOLDER




04/18/2023

Case No.

S-6

S6.1

S6.2

S6.3

S6.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

PLACE HOLDER




04/18/2023

Case No.

S-7

S7.1

S7.2

S7.3

S7.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

PLACE HOLDER




04/18/2023

Case No.

S-8

S8.1

S8.2

S8.3

S8.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

PLACE HOLDER




04/18/2023

Case No.

S-9

S9.1

S9.2

S9.3

S9.4


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)




04/18/2023

Case No.


ELECTRICITY


POWER LOSS TO

GAS REMOVAL



repressurization


left


(at left)

Sheet 4.2 EnFigMerit


04/18/2023

ENGINEERING FIGURES OF MERIT

OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER

ppmv

MAIN CASE GROUP 1 HIGH TEMP/HIGH PRESSURE/HI GASB-1 2,291,000 T = 550 48,800 T 334 49,900

2-stage ejector P = 1177 P 114

B1.1 2,291,000 T = 550 48,800 T 334 49,9003-stage turbo P = 1177 P 114

B1.2 2,289,000 T = 550 48,800 T 334 49,900reboiler P = 1177 P 114

B1.3 2,291,000 T = 550 48,800 T 334 49,900biphase P = 1177 P 114eductor

B1.4 2,291,000 T = 550 48,800 T 334 49,900hybrid P = 1177 P 114

GROSS PLANT FEED

(combined well flow to flash)

STEAM TEMPERATURE, PRESSURE & GAS CONTENT

Case No.


T = oF

Combined Brine & Steam Gas Conc'n.

Flash Conditions

Gas Loading in Steam

lbs / hour (at 15% steam quality)

P = PSIA

parts per million by weight (ppmw) as CO2

oF, PSIA

Define a technical "figure of merit" as a ratio of net power plant productivities, comparing the respective productivity value for each alternative plant configuration to the productivity of their common "Base Case." The common bases include overall process conditions and design assumptions outlined in worksheets 2.1, 2.2, and 4.1. Define productivity as the balance of plant

generating capacity (as megawatts) remaining after deducting power losses consumed specifically by the noncondensable gas removal system and that system's dedicated share of the cooling system power demand; for the biphase eductor option, also include the power needed to repressurize flashed brine for transfer out of the system. Express this productivity as "Net Sales"

megawatts or as percent of gross plant capacity -- i.e. the "residual plant capacity." This assumes any other in-plant utility power demands are essentially constant, and are therefore considered separately from gas removal power demands.

The value of the figure of merit for the Base Case design is 1.00 by this definition. Figure of merit values greater than 1 show that an alternative technology outperforms the Base Case in proportion to the value. Figure-of-merit values less than 1 indicate the Base Case performs better than the alternative.



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA

MAIN CASE GROUP 2 HIGH TEMP/HIGH PRESSURE/MID GASB-2 2,288,000 T = 550 29,000 T 334 29,900



B2.2 2,287,000 T = 550 29,000 T 334 29,900reboiler P = 1124 P 113


B2.4 2,288,000 T = 550 29,000 T 334 29,900hybrid P = 1124 P 113

MAIN CASE GROUP 3 HIGH TEMP/HIGH PRESSURE/LOW GASB-3 2,284,000 T = 550 9,600 T 335 10,000



B3.2 2,284,000 T = 550 9,600 T 335 10,000reboiler P = 1072 P 111


B3.4 2,284,000 T = 550 9,600 T 335 10,000hybrid P = 1072 P 111



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA

MAIN CASE GROUP 4 LOW TEMP/LOW PRESSURE/LOW GASB-4 5,418,000 T = 350 6,500 T 235 10,000



B4.2 5,418,000 T = 350 6,500 T 235 10,000reboiler P = 137 P 23


B4.4 5,418,000 T = 350 6,500 T 235 10,000hybrid P = 137 P 23



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA

PLACE HOLDER PLACE HOLDER PLACE HOLDER

MAIN CASE GROUP 5 LOW TEMP/LOW PRESSURE/MID GAS

B-5 5,395,000 T = 350 19,700 T 234 30,100


B5.1 5,395,000 T = 350 19,700 T 234 30,100

3-stage turbo P = 142 P 23

B5.2 5,391,000 T = 350 19,700 T 234 30,100

reboiler P = 142 P 23

B5.3 5,395,000 T = 350 19,700 T 234 30,100

biphase P = 142 P 23

eductor

B5.4 5,395,000 T = 350 19,700 T 234 30,100

hybrid P = 142 P 23



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA


MAIN CASE GROUP 6 LOW TEMP/LOW PRESSURE/HI GAS

B-6 5,365,000 T = 350 33,400 T 234 50,100


B6.1 5,365,000 T = 350 33,400 T 234 50,100


B6.2 5,354,000 T = 350 33,400 T 234 50,100


B6.3 5,365,000 T = 350 33,400 T 234 50,100


eductor

B6.4 5,365,000 T = 350 33,400 T 234 50,100

hybrid P = 146 P 24



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA


MAIN CASE GROUP 7 LOW TEMP/LOW PRESSURE/VERY HIGH GAS

B-7 5,201,000 T = 350 108,500 T 232 149,200


B7.1 5,201,000 T = 350 108,500 T 232 149,200


B7.2 5,119,000 T = 350 108,500 T 232 149,200


B7.3 5,201,000 T = 350 108,500 T 232 149,200


eductor

B7.4 5,201,000 T = 350 108,500 T 232 149,200

hybrid P = 170 P 25



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA


MAIN CASE GROUP 8 HIGH TEMP/HIGH PRESSURE/VERY HIGH GAS

B-8 2,297,000 T = 550 99,700 T 333 99,600


B8.1 2,297,000 T = 550 99,700 T 333 99,600


B8.2 2,289,000 T = 550 99,700 T 333 99,600


B8.3 2,297,000 T = 550 99,700 T 333 99,600


eductor

B8.4 2,297,000 T = 550 99,700 T 333 99,600

hybrid P = 1316 P 119



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA


LOW EJECTOR EFFICIENCY

SENSITIVITY CASE GROUP 1 -- HIGH TEMP / HIGH GAS

S-1 2,291,000 T = 550 48,800 T 334 49,900


S1.1 2,291,000 T = 550 48,800 T 334 49,900


S1.2 2,289,000 T = 550 48,800 T 334 49,900


S1.3 2,291,000 T = 550 48,800 T 334 49,900


eductor

S1.4 2,291,000 T = 550 48,800 T 334 49,900

hybrid P = 1177 P 114



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA



SENSITIVITY CASE GROUP 2 -- LOW TEMP / LOW GAS

S-2 5,418,000 T = 350 6,500 T 235 10,100


S2.1 5,418,000 T = 350 6,500 T 235 10,100


S2.2 5,418,000 T = 350 6,500 T 235 10,100


S2.3 5,418,000 T = 350 6,500 T 235 10,100


eductor

S2.4 5,418,000 T = 350 6,500 T 235 10,100

hybrid P = 137 P 23



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA


SENSITIVITY CASE GROUP 3 -- HIGH TEMP / MID GAS

S-3 2,505,000 T = 550 28,900 T 344 30,400


S3.1 2,505,000 T = 550 28,900 T 344 30,400


S3.2 2,505,000 T = 550 28,900 T 344 30,400


S3.3 2,505,000 T = 550 28,900 T 344 30,400


eductor

S3.4 2,505,000 T = 550 28,900 T 344 30,400

hybrid P = 1124 P 128

WET BULB TEMPERATURE 80 oF



04/18/2023


ppmv

GROSS PLANT FEED



Case No.


T = oF


Flash Conditions



P = PSIA


oF, PSIA


SENSITIVITY CASE GROUP 4 -- LOW TEMP / LOW GAS

S-4 6,251,000 T = 350 6,400 T 244 10,100


S4.1 6,251,000 T = 350 6,400 T 244 10,100


S4.2 6,250,000 T = 350 6,400 T 244 10,100


S4.3 6,251,000 T = 350 6,400 T 244 10,100


eductor

S4.4 6,251,000 T = 350 6,400 T 244 10,100

hybrid P = 137 P 27




04/18/2023



MAIN CASE GROUP 1B-1

B1.1

B1.2

B1.3

B1.4

Case No.






FLASHED STEAM AND GROSS POWER NET SALES

ELECTRICITY ( A ) ( B ) ( C )

B = 1 - ( A )

lbs / hour Megawatts Megawatts % %

MAIN GROUP 1968,000 50.0 38.2 23.7% 76.3% 1.00

968,000 50.0 40.5 19.1% 80.9% 1.06

968,000 50.0 38.6 22.9% 77.1% 1.01750,000 = clean steam turbine feed

968,000 50.0 39.0 21.9% 78.1% 1.02

968,000 50.0 39.9 20.2% 79.8% 1.05

POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY

TECHNICAL FIGURE OF MERIT

TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output

Percent of Gross "Unit Capacity" ratio of alternate case

resid. capacity to "base case" resid.

capacity





RETURN



04/18/2023


Case No.


B2.1

B2.2

B2.3

B2.4


B3.1

B3.2

B3.3

B3.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN

MAIN GROUP 2932,000 50.0 41.7 16.6% 83.4% 1.00

932,000 50.0 43.3 13.5% 86.5% 1.04


932,000 50.0 43.0 14.0% 86.0% 1.03

932,000 50.0 42.9 14.2% 85.8% 1.03

MAIN GROUP 3896,000 50.0 45.4 9.2% 90.8% 1.00

896,000 50.0 46.0 7.9% 92.1% 1.01


896,000 50.0 46.5 7.0% 93.0% 1.02

896,000 50.0 45.9 8.1% 91.9% 1.01

RETURN



04/18/2023


Case No.


B4.1

B4.2

B4.3

B4.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN

MAIN GROUP 41,446,000 50.0 40.6 18.8% 81.2% 1.00

1,446,000 50.0 43.2 13.5% 86.5% 1.07

1,446,000 50.0 43.3 13.3% 86.7% 1.071,375,000 = clean steam turbine feed

1,446,000 50.0 41.3 17.4% 82.6% 1.02

1,446,000 50.0 42.7 14.6% 85.4% 1.05



04/18/2023


Case No.

MAIN CASE GROUP 5

B-5

B5.1

B5.2

B5.3

B5.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN


MAIN GROUP 5

1,505,000 50.0 31.7 36.6% 63.4% 1.00

1,505,000 50.0 38.8 22.5% 77.5% 1.22

1,505,000 50.0 39.9 20.3% 79.7% 1.26

1,291,000 = clean steam turbine feed

1,505,000 50.0 32.8 34.4% 65.6% 1.03

1,505,000 50.0 36.8 26.3% 73.7% 1.16



04/18/2023


Case No.

MAIN CASE GROUP 6

B-6

B6.1

B6.2

B6.3

B6.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN


MAIN GROUP 6

1,563,000 50.0 24.8 50.4% 49.6% 1.00

1,563,000 50.0 34.2 31.5% 68.5% 1.38

1,563,000 50.0 36.6 26.8% 73.2% 1.48


1,563,000 50.0 25.9 48.3% 51.7% 1.04

1,563,000 50.0 31.1 37.8% 62.2% 1.25



04/18/2023


Case No.

MAIN CASE GROUP 7

B-7

B7.1

B7.2

B7.3

B7.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN


MAIN GROUP 7

1,873,000 49.9 5.5 89.0% 11.0% 1.00

1,873,000 49.9 11.2 77.5% 22.5% 2.04

1,873,000 49.9 23.6 52.7% 47.3% 4.28

751,000 = clean steam turbine feed

1,873,000 49.9 7.1 85.7% 14.3% 1.29

1,873,000 49.9 8.7 82.5% 17.5% 1.59



04/18/2023


Case No.

MAIN CASE GROUP 8

B-8

B8.1

B8.2

B8.3

B8.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN


MAIN GROUP 8

1,062,000 50.0 30.6 38.8% 61.2% 1.00

1,062,000 50.0 33.4 33.2% 66.8% 1.09

1,062,000 50.0 31.0 37.9% 62.1% 1.01


1,062,000 50.0 29.8 40.3% 59.7% 0.98

1,062,000 50.0 32.7 34.5% 65.5% 1.07



04/18/2023


Case No.

S-1

S1.1

S1.2

S1.3

S1.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN



SENGROUP 1

968,000 50.0 34.2 31.5% 68.5% 1.00

968,000 50.0 40.5 19.0% 81.0% 1.18

968,000 50.0 38.6 22.9% 77.1% 1.13


968,000 50.0 35.8 28.5% 71.5% 1.04

968,000 50.0 37.2 25.6% 74.4% 1.09



04/18/2023


Case No.

S-2

S2.1

S2.2

S2.3

S2.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN



SENGROUP 2

1,446,000 50.0 38.7 22.6% 77.4% 1.00

1,446,000 50.0 43.2 13.5% 86.5% 1.12

1,446,000 50.0 43.3 13.3% 86.7% 1.12


1,446,000 50.0 39.9 20.3% 79.7% 1.03

1,446,000 50.0 41.6 16.7% 83.3% 1.08



04/18/2023


Case No.

S-3

S3.1

S3.2

S3.3

S3.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN


SENGROUP 3

1,001,000 50.0 42.2 15.6% 84.4% 1.00

1,001,000 50.0 43.4 13.3% 86.7% 1.03

1,001,000 50.0 41.7 16.7% 83.3% 0.99


1,001,000 50.0 43.5 13.0% 87.0% 1.03

1,001,000 50.0 43.1 13.8% 86.2% 1.02




04/18/2023


Case No.

S-4

S4.1

S4.2

S4.3

S4.4



B = 1 - ( A )


POWER LOSS TO GAS

REMOVAL

RESIDUAL PLANT

CAPACITY


TOTAL FLOW

UNIT CAPACITY

Steam + Gases

Gross Generator

Output



capacity

RETURN


SENGROUP 4

1,615,000 50.0 41.0 18.0% 82.0% 1.00

1,615,000 50.0 42.8 14.4% 85.6% 1.04

1,615,000 50.0 42.8 14.4% 85.6% 1.04


1,615,000 50.0 41.5 16.9% 83.1% 1.01

1,615,000 50.0 42.4 15.1% 84.9% 1.04


Sheet 4.3 $ FigMerit


04/18/2023

ECONOMIC FIGURE OF MERIT


TOTAL FLOW

Configuration

P = PSIA ppmv lbs / hour

60

MAIN CASE GROUP 1

HIGH TEMPERATURE/PRESSURE AND HIGH GAS CONTENTB-1 BASE CASE 2,291,000 T = 550 48,800 T 334 49,900 968,000

2-stage ejectors P = 1177 P 114

B1.1 ALTERNATIVE A 2,291,000 T = 550 48,800 T 334 49,900 968,000 3-stage turbo- P = 1177 P 114compressor

B1.2 ALTERNATIVE B 2,289,000 T = 550 48,800 T 334 49,900 968,000 reboiler P = 1177 P 114 750,000

B1.3 ALTERNATIVE C 2,291,000 T = 550 48,800 T 334 49,900 968,000 biphase eductor P = 1177 P 114

B1.4 ALTERNATIVE D 2,291,000 T = 550 48,800 T 334 49,900 968,000 hybrid turbo- P = 1177 P 114compressor

MAIN CASE GROUP 2

HIGH TEMPERATURE/PRESSURE AND MID GAS CONTENTB-2 BASE CASE 2,288,000 T 550 29,000 T 334 29,900 932,000

2-stage ejectors P 1,124 P 113

B2.1 ALTERNATIVE A 2,288,000 T 550 29,000 T 334 29,900 932,000 3-stage turbo- P 1,124 P 113

GROSS PLANT FEED (combined well flows entering flash to produce steam for a 50 MW turbine/generator)

STEAM PRESSURE AND TEMPERATURE

Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases


parts per million by

weight (ppmw) as

CO2

oF, PSIA

Define an economic "figure of merit" that allocates dollars as credit for savings in parasitic power losses. Evaluate the credits by calculating the equivalent electrical generating output of the steam and electricity used to run the noncondensable gas removal systems. Assign the "found" generating power a unit value (see worksheet tab 2.2 -- "Bases&Input").

Then calculate the figure of merit value as the payback period for the cost of investing in conversion to an alternative gas removal system: Divide the investment cost by the "found power" revenue value ($ per year), yielding a value of years to recover the alternate technology investment costs. The shorter the payback period, the better the option is as a recoverable cost.



04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA

compressorB2.2 ALTERNATIVE B 2,287,000 T 550 29,000 T 334 29,900 932,000

reboiler P 1,124 P 113 803,000

B2.3 ALTERNATIVE C 2,288,000 T 550 29,000 T 334 29,900 932,000 biphase eductor P 1,124 P 113

B2.4 ALTERNATIVE D 2,288,000 T 550 29,000 T 334 29,900 932,000 hybrid turbo- P 1,124 P 113compressor



04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA

MAIN CASE GROUP 3

HIGH TEMPERATURE/PRESSURE AND LOW GAS CONTENTB-3 BASE CASE 2,284,000 T = 550 9,600 T 335 10,000 896,000


B3.1 ALTERNATIVE A 2,284,000 T = 550 9,600 T 335 10,000 896,000 3-stage turbo- P = 1072 P 111compressor

B3.2 ALTERNATIVE B 2,284,000 T = 550 9,600 T 335 10,000 896,000 reboiler P = 1072 P 111 853,000

B3.3 ALTERNATIVE C 2,284,000 T = 550 9,600 T 335 10,000 896,000 biphase eductor P = 1072 P 111

B3.4 ALTERNATIVE D 2,284,000 T = 550 9,600 T 335 10,000 896,000 hybrid turbo- P = 1072 P 111compressor

MAIN CASE GROUP 4

LOW TEMPERATURE/PRESSURE AND LOW GAS CONTENTB-4 BASE CASE 5,418,000 T 350 6,500 T 235 10,000 1,446,000

2-stage ejectors P 137 P 23

B4.1 ALTERNATIVE A 5,418,000 T 350 6,500 T 235 10,000 1,446,000 3-stage turbo- P 137 P 23compressor

B4.2 ALTERNATIVE B 5,418,000 T 350 6,500 T 235 10,000 1,446,000 reboiler P 137 P 23 1,375,000

B4.3 ALTERNATIVE C 5,418,000 T 350 6,500 T 235 10,000 1,446,000 biphase eductor P 137 P 23

B4.4 ALTERNATIVE D 5,418,000 T 350 6,500 T 235 10,000 1,446,000 hybrid turbo- P 137 P 23compressor




04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA

MAIN CASE GROUP 5

LOW TEMPERATURE/PRESSURE AND MID GAS CONTENT

B-5 BASE CASE 5,395,000 T = 350 19,700 T 234 30,100 1,505,000


B5.1 ALTERNATIVE A 5,395,000 T = 350 19,700 T 234 30,100 1,505,000

3-stage turbo- P = 142 P 23

compressor

B5.2 ALTERNATIVE B 5,391,000 T = 350 19,700 T 234 30,100 1,505,000

reboiler P = 142 P 23 1,291,000

B5.3 ALTERNATIVE C 5,395,000 T = 350 19,700 T 234 30,100 1,505,000

biphase eductor P = 142 P 23

B5.4 ALTERNATIVE D 5,395,000 T = 350 19,700 T 234 30,100 1,505,000

hybrid turbo- P = 142 P 23

compressorPLACE HOLDER PLACE HOLDER PLACE HOLDER

MAIN CASE GROUP 6

LOW TEMPERATURE/PRESSURE AND HIGH GAS CONTENT

B-6 BASE CASE 5,365,000 T 350 33,400 T 234 50,100 1,563,000


B6.1 ALTERNATIVE A 5,365,000 T 350 33,400 T 234 50,100 1,563,000

3-stage turbo- P 146 P 24

compressor

B6.2 ALTERNATIVE B 5,354,000 T 350 33,400 T 234 50,100 1,563,000

reboiler P 146 P 24 1,203,000



04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA

B6.3 ALTERNATIVE C 5,365,000 T 350 33,400 T 234 50,100 1,563,000

biphase eductor P 146 P 24

B6.4 ALTERNATIVE D 5,365,000 T 350 33,400 T 234 50,100 1,563,000

hybrid turbo- P 146 P 24




04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA

MAIN CASE GROUP 7

LOW TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT

B-7 BASE CASE 5,201,000 T = 350 108,500 T 232 149,200 1,873,000


B7.1 ALTERNATIVE A 5,201,000 T = 350 108,500 T 232 149,200 1,873,000

3-stage turbo- P = 170 P 25

compressor

B7.2 ALTERNATIVE B 5,119,000 T = 350 108,500 T 232 149,200 1,873,000

reboiler P = 170 P 25 751,000

B7.3 ALTERNATIVE C 5,201,000 T = 350 108,500 T 232 149,200 1,873,000

biphase eductor P = 170 P 25

B7.4 ALTERNATIVE D 5,201,000 T = 350 108,500 T 232 149,200 1,873,000

hybrid turbo- P = 170 P 25


MAIN CASE GROUP 8

HIGH TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT

B-8 BASE CASE 2,297,000 T 550 99,700 T 333 99,600 1,062,000


B8.1 ALTERNATIVE A 2,297,000 T 550 99,700 T 333 99,600 1,062,000

3-stage turbo- P 1,316 P 119

compressor

B8.2 ALTERNATIVE B 2,289,000 T 550 99,700 T 333 99,600 1,062,000

reboiler P 1,316 P 119 614,000

B8.3 ALTERNATIVE C 2,297,000 T 550 99,700 T 333 99,600 1,062,000

biphase eductor P 1,316 P 119



04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA

B8.4 ALTERNATIVE D 2,297,000 T 550 99,700 T 333 99,600 1,062,000

hybrid turbo- P 1,316 P 119

compressor




04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA

SENSITIVITY CASE GROUP S - 1 LOW STEAM JET EJECTOR EFFICIENCY

HIGH TEMPERATURE / HIGH GAS CONTENT

S-1 BASE CASE 2,291,000 T 550 48,800 T 334 49,900 968,000


S1.1 ALTERNATIVE A 2,291,000 T 550 48,800 T 334 49,900 968,000


compressor

S1.2 ALTERNATIVE B 2,289,000 T 550 48,800 T 334 49,900 968,000

reboiler P 1,177 P 114 750,000

S1.3 ALTERNATIVE C 2,291,000 T 550 48,800 T 334 49,900 968,000


S1.4 ALTERNATIVE D 2,291,000 T 550 48,800 T 334 49,900 968,000



SENSITIVITY CASE GROUP S - 2 LOW STEAM JET EJECTOR EFFICIENCY

LOW TEMPERATURE / LOW GAS CONTENT

S-2 BASE CASE 5,418,000 T 350 6,500 T 235 10,100 1,446,000


S2.1 ALTERNATIVE A 5,418,000 T 350 6,500 T 235 10,100 1,446,000


compressor

S2.2 ALTERNATIVE B 5,418,000 T 350 6,500 T 235 10,100 1,446,000

reboiler P 137 P 23 1,375,000

S2.3 ALTERNATIVE C 5,418,000 T 350 6,500 T 235 10,100 1,446,000



04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA


S2.4 ALTERNATIVE D 5,418,000 T 350 6,500 T 235 10,100 1,446,000





04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA

SENSITIVITY CASE GROUP S - 3

HIGH TEMPERATURE / MID GAS CONTENT

S-3 BASE CASE 2,505,000 T 550 28,900 T 344 30,400 1,001,000




compressor


reboiler P 1,124 P 128 860,000







LOW TEMPERATURE / LOW GAS CONTENT

S-4 BASE CASE 6,251,000 T 350 6,400 T 244 10,100 1,615,000




compressor


reboiler P 137 P 27 1,536,000




80 oF WET BULB TEMPERATURE




04/18/2023


TOTAL FLOW

Configuration




Case No.

Combined Brine &

Steam FlowT = oF

Combined Brine &

Steam Gas Conc'n.

Flash Conditio

ns

Gas Content

Steam + Gases



weight (ppmw) as

CO2

oF, PSIA


compressor



04/18/2023


FLASHED STEAM AND GROSS POWER

ELECTRICITY ( A ) ( B )

B = 1 - ( A )

Megawatts Megawatts % $ $ / year

Use an annual on-line "streamfactor" of :

Annual ops. hours=Recovered power valued at :

( $ / kWh ) =

MAIN CASE GROUP 150.0 38.2 23.7% 76.3% N/A $ 86,900 N/A

50.0 40.5 19.1% 80.9% $ 4,800,000 $ 240,000 18,050,000

50.0 38.6 22.9% 77.1% $ 5,177,000 $ 259,000 3,020,000 = clean steam turbine feed

50.0 39.0 21.9% 78.1% $ 2,228,000 $ 111,000 6,890,000

50.0 39.9 20.2% 79.8% $ 1,200,000 $ 60,000 13,660,000


50.0 43.3 13.5% 86.5% $ 2,400,000 $ 120,000 12,600,000

NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL

NET PLANT PRODUCTIVITY AFTER "GAS

LOSS"

COSTS OF DESIGN ALTERNATIVES

VALUE OF UNEXPENDED PARASITIC POWER AS A

SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M

Net Unexpended Power Available

for SaleGross Generator

Output

Percent of gross "Unit Capacity"

Kilowatt-hours per year





04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output




50.0 43.0 14.0% 86.0% $ 2,262,000 $ 113,000 10,300,000

50.0 42.9 14.2% 85.8% $ 600,000 $ 30,000 9,500,000



04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output




50.0 46.0 7.9% 92.1% $ 1,740,000 $ 87,000 5,200,000

50.0 45.4 9.2% 90.8% $ 5,593,000 $ 280,000 200,000 = clean steam turbine feed

50.0 46.5 7.0% 93.0% $ 2,119,000 $ 106,000 8,700,000

50.0 45.9 8.1% 91.9% $ 300,000 $ 15,000 4,500,000


50.0 43.2 13.5% 86.5% $ 2,040,000 $ 102,000 20,800,000


50.0 41.3 17.4% 82.6% $ 4,313,000 $ 216,000 5,600,000

50.0 42.7 14.6% 85.4% $ 600,000 $ 30,000 16,500,000




04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output



MAIN CASE GROUP 5

50.0 31.7 36.6% 63.4% N/A $ 83,700 N/A

50.0 38.8 22.5% 77.5% $ 4,800,000 $ 240,000 55,700,000

50.0 39.9 20.3% 79.7% $ 7,522,000 $ 376,000 64,200,000

= clean steam turbine feed

50.0 32.8 34.4% 65.6% $ 4,259,000 $ 213,000 8,600,000

50.0 36.8 26.3% 73.7% $ 1,200,000 $ 60,000 40,500,000


MAIN CASE GROUP 6

50.0 24.8 50.4% 49.6% N/A $ 116,200 N/A

50.0 34.2 31.5% 68.5% $ 9,600,000 $ 480,000 74,300,000

50.0 36.6 26.8% 73.2% $ 7,210,000 $ 361,000 93,000,000




04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output



50.0 25.9 48.3% 51.7% $ 4,200,000 $ 210,000 8,400,000

50.0 31.1 37.8% 62.2% $ 2,400,000 $ 120,000 49,800,000




04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output



MAIN CASE GROUP 7

49.9 5.5 89.0% 11.0% N/A $ 249,200 N/A

49.9 11.2 77.5% 22.5% $ 34,680,000 $ 1,734,000 45,200,000

49.9 23.6 52.7% 47.3% $ 5,434,000 $ 272,000 142,700,000


49.9 7.1 85.7% 14.3% $ 3,877,000 $ 194,000 12,800,000

49.9 8.7 82.5% 17.5% $ 8,400,000 $ 420,000 25,400,000


MAIN CASE GROUP 8

50.0 30.6 38.8% 61.2% N/A $ 139,100 N/A

50.0 33.4 33.2% 66.8% $ 12,360,000 $ 618,000 22,100,000

50.0 31.0 37.9% 62.1% $ 4,592,000 $ 230,000 3,600,000


50.0 29.8 40.3% 59.7% $ 2,137,000 $ 107,000 -5,800,000



04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output



50.0 32.7 34.5% 65.5% $ 3,000,000 $ 150,000 17,000,000




04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output



LOW STEAM JET EJECTOR EFFICIENCY LOW EJECTOR EFFICIENCY


50.0 34.2 31.5% 68.5% N/A $ 86,900 N/A

50.0 40.5 19.0% 81.0% $ 4,800,000 $ 240,000 49,300,000

50.0 38.6 22.9% 77.1% $ 5,177,000 $ 259,000 34,000,000


50.0 35.8 28.5% 71.5% $ 2,228,000 $ 111,000 11,900,000

50.0 37.2 25.6% 74.4% $ 1,200,000 $ 60,000 23,500,000


LOW STEAM JET EJECTOR EFFICIENCY LOW EJECTOR EFFICIENCY


50.0 38.7 22.6% 77.4% N/A $ 42,400 N/A

50.0 43.2 13.5% 86.5% $ 2,040,000 $ 102,000 35,600,000

50.0 43.3 13.3% 86.7% $ 7,812,000 $ 391,000 36,400,000


50.0 39.9 20.3% 79.7% $ 4,313,000 $ 216,000 9,100,000



04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output



50.0 41.6 16.7% 83.3% $ 600,000 $ 30,000 23,000,000




04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output




50.0 42.2 15.6% 84.4% N/A $ 65,900 N/A

50.0 43.4 13.3% 86.7% $ 3,120,000 $ 156,000 9,200,000

50.0 41.7 16.7% 83.3% $ 5,620,000 $ 281,000 -4,500,000


50.0 43.5 13.0% 87.0% $ 2,407,000 $ 120,000 10,100,000

50.0 43.1 13.8% 86.2% $ 600,000 $ 30,000 7,000,000



50.0 41.0 18.0% 82.0% N/A $ 45,300 N/A

50.0 42.8 14.4% 85.6% $ 2,400,000 $ 120,000 14,400,000

50.0 42.8 14.4% 85.6% $ 8,348,000 $ 417,000 14,100,000


50.0 41.5 16.9% 83.1% $ 4,732,000 $ 237,000 4,400,000

50.0 42.4 15.1% 84.9% $ 600,000 $ 30,000 11,300,000

F WET BULB TEMPERATURE 80 oF WET BULB TEMPERATURE

F WET BULB TEMPERATURE 80 oF WET BULB TEMPERATURE



04/18/2023



B = 1 - ( A )


NET SALES POWER

AVAILABLE

POWER LOSS TO

GAS REMOVAL


LOSS"



SALABLE PRODUCT

UNIT CAPACITY

CAPITAL (installed)

ANNUAL O & M



Output





04/18/2023


$ / year

Use an annual on-line "stream90%7884

Recovered power valued at : $ 0.040

MAIN CASE GROUP 1N/A N/A

$ 722,000 8.4

$ 120,800 -100.9

$ 275,600 13.5

$ 546,400 2.1


$ 504,000 5.4


SALABLE PRODUCT

FIGURE OF

MERIT

Sales value of unexpended

power

PAYOUT PERIOD

"simple payback" (years)



RETURN



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN

$ 68,000 -38.7

$ 412,000 7.6

$ 380,000 1.5



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN


$ 208,000 11.4

$ 8,000 -23.3

$ 348,000 7.7

$ 180,000 1.5


$ 832,000 2.6

$ 860,000 15.3

$ 224,000 539.1

$ 660,000 0.9

PLACE HOLDER



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN

MAIN CASE GROUP 5

N/A N/A

$ 2,228,000 2.3

$ 2,568,000 3.3

$ 344,000 32.5

$ 1,620,000 0.7

PLACE HOLDER

MAIN CASE GROUP 6

N/A N/A

$ 2,972,000 3.7

$ 3,720,000 2.1



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN

$ 336,000 33.3

$ 1,992,000 1.2

PLACE HOLDER



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN

MAIN CASE GROUP 7

N/A N/A

$ 1,808,000 107.3

$ 5,708,000 1.0

$ 512,000 6.8

$ 1,016,000 9.9

PLACE HOLDER

MAIN CASE GROUP 8

N/A N/A

$ 884,000 30.5

$ 144,000 86.5

$ (232,000) -6.3



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN

$ 680,000 4.5

PLACE HOLDER



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN



N/A N/A

$ 1,972,000 2.6

$ 1,360,000 4.4

$ 476,000 6.1

$ 940,000 1.2

PLACE HOLDER



N/A N/A

$ 1,424,000 1.5

$ 1,456,000 7.1

$ 364,000 29.1



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN

$ 920,000 0.6

PLACE HOLDER



04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN


N/A N/A

$ 368,000 11.2

$ (180,000) -14.2

$ 404,000 8.5

$ 280,000 1.9

PLACE HOLDER


N/A N/A

$ 576,000 4.8

$ 564,000 43.4

$ 176,000 -77.6

$ 452,000 1.3





04/18/2023

$ / year


SALABLE PRODUCT

FIGURE OF

MERIT


power

PAYOUT PERIOD


RETURN

4.3a Alt $ FigMerit


Page 4.3a.268 10:22:2504/18/2023

ECONOMIC FIGURE OF MERIT ---- NET PRESENT VALUES


Case No. Configuration

P = PSIA ppmv

MAIN CASE GROUP 1HIGH TEMPERATURE/PRESSURE AND HIGH GAS CONTENT

B-1 BASE CASE 2,291,000 T = 550 48,800 T 334 49,900 2-stage ejectors P = 1177 P 114

B1.1 ALTERNATIVE A 2,291,000 T = 550 48,800 T 334 49,900 3-stage turbo- P = 1177 P 114compressor

B1.2 ALTERNATIVE B 2,289,000 T = 550 48,800 T 334 49,900 reboiler P = 1177 P 114

B1.3 ALTERNATIVE C 2,291,000 T = 550 48,800 T 334 49,900 biphase eductor P = 1177 P 114

B1.4 ALTERNATIVE D 2,291,000 T = 550 48,800 T 334 49,900 hybrid turbo- P = 1177 P 114compressor

MAIN CASE GROUP 2HIGH TEMPERATURE/PRESSURE AND MID GAS CONTENT

B-2 BASE CASE 2,288,000 T 550 29,000 T 334 29,900 2-stage ejectors P 1,124 P 113

B2.1 ALTERNATIVE A 2,288,000 T 550 29,000 T 334 29,900 3-stage turbo- P 1,124 P 113compressor

B2.2 ALTERNATIVE B 2,287,000 T 550 29,000 T 334 29,900 reboiler P 1,124 P 113

B2.3 ALTERNATIVE C 2,288,000 T 550 29,000 T 334 29,900




T = oF Combined

Brine & Steam Gas Conc'n.

Flash Condition

s

Gas Content


quality)


weight (ppmw) as CO2

oF, PSIA


Then calculate the figure of merit value as the net present value for the cost of investing in conversion to an alternative gas removal system. See worksheet 4.3b, Present Values, for the detailed calculation of net present value cash flows. Input defining the financial variables is made in worksheet 2.2, Bases&Input.

4.3a Alt $ FigMerit


Page 4.3a.269 10:22:2504/18/2023



P = PSIA ppmv




T = oF Combined


Flash Condition

s

Gas Content


quality)



oF, PSIA


B2.4 ALTERNATIVE D 2,288,000 T 550 29,000 T 334 29,900 hybrid turbo- P 1,124 P 113compressor

4.3a Alt $ FigMerit


Page 4.3a.270 10:22:2504/18/2023



P = PSIA ppmv




T = oF Combined


Flash Condition

s

Gas Content


quality)



oF, PSIA

MAIN CASE GROUP 3HIGH TEMPERATURE/PRESSURE AND LOW GAS CONTENT






MAIN CASE GROUP 4LOW TEMPERATURE/PRESSURE AND LOW GAS CONTENT

B-4 BASE CASE 5,418,000 T 350 6,500 T 235 10,000 2-stage ejectors P 137 P 23

B4.1 ALTERNATIVE A 5,418,000 T 350 6,500 T 235 10,000 3-stage turbo- P 137 P 23compressor

B4.2 ALTERNATIVE B 5,418,000 T 350 6,500 T 235 10,000 reboiler P 137 P 23

B4.3 ALTERNATIVE C 5,418,000 T 350 6,500 T 235 10,000 biphase eductor P 137 P 23

B4.4 ALTERNATIVE D 5,418,000 T 350 6,500 T 235 10,000 hybrid turbo- P 137 P 23compressor


4.3a Alt $ FigMerit


Page 4.3a.271 10:22:2504/18/2023



P = PSIA ppmv




T = oF Combined


Flash Condition

s

Gas Content


quality)



oF, PSIA

MAIN CASE GROUP 5LOW TEMPERATURE/PRESSURE AND MID GAS CONTENT







MAIN CASE GROUP 6LOW TEMPERATURE/PRESSURE AND HIGH GAS CONTENT

B-6 BASE CASE 5,365,000 T 350 33,400 T 234 50,100 2-stage ejectors P 146 P 24

B6.1 ALTERNATIVE A 5,365,000 T 350 33,400 T 234 50,100 3-stage turbo- P 146 P 24compressor

B6.2 ALTERNATIVE B 5,354,000 T 350 33,400 T 234 50,100 reboiler P 146 P 24

B6.3 ALTERNATIVE C 5,365,000 T 350 33,400 T 234 50,100 biphase eductor P 146 P 24

B6.4 ALTERNATIVE D 5,365,000 T 350 33,400 T 234 50,100 hybrid turbo- P 146 P 24compressor


4.3a Alt $ FigMerit


Page 4.3a.272 10:22:2504/18/2023



P = PSIA ppmv




T = oF Combined


Flash Condition

s

Gas Content


quality)



oF, PSIA

MAIN CASE GROUP 7LOW TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT







MAIN CASE GROUP 8HIGH TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT

B-8 BASE CASE 2,297,000 T 550 99,700 T 333 99,600 2-stage ejectors P 1,316 P 119

B8.1 ALTERNATIVE A 2,297,000 T 550 99,700 T 333 99,600 3-stage turbo- P 1,316 P 119compressor

B8.2 ALTERNATIVE B 2,289,000 T 550 99,700 T 333 99,600 reboiler P 1,316 P 119

B8.3 ALTERNATIVE C 2,297,000 T 550 99,700 T 333 99,600 biphase eductor P 1,316 P 119

B8.4 ALTERNATIVE D 2,297,000 T 550 99,700 T 333 99,600 hybrid turbo- P 1,316 P 119compressor


4.3a Alt $ FigMerit


Page 4.3a.273 10:22:2504/18/2023



P = PSIA ppmv




T = oF Combined


Flash Condition

s

Gas Content


quality)



oF, PSIA

SENSITIVITY CASE GROUP S - 1 LOW STEAM JET EJECTOR EFFICIENCYHIGH TEMPERATURE / HIGH GAS CONTENT

S-1 BASE CASE 2,291,000 T 550 48,800 T 334 49,900 2-stage ejectors P 1,177 P 114

S1.1 ALTERNATIVE A 2,291,000 T 550 48,800 T 334 49,900 3-stage turbo- P 1,177 P 114compressor

S1.2 ALTERNATIVE B 2,289,000 T 550 48,800 T 334 49,900 reboiler P 1,177 P 114

S1.3 ALTERNATIVE C 2,291,000 T 550 48,800 T 334 49,900 biphase eductor P 1,177 P 114

S1.4 ALTERNATIVE D 2,291,000 T 550 48,800 T 334 49,900 hybrid turbo- P 1,177 P 114compressor


SENSITIVITY CASE GROUP S - 2 LOW STEAM JET EJECTOR EFFICIENCYLOW TEMPERATURE / LOW GAS CONTENT

S-2 BASE CASE 5,418,000 T 350 6,500 T 235 10,100 2-stage ejectors P 137 P 23

S2.1 ALTERNATIVE A 5,418,000 T 350 6,500 T 235 10,100 3-stage turbo- P 137 P 23compressor

S2.2 ALTERNATIVE B 5,418,000 T 350 6,500 T 235 10,100 reboiler P 137 P 23

S2.3 ALTERNATIVE C 5,418,000 T 350 6,500 T 235 10,100 biphase eductor P 137 P 23

S2.4 ALTERNATIVE D 5,418,000 T 350 6,500 T 235 10,100 hybrid turbo- P 137 P 23compressor


4.3a Alt $ FigMerit


Page 4.3a.274 10:22:2504/18/2023



P = PSIA ppmv




T = oF Combined


Flash Condition

s

Gas Content


quality)



oF, PSIA

SENSITIVITY CASE GROUP S - 3HIGH TEMPERATURE / MID GAS CONTENT

S-3 BASE CASE 2,505,000 T 550 28,900 T 344 30,400 2-stage ejectors P 1,124 P 128

S3.1 ALTERNATIVE A 2,505,000 T 550 28,900 T 344 30,400 3-stage turbo- P 1,124 P 128compressor

S3.2 ALTERNATIVE B 2,505,000 T 550 28,900 T 344 30,400 reboiler P 1,124 P 128

S3.3 ALTERNATIVE C 2,505,000 T 550 28,900 T 344 30,400 biphase eductor P 1,124 P 128

S3.4 ALTERNATIVE D 2,505,000 T 550 28,900 T 344 30,400 hybrid turbo- P 1,124 P 128compressor


SENSITIVITY CASE GROUP S - 4LOW TEMPERATURE / LOW GAS CONTENT

S-4 BASE CASE 6,251,000 T 350 6,400 T 244 10,100 2-stage ejectors P 137 P 27

S4.1 ALTERNATIVE A 6,251,000 T 350 6,400 T 244 10,100 3-stage turbo- P 137 P 27compressor

S4.2 ALTERNATIVE B 6,250,000 T 350 6,400 T 244 10,100 reboiler P 137 P 27

S4.3 ALTERNATIVE C 6,251,000 T 350 6,400 T 244 10,100 biphase eductor P 137 P 27

S4.4 ALTERNATIVE D 6,251,000 T 350 6,400 T 244 10,100 hybrid turbo- P 137 P 27compressor



4.3a Alt $ FigMerit


Page 4.3a.275 10:22:2504/18/2023



TOTAL FLOW ELECTRICITY ( A ) ( B )

ANNUAL O & M

B = 1 - ( A )

lbs / hour Megawatts Megawatts % $ $ / year

Annual ops. hours=

968,000 50.0 38.2 23.7% 76.3% N/A $ 86,900

968,000 50.0 40.5 19.1% 80.9% $ 4,800,000 $ 240,000

968,000 50.0 38.6 22.9% 77.1% $ 5,177,000 $ 259,000 750,000 = clean steam turbine feed

968,000 50.0 39.0 21.9% 78.1% $ 2,228,000 $ 111,000

968,000 50.0 39.9 20.2% 79.8% $ 1,200,000 $ 60,000

932,000 50.0 41.7 16.6% 83.4% N/A $ 62,500

932,000 50.0 43.3 13.5% 86.5% $ 2,400,000 $ 120,000


932,000 50.0 43.0 14.0% 86.0% $ 2,262,000 $ 113,000

NET SALES POWER

AVAILABLE

POWER LOSS

TO GAS REMOV

AL

NET PLANT PRODUCTIVITY AFTER

"GAS LOSS"


UNIT CAPACIT

YCAPITAL (installed)Steam +

Gases

Gross Generator

Output

Percent of gross

"Unit Capacity"



4.3a Alt $ FigMerit


Page 4.3a.276 10:22:2504/18/2023



ANNUAL O & M

B = 1 - ( A )


Annual ops. hours=

NET SALES POWER

AVAILABLE

POWER LOSS

TO GAS REMOV

AL


"GAS LOSS"


UNIT CAPACIT


Gases

Gross Generator

Output

Percent of gross

"Unit Capacity"

932,000 50.0 42.9 14.2% 85.8% $ 600,000 $ 30,000

4.3a Alt $ FigMerit


Page 4.3a.277 10:22:2504/18/2023



ANNUAL O & M

B = 1 - ( A )


Annual ops. hours=

NET SALES POWER

AVAILABLE

POWER LOSS

TO GAS REMOV

AL


"GAS LOSS"


UNIT CAPACIT


Gases

Gross Generator

Output

Percent of gross

"Unit Capacity"

896,000 50.0 45.4 9.2% 90.8% N/A $ 31,600

896,000 50.0 46.0 7.9% 92.1% $ 1,740,000 $ 87,000


896,000 50.0 46.5 7.0% 93.0% $ 2,119,000 $ 106,000

896,000 50.0 45.9 8.1% 91.9% $ 300,000 $ 15,000

1,446,000 50.0 40.6 18.8% 81.2% N/A $ 42,200

1,446,000 50.0 43.2 13.5% 86.5% $ 2,040,000 $ 102,000

1,446,000 50.0 43.3 13.3% 86.7% $ 7,812,000 $ 391,000 1,375,000 = clean steam turbine feed

1,446,000 50.0 41.3 17.4% 82.6% $ 4,313,000 $ 216,000

1,446,000 50.0 42.7 14.6% 85.4% $ 600,000 $ 30,000


4.3a Alt $ FigMerit


Page 4.3a.278 10:22:2504/18/2023



ANNUAL O & M

B = 1 - ( A )


Annual ops. hours=

NET SALES POWER

AVAILABLE

POWER LOSS

TO GAS REMOV

AL


"GAS LOSS"


UNIT CAPACIT


Gases

Gross Generator

Output

Percent of gross

"Unit Capacity"

1,505,000 50.0 31.7 36.6% 63.4% N/A $ 83,700

1,505,000 50.0 38.8 22.5% 77.5% $ 4,800,000 $ 240,000


1,505,000 50.0 32.8 34.4% 65.6% $ 4,259,000 $ 213,000

1,505,000 50.0 36.8 26.3% 73.7% $ 1,200,000 $ 60,000


1,563,000 50.0 24.8 50.4% 49.6% N/A $ 116,200

1,563,000 50.0 34.2 31.5% 68.5% $ 9,600,000 $ 480,000


1,563,000 50.0 25.9 48.3% 51.7% $ 4,200,000 $ 210,000

1,563,000 50.0 31.1 37.8% 62.2% $ 2,400,000 $ 120,000


4.3a Alt $ FigMerit


Page 4.3a.279 10:22:2504/18/2023



ANNUAL O & M

B = 1 - ( A )


Annual ops. hours=

NET SALES POWER

AVAILABLE

POWER LOSS

TO GAS REMOV

AL


"GAS LOSS"


UNIT CAPACIT


Gases

Gross Generator

Output

Percent of gross

"Unit Capacity"

1,873,000 49.9 5.5 89.0% 11.0% N/A $ 249,200

1,873,000 49.9 11.2 77.5% 22.5% $ 34,680,000 $ 1,734,000

1,873,000 49.9 23.6 52.7% 47.3% $ 5,434,000 $ 272,000 751,000 = clean steam turbine feed

1,873,000 49.9 7.1 85.7% 14.3% $ 3,877,000 $ 194,000

1,873,000 49.9 8.7 82.5% 17.5% $ 8,400,000 $ 420,000


1,062,000 50.0 30.6 38.8% 61.2% N/A $ 139,100

1,062,000 50.0 33.4 33.2% 66.8% $ 12,360,000 $ 618,000


1,062,000 50.0 29.8 40.3% 59.7% $ 2,137,000 $ 107,000

1,062,000 50.0 32.7 34.5% 65.5% $ 3,000,000 $ 150,000


4.3a Alt $ FigMerit


Page 4.3a.280 10:22:2504/18/2023



ANNUAL O & M

B = 1 - ( A )


Annual ops. hours=

NET SALES POWER

AVAILABLE

POWER LOSS

TO GAS REMOV

AL


"GAS LOSS"


UNIT CAPACIT


Gases

Gross Generator

Output

Percent of gross

"Unit Capacity"

LOW STEAM JET EJECTOR EFFICIENCY

968,000 50.0 34.2 31.5% 68.5% N/A $ 86,900

968,000 50.0 40.5 19.0% 81.0% $ 4,800,000 $ 240,000


968,000 50.0 35.8 28.5% 71.5% $ 2,228,000 $ 111,000

968,000 50.0 37.2 25.6% 74.4% $ 1,200,000 $ 60,000


LOW STEAM JET EJECTOR EFFICIENCY

1,446,000 50.0 38.7 22.6% 77.4% N/A $ 42,400

1,446,000 50.0 43.2 13.5% 86.5% $ 2,040,000 $ 102,000


1,446,000 50.0 39.9 20.3% 79.7% $ 4,313,000 $ 216,000

1,446,000 50.0 41.6 16.7% 83.3% $ 600,000 $ 30,000


4.3a Alt $ FigMerit


Page 4.3a.281 10:22:2504/18/2023



ANNUAL O & M

B = 1 - ( A )


Annual ops. hours=

NET SALES POWER

AVAILABLE

POWER LOSS

TO GAS REMOV

AL


"GAS LOSS"


UNIT CAPACIT


Gases

Gross Generator

Output

Percent of gross

"Unit Capacity"

1,001,000 50.0 42.2 15.6% 84.4% N/A $ 65,900

1,001,000 50.0 43.4 13.3% 86.7% $ 3,120,000 $ 156,000


1,001,000 50.0 43.5 13.0% 87.0% $ 2,407,000 $ 120,000

1,001,000 50.0 43.1 13.8% 86.2% $ 600,000 $ 30,000


1,615,000 50.0 41.0 18.0% 82.0% N/A $ 45,300

1,615,000 50.0 42.8 14.4% 85.6% $ 2,400,000 $ 120,000


1,615,000 50.0 41.5 16.9% 83.1% $ 4,732,000 $ 237,000

1,615,000 50.0 42.4 15.1% 84.9% $ 600,000 $ 30,000



4.3a Alt $ FigMerit


Page 4.3a.282 10:22:2504/18/2023


$ / year

Use an annual on-line "stream Seefactor" of : 90% Worksheet

Annual ops. hours= 7884 4.3bRecovered power valued at : "Present( $ / kWh ) = $ 0.040 Values"

MAIN CASE GROUP 1N/A N/A N/A

18,050,000 $ 722,000 $ (1,540,000)

3,020,000 $ 120,800 $ (4,590,000)

6,890,000 $ 275,600 $ (980,000)

13,660,000 $ 546,400 $ 1,250,000


12,600,000 $ 504,000 $ (130,000)

1,700,000 $ 68,000 $ (5,040,000)

10,300,000 $ 412,000 $ (400,000)


SALABLE PRODUCT

ECONOMIC FIGURE OF

MERIT


for Sale


power

NET PRESENT VALUE


NPV at end of term



4.3a Alt $ FigMerit


Page 4.3a.283 10:22:2504/18/2023

$ / year




SALABLE PRODUCT

ECONOMIC FIGURE OF

MERIT


for Sale


power

NET PRESENT VALUE


NPV at end of term

9,500,000 $ 380,000 $ 1,100,000

4.3a Alt $ FigMerit


Page 4.3a.284 10:22:2504/18/2023

$ / year




SALABLE PRODUCT

ECONOMIC FIGURE OF

MERIT


for Sale


power

NET PRESENT VALUE


NPV at end of term


5,200,000 $ 208,000 $ (800,000)

200,000 $ 8,000 $ (5,510,000)

8,700,000 $ 348,000 $ (550,000)

4,500,000 $ 180,000 $ 510,000


20,800,000 $ 832,000 $ 1,690,000

21,500,000 $ 860,000 $ (3,910,000)

5,600,000 $ 224,000 $ (3,280,000)

16,500,000 $ 660,000 $ 2,350,000


4.3a Alt $ FigMerit


Page 4.3a.285 10:22:2504/18/2023

$ / year




SALABLE PRODUCT

ECONOMIC FIGURE OF

MERIT


for Sale


power

NET PRESENT VALUE


NPV at end of term


55,700,000 $ 2,228,000 $ 5,180,000

64,200,000 $ 2,568,000 $ 4,000,000

8,600,000 $ 344,000 $ (2,690,000)

40,500,000 $ 1,620,000 $ 6,040,000



74,300,000 $ 2,972,000 $ 3,740,000

93,000,000 $ 3,720,000 $ 9,440,000

8,400,000 $ 336,000 $ (2,660,000)

49,800,000 $ 1,992,000 $ 6,510,000


4.3a Alt $ FigMerit


Page 4.3a.286 10:22:2504/18/2023

$ / year




SALABLE PRODUCT

ECONOMIC FIGURE OF

MERIT


for Sale


power

NET PRESENT VALUE


NPV at end of term


45,200,000 $ 1,808,000 $ (26,300,000)

142,700,000 $ 5,708,000 $ 20,070,000

12,800,000 $ 512,000 $ (1,560,000)

25,400,000 $ 1,016,000 $ (3,790,000)



22,100,000 $ 884,000 $ (8,310,000)

3,600,000 $ 144,000 $ (3,910,000)

-5,800,000 $ (232,000) $ (3,150,000)

17,000,000 $ 680,000 $ 60,000


4.3a Alt $ FigMerit


Page 4.3a.287 10:22:2504/18/2023

$ / year




SALABLE PRODUCT

ECONOMIC FIGURE OF

MERIT


for Sale


power

NET PRESENT VALUE


NPV at end of term

LOW EJECTOR EFFICIENCYSENSITIVITY CASE GROUP S - 1

N/A N/A N/APAYBACKPERIODS

49,300,000 $ 1,972,000 2.6

34,000,000 $ 1,360,000 4.4

11,900,000 $ 476,000 6.1

23,500,000 $ 940,000 1.2


LOW EJECTOR EFFICIENCYSENSITIVITY CASE GROUP S - 2

N/A N/A N/APAYBACKPERIODS

35,600,000 $ 1,424,000 1.5

36,400,000 $ 1,456,000 7.1

9,100,000 $ 364,000 29.1

23,000,000 $ 920,000 0.6


4.3a Alt $ FigMerit


Page 4.3a.288 10:22:2504/18/2023

$ / year




SALABLE PRODUCT

ECONOMIC FIGURE OF

MERIT


for Sale


power

NET PRESENT VALUE


NPV at end of term

SENSITIVITY CASE GROUP S - 3N/A N/A N/A

PAYBACKPERIODS

9,200,000 $ 368,000 11.2

-4,500,000 $ (180,000) -14.2

10,100,000 $ 404,000 8.5

7,000,000 $ 280,000 1.9


SENSITIVITY CASE GROUP S - 4N/A N/A N/A

PAYBACKPERIODS

14,400,000 $ 576,000 4.8

14,100,000 $ 564,000 43.4

4,400,000 $ 176,000 -77.6

11,300,000 $ 452,000 1.3



4.3b Present Values


Page 4.3b.289 10:22:2504/18/2023

CALCULATIONS OF NET PRESENT VALUES OF THE ALTERNATIVE GAS REMOVAL SYSTEMS

NOTE : DEFINING VALUES OF THESE DATA ARE SET IN WORKSHEET 2.2, "INPUT&BASES"Valuation Periods : Analysis Term = 10 years (15 max.) Depreciation Term =

Annual Rates : Nominal Discount Rate = 10.00% en.Inflation Rate = 2.00%Real Discount Rate (Nom. Discount Rate / Gen. Inflation Rate) = 7.84% To correct Depreciation apply: 1 + Inflation =

For NPV factors apply (1+Real Discount Rate) = 1.0784 lvage Values = (see sheet 2.2 -- specific to each technology)

Electricity Price Inflation : 2.0% Electricity Price Inflation Compensation :

This worksheet calculates the present worth values of the gas removal system alternatives, using the performance data calculated in the engineering and economic figure of merit worksheets. The values of the controlling bases for these calculations are entered in worksheet 2.2, Bases&Input. These calculations use constant-dollar values, correcting the depreciation values and nominal interest (capital discount) rates for general market inflation. This adjusts the future years' net revenue values for the assigned capital discount rate. This spreadsheet allows the user to specify a separate inflation (deflation) rate for the contract price of electricity, which is realistic in today's markets. The difference between general and price-of-electricity inflation rates is compensated in the net present value (NPV) calculations.

Based on guidelines listed in the NREL publication, "A Manual for the Economic Evaluation of Energy Efficiency and Renewable Energy Technologies," (Short, Packey, Holt, 1995), this evaluation accommodates:

- user-selected values of annual capital discount rate, general inflation rate, standalone inflation rates on electricity prices, and tax rates.- taxes as a percent of net revenue after expenses are deducted.- cash flow analysis terms up to 15 years.- depreciation terms up to 12 years.- only straight-line depreciation.

The following operating cost variables can be assigned discretely for each gas removal technology:

- variable "O&M" costs as a percent of fixed capital costs for the alternative gas removal systems.- variable pre-tax expenses for salvage value and other general expenses as percents of capital costs or revenues.- pre-tax labor charges (which would usually be applied in lieu of a labor component in O&M charges).

The net present value of each gas removal option is calculated by balancing the values of installation capital costs and various operating costs versus the revenues attributable to that option. These calculations are based on each technology's specific performance at the plant conditions cited in worksheet 4.1, "Ops Details." The revenues for each option result from the energy savings (or deficit) that a gas removal option achieves compared to the Base Case plant configuration (in the original spreadsheet format the Base Case configuration is a two-stage steam jet ejector system -- the use can change that configuration). These revenues must pay for the installation and operating costs -- if not, the NPV results remain negative indefinitely.

The user can substitute different values of the controlling financial variables shown in Worksheet 2.2 (Bases&Input), such that the economic analyses can approximate a wide range of world electrical power market circumstances. This methodology is general but realistic in its form, and the uniform application of the method gives a good comparison of the relative economic merits of the gas removal alternatives.

As the calculations below are configured at delivery to the National Renewable Energy Laboratory, the economics account for retrofit conversions from a conventional steam jet ejector gas removal systems to one of the alternatives. The conversion is based on supporting a defined power plant capacity of 50 Megawatts. This worksheet can be modified easily to evaluate the alternative technologies as original construction options in lieu of steam jets. This may be done by reducing the capital costs of the alternatives by the cost of installation of a steam jet ejector configuration for the defined power plant capacity.

4.3b Present Values


Page 4.3b.290 10:22:2504/18/2023

ONE - TIME RECURRING ANNUAL COSTSCOST

CASE LABEL & ID YEAR 0 CONSTANT-DOLLAR VALUES

Revenues O & M Costs

$ / year $ / year $ / year

(a) (b) (c) (d) = b + c + dincome cost cost cost cost worksheet 2.2)


B1.1 ALTERNATIVE A $ 4,800,000 $ 722,000 $ 240,000 - $ - $ - $ 240,000 3-stage turbo-compressor

B1.2 ALTERNATIVE B $ 5,177,000 $ 120,800 $ 259,000 - $ - $ - $ 259,000 reboiler

B1.3 ALTERNATIVE C $ 2,228,000 $ 275,600 $ 111,000 - $ - $ - $ 111,000 biphase eductor

B1.4 ALTERNATIVE D $ 1,200,000 $ 546,400 $ 60,000 - $ - $ - $ 60,000 hybrid turbo-compressor





B2.4 ALTERNATIVE D $ 600,000 $ 380,000 $ 30,000 - $ - $ - $ 30,000 hybrid turbo-compressor

Installation Capital Costs

Labor Allocatio

n

Labor Costs

General Expense

s Net Costs Before

Depreciation

Equivalent

Personnel per

System

$ / year

Estimated Fixed Price

value of saved energy

% of fixed capital

% of revenue

s

4.3b Present Values


Page 4.3b.291 10:22:2504/18/2023







Labor Allocatio

n

Labor Costs

General Expense

s Net Costs Before

Depreciation

Equivalent

Personnel per

System

$ / year



% of fixed capital

% of revenue

s











4.3b Present Values


Page 4.3b.292 10:22:2504/18/2023







Labor Allocatio

n

Labor Costs

General Expense

s Net Costs Before

Depreciation

Equivalent

Personnel per

System

$ / year



% of fixed capital

% of revenue

s


B5.1 ALTERNATIVE A $ 4,800,000 $ 2,228,000 $ 240,000 - $ - $ - $ 240,000 3-stage turbo-compressor

B5.2 ALTERNATIVE B $ 7,522,000 $ 2,568,000 $ 376,000 - $ - $ - $ 376,000 reboiler


B5.4 ALTERNATIVE D $ 1,200,000 $ 1,620,000 $ 60,000 - $ - $ - $ 60,000 hybrid turbo-compressor


B6.1 ALTERNATIVE A $ 9,600,000 $ 2,972,000 $ 480,000 - $ - $ - $ 480,000 3-stage turbo-compressor




4.3b Present Values


Page 4.3b.293 10:22:2504/18/2023







Labor Allocatio

n

Labor Costs

General Expense

s Net Costs Before

Depreciation

Equivalent

Personnel per

System

$ / year



% of fixed capital

% of revenue

s


B7.1 ALTERNATIVE A $ 34,680,000 $ 1,808,000 $ 1,734,000 - $ - $ - $1,734,000 3-stage turbo-compressor







B8.3 ALTERNATIVE C $ 2,137,000 $ (232,000) $ 107,000 - $ - $ - $ 107,000 biphase eductor

B8.4 ALTERNATIVE D $ 3,000,000 $ 680,000 $ 150,000 - $ - $ - $ 150,000 hybrid turbo-compressor

4.3b Present Values


Page 4.3b.294 10:22:2504/18/2023

CALCULATIONS OF NET PRESENT VALUES OF THE ALTERNATIVE GAS REMOVAL SYSTEMS

NOTE : DEFINING VALUES OF THESE DATA ARE SET IN WORKSHEET 2.2, "INPUT&BASES"5 years (12 max.)

(labor, etc.) Tax Rate = 34%1 + Inflation = 1.02

(see sheet 2.2 -- specific to each technology)

1.00

This worksheet calculates the present worth values of the gas removal system alternatives, using the performance data calculated in the engineering and economic figure of merit worksheets. The values of the controlling bases for these calculations are entered in worksheet 2.2, Bases&Input. These calculations use constant-dollar values, correcting the depreciation values and nominal interest (capital discount) rates for general market inflation. This adjusts the future years' net revenue values for the assigned capital discount rate. This spreadsheet allows the user to specify a separate inflation (deflation) rate for the contract price of electricity, which is realistic in today's markets. The difference between general and price-of-electricity inflation rates is compensated in the net present value (NPV) calculations.

Based on guidelines listed in the NREL publication, "A Manual for the Economic Evaluation of Energy Efficiency and Renewable Energy Technologies," (Short, Packey, Holt, 1995), this evaluation accommodates:

- user-selected values of annual capital discount rate, general inflation rate, standalone inflation rates on electricity prices, and tax rates.- taxes as a percent of net revenue after expenses are deducted.- cash flow analysis terms up to 15 years.- depreciation terms up to 12 years.- only straight-line depreciation.

The following operating cost variables can be assigned discretely for each gas removal technology:

- variable "O&M" costs as a percent of fixed capital costs for the alternative gas removal systems.- variable pre-tax expenses for salvage value and other general expenses as percents of capital costs or revenues.- pre-tax labor charges (which would usually be applied in lieu of a labor component in O&M charges).

The net present value of each gas removal option is calculated by balancing the values of installation capital costs and various operating costs versus the revenues attributable to that option. These calculations are based on each technology's specific performance at the plant conditions cited in worksheet 4.1, "Ops Details." The revenues for each option result from the energy savings (or deficit) that a gas removal option achieves compared to the Base Case plant configuration (in the original spreadsheet format the Base Case configuration is a two-stage steam jet ejector system -- the use can change that configuration). These revenues must pay for the installation and operating costs -- if not, the NPV results remain negative indefinitely.

The user can substitute different values of the controlling financial variables shown in Worksheet 2.2 (Bases&Input), such that the economic analyses can approximate a wide range of world electrical power market circumstances. This methodology is general but realistic in its form, and the uniform application of the method gives a good comparison of the relative economic merits of the gas removal alternatives.

As the calculations below are configured at delivery to the National Renewable Energy Laboratory, the economics account for retrofit conversions from a conventional steam jet ejector gas removal systems to one of the alternatives. The conversion is based on supporting a defined power plant capacity of 50 Megawatts. This worksheet can be modified easily to evaluate the alternative technologies as original construction options in lieu of steam jets. This may be done by reducing the capital costs of the alternatives by the cost of installation of a steam jet ejector configuration for the defined power plant capacity.

4.3b Present Values


Page 4.3b.295 10:22:2504/18/2023

RECURRING ANNUAL COSTS CASH FLOW RESULTS -- CONSTANT-DOLLAR ANNUAL AND DISCOUNTED CUMULATIVE NET PRESENT VALUES

CONSTANT-DOLLAR VALUES YEAR NO. = 0 1 2 3

Depreciation 1 1 1

1 1 1

0.9273 0.8598 0.7973

Depreciation Inflation Factors = 0.9804 0.9612 0.9423 worksheet 2.2) Electr. Price Compensation = 1.0000 1.0000 1.0000


TOP ROW OF EACH PAIR : CONSTANT-DOLLAR ANNUAL NET REVENUES AFTER TAXESBOTTOM ROW OF EACH PAIR : CUMULATIVE NET PRESENT VALUE OF CASH FLOWS THROUGH LAST YEAR OF ANALYSIS TERM

$ 864,000 Constant $/yr $ (4,800,000) $ 606,120 $ 600,473 $ 594,937 Cum. NPV $ (4,800,000) $ (4,237,961) $ (3,721,654) $ (3,247,310)



$ 216,000 Constant $/yr $ (1,200,000) $ 393,024 $ 391,612 $ 390,228 Cum. NPV $ (1,200,000) $ (835,560) $ (498,838) $ (187,708)






$ 108,000 Constant $/yr $ (600,000) $ 267,000 $ 266,294 $ 265,602 Cum. NPV $ (600,000) $ (352,418) $ (123,449) $ 88,316

Analysis Switch

1 = on 0 = off

current dollar values $ / year

Depreciation Switch

1 = on 0 = off

Fixed price / Depr'n Term

Annual NPV Factors (with discount rate & inflation) =

(salvage % on

4.3b Present Values


Page 4.3b.296 10:22:2504/18/2023



Depreciation 1 1 1

1 1 1

0.9273 0.8598 0.7973


Analysis Switch

1 = on 0 = off


Depreciation Switch

1 = on 0 = off



(salvage % on




$ 1,006,740 Constant $/yr $ (5,593,000) $ 156,060 $ 149,480 $ 143,029 Cum. NPV $ (5,593,000) $ (5,448,290) $ (5,319,762) $ (5,205,725)


$ 54,000 Constant $/yr $ (300,000) $ 126,900 $ 126,547 $ 126,201 Cum. NPV $ (300,000) $ (182,329) $ (73,520) $ 27,101



$ 367,200 Constant $/yr $ (2,040,000) $ 604,200 $ 601,800 $ 599,447 Cum. NPV $ (2,040,000) $ (1,479,742) $ (962,293) $ (484,353)



$ 108,000 Constant $/yr $ (600,000) $ 451,800 $ 451,094 $ 450,402 Cum. NPV $ (600,000) $ (181,058) $ 206,808 $ 565,914

4.3b Present Values


Page 4.3b.297 10:22:2504/18/2023



Depreciation 1 1 1

1 1 1

0.9273 0.8598 0.7973


Analysis Switch

1 = on 0 = off


Depreciation Switch

1 = on 0 = off



(salvage % on



$ 864,000 Constant $/yr $ (4,800,000) $ 1,600,080 $ 1,594,433 $ 1,588,897 Cum. NPV $ (4,800,000) $ (3,316,289) $ (1,945,341) $ (678,511)

$ 1,353,960 Constant $/yr $ (7,522,000) $ 1,898,040 $ 1,889,191 $ 1,880,515 Cum. NPV $ (7,522,000) $ (5,761,999) $ (4,137,608) $ (2,638,271)


$ 216,000 Constant $/yr $ (1,200,000) $ 1,101,600 $ 1,100,188 $ 1,098,804 Cum. NPV $ (1,200,000) $ (178,516) $ 767,464 $ 1,643,542




$ 1,297,800 Constant $/yr $ (7,210,000) $ 2,649,540 $ 2,641,058 $ 2,632,742 Cum. NPV $ (7,210,000) $ (4,753,154) $ (2,482,281) $ (383,193)


$ 432,000 Constant $/yr $ (2,400,000) $ 1,379,520 $ 1,376,696 $ 1,373,928 Cum. NPV $ (2,400,000) $ (1,120,809) $ 62,923 $ 1,158,357

4.3b Present Values


Page 4.3b.298 10:22:2504/18/2023



Depreciation 1 1 1

1 1 1

0.9273 0.8598 0.7973


Analysis Switch

1 = on 0 = off


Depreciation Switch

1 = on 0 = off



(salvage % on




$ 978,120 Constant $/yr $ (5,434,000) $ 3,913,800 $ 3,907,407 $ 3,901,139 Cum. NPV $ (5,434,000) $ (1,804,840) $ 1,554,884 $ 4,665,268







$ 384,660 Constant $/yr $ (2,137,000) $ (95,520) $ (98,034) $ (100,499)Cum. NPV $ (2,137,000) $ (2,225,573) $ (2,309,866) $ (2,389,994)


4.3b Present Values


Page 4.3b.299 10:22:2504/18/2023

NOTES:

1. The "Analysis Term" is the total time period for which NPV calculations are requested, to a maximum duration of 15 years. The Figure of Merit plots indicate the cumulative NPV for the end of the specified term. The user may examine successive years' results graphically by changing the analysis term value. By selecting a value of 15 years, the table below gives the NPV history for all years.

2. The "Depreciation Term" is the period over which depreciation is deducted for tax purposes. Only straight-line depreciation is considered in this screening model.

3. The "Nominal Discount Rate" is the target time-value-of-money compounding rate required for return on investment by a prospective owner or investor.

4. The "General Inflation Rate" is a general economic term for costs of labor, supplies, materials, etc. This inflation rate is also used to correct the depreciation value (a non-inflating current-year value) to cancel the application of inflation in the NPV factors (see 5, following).

5. The "Real Discount Rate" is the effective rate of compounding of net revenues after compensating for inflation. This ratio is used to calculate NPV factors.

6. The price of electricity is assigned a separate inflation rate. The "Electricity Price Inflation Compensation" factor compensates for the differential price inflation compared to the general inflation factor built into the NPV factors.

7. The tax rate is the overall value of taxation on net revenues, including the deduction for depreciation.

8, The Recurring Annual Costs below are referred from other worksheets and calculated as listed.

9. The general formulae for the net annual revenues and the cumulative net present values of revenues and costs are as follows:

Annual Net Revenues = (electricity revenue) * (price inflation factor) - (net costs before depreciation) - (tax rate) * [ (electricity revenue) * (price inflation factor) - (net costs before depreciation) - (depreciation) * (depreciation factor) ]

Current-Year Cumulative NPV = (prior year cumulative NPV) + (current-year Annual Net Revenues) * (NPV factor based on net discount rate after inflation)

The Analysis Switch and the Depreciation Switch activate the calculation of annual net revenues and of depreciation, respectively, for only the years specified by the Analysis Term and Depreciation Term values. The Cumulative NPV remains constant in all years after the last year of the Analysis Term.

4.3b Present Values


Page 4.3b.300 10:22:2504/18/2023

CASH FLOW RESULTS -- CONSTANT-DOLLAR ANNUAL AND DISCOUNTED CUMULATIVE NET PRESENT VALUES

4 5 6 7 8 9

1 1 1 1 1 1

1 1 0 0 0 0

0.7393 0.6855 0.6357 0.5895 0.5466 0.5068

0.9238 0.9057 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000



$ 589,509 $ 584,187 $ 318,120 $ 318,120 $ 318,120 $ 318,120 $ (2,811,477) $ (2,410,989) $ (2,208,763) $ (2,021,245) $ (1,847,365) $ (1,686,130)

$ 201,492 $ 195,753 $ (91,212) $ (91,212) $ (91,212) $ (91,212) $ (4,475,847) $ (4,341,650) $ (4,399,632) $ (4,453,398) $ (4,503,253) $ (4,549,483)

$ 234,606 $ 232,136 $ 108,636 $ 108,636 $ 108,636 $ 108,636 $ (1,434,701) $ (1,275,561) $ (1,206,503) $ (1,142,466) $ (1,083,087) $ (1,028,027)

$ 388,871 $ 387,541 $ 321,024 $ 321,024 $ 321,024 $ 321,024 $ 99,790 $ 365,468 $ 569,539 $ 758,769 $ 934,237 $ 1,096,944



$ 389,134 $ 386,474 $ 253,440 $ 253,440 $ 253,440 $ 253,440 $ (1,092,045) $ (827,099) $ (665,990) $ (516,598) $ (378,071) $ (249,619)

$ 171,653 $ 165,673 $ (133,320) $ (133,320) $ (133,320) $ (133,320) $ (4,790,706) $ (4,677,129) $ (4,761,879) $ (4,840,465) $ (4,913,337) $ (4,980,908)

$ 325,232 $ 322,724 $ 197,340 $ 197,340 $ 197,340 $ 197,340 $ (1,167,278) $ (946,035) $ (820,588) $ (704,265) $ (596,401) $ (496,382)

$ 264,924 $ 264,258 $ 231,000 $ 231,000 $ 231,000 $ 231,000 $ 284,178 $ 465,339 $ 612,184 $ 748,348 $ 874,610 $ 991,689

4.3b Present Values


Page 4.3b.301 10:22:2604/18/2023


4 5 6 7 8 9

1 1 1 1 1 1

1 1 0 0 0 0

0.7393 0.6855 0.6357 0.5895 0.5466 0.5068

0.9238 0.9057 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000



$ 178,238 $ 176,309 $ 79,860 $ 79,860 $ 79,860 $ 79,860 $ (1,137,015) $ (1,016,146) $ (965,380) $ (918,306) $ (874,656) $ (834,180)

$ 136,705 $ 130,504 $ (179,520) $ (179,520) $ (179,520) $ (179,520) $ (5,104,657) $ (5,015,190) $ (5,129,309) $ (5,235,128) $ (5,333,252) $ (5,424,239)

$ 279,527 $ 277,178 $ 159,720 $ 159,720 $ 159,720 $ 159,720 $ (1,177,058) $ (987,039) $ (885,507) $ (791,359) $ (704,058) $ (623,106)

$ 125,862 $ 125,529 $ 108,900 $ 108,900 $ 108,900 $ 108,900 $ 120,152 $ 206,209 $ 275,435 $ 339,627 $ 399,150 $ 454,345



$ 597,140 $ 594,879 $ 481,800 $ 481,800 $ 481,800 $ 481,800 $ (42,878) $ 364,939 $ 671,214 $ 955,215 $ 1,218,561 $ 1,462,754

$ 751,225 $ 742,565 $ 309,540 $ 309,540 $ 309,540 $ 309,540 $ (5,267,679) $ (4,758,616) $ (4,561,845) $ (4,379,384) $ (4,210,193) $ (4,053,307)

$ 249,134 $ 244,353 $ 5,280 $ 5,280 $ 5,280 $ 5,280 $ (3,458,747) $ (3,291,232) $ (3,287,875) $ (3,284,763) $ (3,281,877) $ (3,279,201)

$ 449,724 $ 449,058 $ 415,800 $ 415,800 $ 415,800 $ 415,800 $ 898,402 $ 1,206,253 $ 1,470,573 $ 1,715,669 $ 1,942,940 $ 2,153,682

4.3b Present Values


Page 4.3b.302 10:22:2604/18/2023


4 5 6 7 8 9

1 1 1 1 1 1

1 1 0 0 0 0

0.7393 0.6855 0.6357 0.5895 0.5466 0.5068

0.9238 0.9057 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000



$ 1,583,469 $ 1,578,147 $ 1,312,080 $ 1,312,080 $ 1,312,080 $ 1,312,080 $ 492,172 $ 1,574,067 $ 2,408,142 $ 3,181,557 $ 3,898,724 $ 4,563,733

$ 1,872,009 $ 1,863,670 $ 1,446,720 $ 1,446,720 $ 1,446,720 $ 1,446,720 $ (1,254,265) $ 23,369 $ 943,033 $ 1,795,813 $ 2,586,572 $ 3,319,822

$ 327,261 $ 322,539 $ 86,460 $ 86,460 $ 86,460 $ 86,460 $ (3,145,403) $ (2,924,287) $ (2,869,325) $ (2,818,361) $ (2,771,103) $ (2,727,282)

$ 1,097,447 $ 1,096,117 $ 1,029,600 $ 1,029,600 $ 1,029,600 $ 1,029,600 $ 2,454,902 $ 3,206,342 $ 3,860,847 $ 4,467,753 $ 5,030,519 $ 5,552,358



$ 2,187,498 $ 2,176,855 $ 1,644,720 $ 1,644,720 $ 1,644,720 $ 1,644,720 $ (2,271,045) $ (778,708) $ 266,823 $ 1,236,316 $ 2,135,300 $ 2,968,903

$ 2,624,589 $ 2,616,596 $ 2,216,940 $ 2,216,940 $ 2,216,940 $ 2,216,940 $ 1,557,207 $ 3,351,007 $ 4,760,292 $ 6,067,084 $ 7,278,836 $ 8,402,461

$ 320,625 $ 315,969 $ 83,160 $ 83,160 $ 83,160 $ 83,160 $ (3,108,817) $ (2,892,205) $ (2,839,341) $ (2,790,322) $ (2,744,868) $ (2,702,719)

$ 1,371,214 $ 1,368,554 $ 1,235,520 $ 1,235,520 $ 1,235,520 $ 1,235,520 $ 2,172,118 $ 3,110,326 $ 3,895,733 $ 4,624,019 $ 5,299,340 $ 5,925,545

4.3b Present Values


Page 4.3b.303 10:22:2604/18/2023


4 5 6 7 8 9

1 1 1 1 1 1

1 1 0 0 0 0

0.7393 0.6855 0.6357 0.5895 0.5466 0.5068

0.9238 0.9057 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000



$ 2,009,624 $ 1,971,178 $ 48,840 $ 48,840 $ 48,840 $ 48,840 $ (27,789,896) $ (26,438,561) $ (26,407,514) $ (26,378,725) $ (26,352,029) $ (26,327,275)

$ 3,894,995 $ 3,888,971 $ 3,587,760 $ 3,587,760 $ 3,587,760 $ 3,587,760 $ 7,544,899 $ 10,210,972 $ 12,491,673 $ 14,606,504 $ 16,567,530 $ 18,385,936

$ 429,083 $ 424,785 $ 209,880 $ 209,880 $ 209,880 $ 209,880 $ (2,427,295) $ (2,136,085) $ (2,002,666) $ (1,878,951) $ (1,764,233) $ (1,657,859)

$ 868,290 $ 858,978 $ 393,360 $ 393,360 $ 393,360 $ 393,360 $ (5,463,015) $ (4,874,145) $ (4,624,090) $ (4,392,221) $ (4,177,216) $ (3,977,847)



$ 874,386 $ 860,684 $ 175,560 $ 175,560 $ 175,560 $ 175,560 $ (9,378,699) $ (8,788,660) $ (8,677,058) $ (8,573,573) $ (8,477,614) $ (8,388,634)

$ 202,869 $ 197,778 $ (56,760) $ (56,760) $ (56,760) $ (56,760) $ (3,889,826) $ (3,754,240) $ (3,790,322) $ (3,823,779) $ (3,854,804) $ (3,883,572)

$ (102,915) $ (105,285) $ (223,740) $ (223,740) $ (223,740) $ (223,740) $ (2,466,081) $ (2,538,259) $ (2,680,488) $ (2,812,373) $ (2,934,667) $ (3,048,066)

$ 519,418 $ 516,092 $ 349,800 $ 349,800 $ 349,800 $ 349,800 $ (1,255,374) $ (901,568) $ (679,204) $ (473,012) $ (281,816) $ (104,524)

4.3b Present Values


Page 4.3b.304 10:22:2604/18/2023

NOTES:

1. The "Analysis Term" is the total time period for which NPV calculations are requested, to a maximum duration of 15 years. The Figure of Merit plots indicate the cumulative NPV for the end of the specified term. The user may examine successive years' results graphically by changing the analysis term value. By selecting a value of 15 years, the table below gives the NPV history for all years.

2. The "Depreciation Term" is the period over which depreciation is deducted for tax purposes. Only straight-line depreciation is considered in this screening model.

3. The "Nominal Discount Rate" is the target time-value-of-money compounding rate required for return on investment by a prospective owner or investor.

4. The "General Inflation Rate" is a general economic term for costs of labor, supplies, materials, etc. This inflation rate is also used to correct the depreciation value (a non-inflating current-year value) to cancel the application of inflation in the NPV factors (see 5, following).

5. The "Real Discount Rate" is the effective rate of compounding of net revenues after compensating for inflation. This ratio is used to calculate NPV factors.

6. The price of electricity is assigned a separate inflation rate. The "Electricity Price Inflation Compensation" factor compensates for the differential price inflation compared to the general inflation factor built into the NPV factors.

7. The tax rate is the overall value of taxation on net revenues, including the deduction for depreciation.

8, The Recurring Annual Costs below are referred from other worksheets and calculated as listed.

9. The general formulae for the net annual revenues and the cumulative net present values of revenues and costs are as follows:

Annual Net Revenues = (electricity revenue) * (price inflation factor) - (net costs before depreciation) - (tax rate) * [ (electricity revenue) * (price inflation factor) - (net costs before depreciation) - (depreciation) * (depreciation factor) ]

Current-Year Cumulative NPV = (prior year cumulative NPV) + (current-year Annual Net Revenues) * (NPV factor based on net discount rate after inflation)

The Analysis Switch and the Depreciation Switch activate the calculation of annual net revenues and of depreciation, respectively, for only the years specified by the Analysis Term and Depreciation Term values. The Cumulative NPV remains constant in all years after the last year of the Analysis Term.

4.3b Present Values


Page 4.3b.305 10:22:2604/18/2023


10 11 12 13 14 15

1 0 0 0 0 0

0 0 0 0 0 0

0.4700 0.0000 0.0000 0.0000 0.0000 0.0000

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000



$ 318,120 $ - $ - $ - $ - $ - $ (1,536,622) $ (1,536,622) $ (1,536,622) $ (1,536,622) $ (1,536,622) $ (1,536,622)

$ (91,212) $ - $ - $ - $ - $ - $ (4,592,350) $ (4,592,350) $ (4,592,350) $ (4,592,350) $ (4,592,350) $ (4,592,350)

$ 108,636 $ - $ - $ - $ - $ - $ (976,970) $ (976,970) $ (976,970) $ (976,970) $ (976,970) $ (976,970)

$ 321,024 $ - $ - $ - $ - $ - $ 1,247,817 $ 1,247,817 $ 1,247,817 $ 1,247,817 $ 1,247,817 $ 1,247,817



$ 253,440 $ - $ - $ - $ - $ - $ (130,508) $ (130,508) $ (130,508) $ (130,508) $ (130,508) $ (130,508)

$ (133,320) $ - $ - $ - $ - $ - $ (5,043,565) $ (5,043,565) $ (5,043,565) $ (5,043,565) $ (5,043,565) $ (5,043,565)

$ 197,340 $ - $ - $ - $ - $ - $ (403,637) $ (403,637) $ (403,637) $ (403,637) $ (403,637) $ (403,637)

$ 231,000 $ - $ - $ - $ - $ - $ 1,100,253 $ 1,100,253 $ 1,100,253 $ 1,100,253 $ 1,100,253 $ 1,100,253

4.3b Present Values


Page 4.3b.306 10:22:2604/18/2023


10 11 12 13 14 15

1 0 0 0 0 0

0 0 0 0 0 0

0.4700 0.0000 0.0000 0.0000 0.0000 0.0000

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000



$ 79,860 $ - $ - $ - $ - $ - $ (796,647) $ (796,647) $ (796,647) $ (796,647) $ (796,647) $ (796,647)

$ (179,520) $ - $ - $ - $ - $ - $ (5,508,609) $ (5,508,609) $ (5,508,609) $ (5,508,609) $ (5,508,609) $ (5,508,609)

$ 159,720 $ - $ - $ - $ - $ - $ (548,042) $ (548,042) $ (548,042) $ (548,042) $ (548,042) $ (548,042)

$ 108,900 $ - $ - $ - $ - $ - $ 505,525 $ 505,525 $ 505,525 $ 505,525 $ 505,525 $ 505,525



$ 481,800 $ - $ - $ - $ - $ - $ 1,689,188 $ 1,689,188 $ 1,689,188 $ 1,689,188 $ 1,689,188 $ 1,689,188

$ 309,540 $ - $ - $ - $ - $ - $ (3,907,831) $ (3,907,831) $ (3,907,831) $ (3,907,831) $ (3,907,831) $ (3,907,831)

$ 5,280 $ - $ - $ - $ - $ - $ (3,276,719) $ (3,276,719) $ (3,276,719) $ (3,276,719) $ (3,276,719) $ (3,276,719)

$ 415,800 $ - $ - $ - $ - $ - $ 2,349,098 $ 2,349,098 $ 2,349,098 $ 2,349,098 $ 2,349,098 $ 2,349,098

4.3b Present Values


Page 4.3b.307 10:22:2604/18/2023


10 11 12 13 14 15

1 0 0 0 0 0

0 0 0 0 0 0

0.4700 0.0000 0.0000 0.0000 0.0000 0.0000

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000



$ 1,312,080 $ - $ - $ - $ - $ - $ 5,180,378 $ 5,180,378 $ 5,180,378 $ 5,180,378 $ 5,180,378 $ 5,180,378

$ 1,446,720 $ - $ - $ - $ - $ - $ 3,999,744 $ 3,999,744 $ 3,999,744 $ 3,999,744 $ 3,999,744 $ 3,999,744

$ 86,460 $ - $ - $ - $ - $ - $ (2,686,648) $ (2,686,648) $ (2,686,648) $ (2,686,648) $ (2,686,648) $ (2,686,648)

$ 1,029,600 $ - $ - $ - $ - $ - $ 6,036,244 $ 6,036,244 $ 6,036,244 $ 6,036,244 $ 6,036,244 $ 6,036,244



$ 1,644,720 $ - $ - $ - $ - $ - $ 3,741,880 $ 3,741,880 $ 3,741,880 $ 3,741,880 $ 3,741,880 $ 3,741,880

$ 2,216,940 $ - $ - $ - $ - $ - $ 9,444,368 $ 9,444,368 $ 9,444,368 $ 9,444,368 $ 9,444,368 $ 9,444,368

$ 83,160 $ - $ - $ - $ - $ - $ (2,663,636) $ (2,663,636) $ (2,663,636) $ (2,663,636) $ (2,663,636) $ (2,663,636)

$ 1,235,520 $ - $ - $ - $ - $ - $ 6,506,209 $ 6,506,209 $ 6,506,209 $ 6,506,209 $ 6,506,209 $ 6,506,209

4.3b Present Values


Page 4.3b.308 10:22:2604/18/2023


10 11 12 13 14 15

1 0 0 0 0 0

0 0 0 0 0 0

0.4700 0.0000 0.0000 0.0000 0.0000 0.0000

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000



$ 48,840 $ - $ - $ - $ - $ - $ (26,304,322) $ (26,304,322) $ (26,304,322) $ (26,304,322) $ (26,304,322) $ (26,304,322)

$ 3,587,760 $ - $ - $ - $ - $ - $ 20,072,093 $ 20,072,093 $ 20,072,093 $ 20,072,093 $ 20,072,093 $ 20,072,093

$ 209,880 $ - $ - $ - $ - $ - $ (1,559,220) $ (1,559,220) $ (1,559,220) $ (1,559,220) $ (1,559,220) $ (1,559,220)

$ 393,360 $ - $ - $ - $ - $ - $ (3,792,977) $ (3,792,977) $ (3,792,977) $ (3,792,977) $ (3,792,977) $ (3,792,977)



$ 175,560 $ - $ - $ - $ - $ - $ (8,306,125) $ (8,306,125) $ (8,306,125) $ (8,306,125) $ (8,306,125) $ (8,306,125)

$ (56,760) $ - $ - $ - $ - $ - $ (3,910,247) $ (3,910,247) $ (3,910,247) $ (3,910,247) $ (3,910,247) $ (3,910,247)

$ (223,740) $ - $ - $ - $ - $ - $ (3,153,218) $ (3,153,218) $ (3,153,218) $ (3,153,218) $ (3,153,218) $ (3,153,218)

$ 349,800 $ - $ - $ - $ - $ - $ 59,873 $ 59,873 $ 59,873 $ 59,873 $ 59,873 $ 59,873

Sheet 4.4 CostData


Page 4.4.309 10:22:2604/18/2023

CAPACITY CAPACITY

VALUE UNITS COST VALUE

Plant Bases for Ejector Design Case:(high temperature/pressure, mid gas case)

2-Stage System Ejectors, condensers motive 224,000 $ 500,000 EJECTOR DESIGN BASES (hi temp, mid gas Base Case)Installation factor steam lb / hr 2.5 Stage

data Installed system cost 110 psia $ 1,250,000

motive 13-Stage System Ejectors, condensers steam 175,000 $ 700,000

Installation factor data lb / hr 2.5 2

Installed system cost 110 psia $ 1,750,000

Assume steam jet expansion nozzle velocity reaches a maximum of :Assume eductor with flashing brine is only allowed a max. velocity of :The flashing brine or flashed steam temperature is :The flashing brine or flashed steam pressure is :

(use the high temperature case -- more optimistic for brine, allowing higher energy recovery) Steam density is (approximately, not solving for gas effects) :Water density (not solving for dissolved solids) : Estimate flash of brine yields weight percent vapor quality as :Average bulk density of flashing brine is :Estimated brine flow rate from main flash tank :

eductor drive fluid, as flashing 2-phase mixture : Steam volumetric flow rate :

(refer to above ejector quote data for mass flow)Plant Bases for Eductor Design Case: Gas loading in plant flashed steam(high temperature/pressure, mid gas case)

932,000 lb / hr flashed steam an eductor system as the ratio of areas for the estimated flowrates 29,900 ppmv CO2 NCG and assumed velocity limits :

Power-law exponent for ejector systems : This size ratio is now used to apply the power law for roughly estimating theinstalled cost of a brine-driven eductor system :

COST = (Ejector System Price) x (area ratio) exp. (Cost factor) =

HARDWARE COMPONENTS & SYSTEM PACKAGES

at 334 oF

at 334 oF

AREA = volumetric flow / velocity -- so solve for the

CAPITAL AND OPERATING COST DATA FOR GEOTHERMAL POWER PLANTS AND EQUIPMENT SYSTEMS AND COMPONENTS

STEAM JET EJECTOR SYSTEM - ejectors with barometric after-stage condensers

BIPHASE EDUCTOR SYSTEM - - eductors with barometric after-stage condensers. Overall eductor system sizing will be roughly proportional to the estimated brine leaving the plant feed flash system. See Main Case Summaries, Sensitivity Case Summaries.

Design bases are steam and brine flows from the high temperature/pressure and medium gas Base Case.

NOTE : Shaded entries may be adjusted by the user.

RETURN

Sheet 4.4 CostData


Page 4.4.310 10:22:2604/18/2023

TURBOCOMPRESSOR UNITS installed costs -- single unitsInstallation Factor : 1.50 Installation Factor :

16 - inch compressor $ 300,000 24 - inch compressor

CASE NONCONDENSABLE GAS3-STAGE COMPRESSOR SYSTEM INSTALLED HYBRIDGROUP RATES (*) lb / hour 1 2 3 SYSTEM 3rd STAGE

load gas drive gas 24 - inch 24 - inch 16 - inch COSTS 16 - inchBase B-1 110,224 13,293 6 4 4 $ 4,800,000 4

Cases B-2 65,365 4,845 3 2 2 $ 2,400,000 2B-3 21,541 524 2 2 1 $ 1,740,000 1B-4 34,952 1,340 2 2 2 $ 2,040,000 2B-5 105,976 12,709 6 4 4 $ 4,800,000 4B-6 178,383 34,787 12 8 8 $ 9,600,000 8B-7 561,889 268,174 45 28 28 $ 34,680,000 28B-8 226,036 49,509 16 10 10 $ 12,360,000 10

Sensitivity S-1 110,224 13,293 6 4 4 $ 4,800,000 4Cases S-2 35,012 1,345 2 2 2 $ 2,040,000 2

S-3 71,320 4,896 4 3 2 $ 3,120,000 2S-4 39,477 1,404 3 2 2 $ 2,400,000 2S-5S-6S-7

(*) Gas rates also carry matching steam loads at equilibrium conditions.

STEAM REBOILER -- Put 2 plant estimates on common capacity basis :

6- year escalation : As Estimated Sizing exponent :

Estimate for an Installed Plant 20 megawatts $ 2,782,000 53.7Bases :Flashed Steam (lb/hr) : 4.16E+05 for 20 MW capacity

324 - 346 approx.Pressure (psia) 95 - 128Gas Conc. (ppmv) 25,400

Installation Factor : Quotation Estimate for Bare Equipment : 53.7

Quotation Bases : Equivalent CapacityFlashed Steam (lb/hr) : 1.00E+06

335Pressure (psia) 110Gas Conc. (ppmv) 30,000 Equivalent Capacity : 53.7 MW Gross Output

Installed Costs -- integrated vacuum systems

Temperature (oF)

Temperature (oF)

Above from 1993 Parsons Main, Inc. report to PNOC; "conservative values," per personal communication, Dr. G.E. Coury

Bare eqp. and install. factor from Swenson Process Equipment, Inc., Seattle, WA, 9/99 : 316L S/S vertical tube evaporator, flash tank, recirc. piping, and recirc. pump. C/S support structure.

This case basis is effectively the high-temperature, mid-gas case for the present study.

Above is escalated from basis at left and scaled up to capacity equiva,lent to basis below quoted from Swenson.

Sheet 4.4 CostData


Page 4.4.311 10:22:2604/18/2023

Sizing basis, (MW)

883

H2S GAS TREATMENT SYSTEMBasis Units

(plant flashed steam feed )1.00E+06 lb/hr steam 3.00E+04 ppmv CO2

1000 ppmv H2S

UNECO Treating Systems, Inc. Caustic H2S Scrubbing Installed System Cost $ 3,000,000 install incl.

Operating Cost $ 13,809 per day (maint. incl.)

US Filter / LO-CAT II Chelation/Reduction H2S Scrubbing

System Cost $ 5,250,000 skid systems Operating Cost $ 3,334 per day

(w/o maint.) Installation factor 1.5

Installed cost $ 7,875,000

Now take the average of the above two cases and scale up : AVG. REBOILER INSTALLED COST

Steam latent heat at 335 oF (Btu/lb) = Steam latent heat at 234 oF (Btu/lb) =

For estimating reboiler size and cost changes for differing cases, the primary basis of this study is the 50 MW plant power capacity. Costs at different generating capacities and the same steam conditions are based on the gross power ratio raised to a power factor. (see "Bases & Input" worksheet).To calculate reboiler system price changes with differing steam conditions, the capacity factor includes ratios of the values of the clean steam flow to the power turbine, and latent heats of evaporation of steam at the two conditions being considered. This applies to capital cost calculations for the low-temperature case studies. For the high-temperature case studies, the latent heat values drop out of the power factor ratios. The clean steam flowrate is theappropriate heat exchanger sizing basis, because for wide-ranging values of gas concentrations, using the flashed-steam mass flow ratios would distort the sizing adjustments to the heat transfer area in the reboiler.

This is the nominal basis for a 50 MW power plant using the steam feed from the high temperature, medium gas case of this study.

This study neglects potential changes in H2S levels from those given here. Such a change would presumably drive the operating costs in rough proportion to the H2S levels.

This study assumes the sulfur treatment system capital costs for the low-temperature bases will be roughly equal to the values stated at right.

These values are not currently included in the economic figure of merit valuations. These values are for reference regarding the consideration of potentially eliminating gas treatment in favor of reinjecting untreated noncondensable gases.

Sheet 4.4 CostData


Page 4.4.312 10:22:2604/18/2023

CAPACITY CAPACITY

UNITS COST VALUE UNITS COST

Plant Bases for Ejector Design Case: 932,000 lb / hr flashed steam(high temperature/pressure, mid gas case) 29,900 ppmv CO2 NCG

EJECTOR DESIGN BASES (hi temp, mid gas Base Case) Load Gases Stage Pressure Ratio

Steam CO2 lb / hr lb / hr59,300 52,400 3.4

5,700 44,000 2.9

Assume steam jet expansion nozzle velocity reaches a maximum of : 3,000 ft / secAssume eductor with flashing brine is only allowed a max. velocity of : 500 ft / secThe flashing brine or flashed steam temperature is : 334The flashing brine or flashed steam pressure is : 110 psia

(use the high temperature case -- more optimistic for brine, allowing higher energy recovery) Steam density is (approximately, not solving for gas effects) : 0.244 lb / cu.ft.Water density (not solving for dissolved solids) : 56.1 lb / cu.ft.Estimate flash of brine yields weight percent vapor quality as : 7%Average bulk density of flashing brine is : 3.30 lb / cu.ft.Estimated brine flow rate from main flash tank : 1,356,000 lb / hr

as saturated liquid : 3,011 gal / min.eductor drive fluid, as flashing 2-phase mixture : 114 cu. ft. / sec.

ejector drive gas : 254 cu. ft. / sec.(refer to above ejector quote data for mass flow)

29,900 ppmv

an eductor system as the ratio of areas for the estimated flowrates

A(educt) / A (eject) = 2.7

Power-law exponent for ejector systems : 0.6This size ratio is now used to apply the power law for roughly estimating theinstalled cost of a brine-driven eductor system :

COST = (Ejector System Price) x (area ratio) exp. (Cost factor) = $ 2,263,194 installed cost

oF

AREA = volumetric flow / velocity -- so solve for the relative size of

CAPITAL AND OPERATING COST DATA FOR GEOTHERMAL POWER PLANTS AND EQUIPMENT SYSTEMS AND COMPONENTS

NOTE : Shaded entries may be adjusted by the user.

NOTE: overall ejector system sizing will be roughly proportional to plant power turbine feed steam flow rates and gas loading.

RETURN

Sheet 4.4 CostData


Page 4.4.313 10:22:2604/18/2023

Installation Factor : 1.50 24 - inch compressor $ 360,000

INSTALLED 3rd STAGE

COST $ 1,200,000 $ 600,000 $ 300,000 $ 600,000 $ 1,200,000 $ 2,400,000 $ 8,400,000 $ 3,000,000 $ 1,200,000 $ 600,000 $ 600,000 $ 600,000

6- year escalation : 1.19 Sizing exponent : 0.6

megawatts $ 6,010,549 installed cost

Installation Factor : 1.50 MW $ 3,500,000 bare eqp. cost

Equivalent Capacity 5,250,000 installed cost

Bare eqp. and install. factor from Swenson Process Equipment, Inc., Seattle, WA, 9/99 : 316L S/S vertical tube evaporator, flash tank, recirc. piping, and recirc. pump. C/S support structure.

This case basis is effectively the high-temperature, mid-gas case for the present study.

NOTE: overall turbo-compressor system sizing will be roughly proportional to plant power turbine feed steam flow rates and NCG loading, accounting also for drive gas loading.

The turbocompressor units are staged and combined in parallel for the economic figure of merit cases, according to the capacities needed to evacuate case-specific gas and steam flow rates from the condenser train. The matching of specific unit counts for each case is based on examples from Barber-Nichols. Price data obtained 7/99.

Above is escalated from basis at left and scaled up to capacity equiva,lent to basis below quoted from Swenson.

Sheet 4.4 CostData


Page 4.4.314 10:22:2604/18/2023

$ 5,392,000 Reference conditions are the high- Sizing basis, (MW) 50.0 temperature, mid-gas Main Case Group No. 2

956

AVG. REBOILER INSTALLED COST =

Steam latent heat at 234 oF (Btu/lb) =

For estimating reboiler size and cost changes for differing cases, the primary basis of this study is the 50 MW plant power capacity. Costs at different generating capacities and the same steam conditions are based on the gross power ratio raised to a power factor. (see "Bases & Input" worksheet).To calculate reboiler system price changes with differing steam conditions, the capacity factor includes ratios of the values of the clean steam flow to the power turbine, and latent heats of evaporation of steam at the two conditions being considered. This applies to capital cost calculations for the low-temperature case studies. For the high-temperature case studies, the latent heat values drop out of the power factor ratios. The clean steam flowrate is theappropriate heat exchanger sizing basis, because for wide-ranging values of gas concentrations, using the flashed-steam mass flow ratios would distort the sizing adjustments to the heat transfer area in the reboiler.

This is the nominal basis for a 50 MW power plant using the steam feed from the high temperature, medium gas case of this study.

This study neglects potential changes in H2S levels from those given here. Such a change would presumably drive the operating costs in rough proportion to the H2S levels.

This study assumes the sulfur treatment system capital costs for the low-temperature bases will be roughly equal to the values stated at right.

These values are not currently included in the economic figure of merit valuations. These values are for reference regarding the consideration of potentially eliminating gas treatment in favor of reinjecting untreated noncondensable gases.

Sheet 5. SensiComp


Page 5.315 10:22:2604/18/2023

EFFECTS OF DESIGN AND SITE OPERATING PARAMETERS

This worksheet compares the performance of the gas removal technologies at discrete data points for changed assumptions about (1) the prevailing wet bulb temperature at a plant site, and (2) a reduced value of the net efficiency of conventional steam jet ejectors. The comparisons show the change in the technical and economic figures of merit for each noncondensable gas removal technology for alternative assumptions.

The first comparison tests the differences resulting from changing the assumed steam jet ejector efficiency from 23 percent to 15 percent. The 23 percent value is the basis for the main cases in this study. This parameter does not directly change the various alternative technologies' performance abilities. Instead, since the figures of merit are relative values that compare the performance of gas removal alternatives to conventional steam jet ejector systems, the change in ejector efficiency shows up ultimately as changes in the technical figure of merit and payback periods needed to recover the costs of conversion to the alternative gas removal systems.

The second change of conditions looks at a site ambient wet bulb temperature of 80 oF, compared to the value of 60 oF used in the main cases of this study. Raising the wet bulb temperature hinders the heat rejection system. It also imposes a higher backpressure on the power turbine, leading to increased brine and steam flows through the power system. There is not much evident change in vacuum system drive gas demand, but cooling system electrical loads tend to increase slightly.

The "Relative Change" parameter under the "Economic" heading below indicates the economic impact of changes in system operation at the alternative conditions. For the cases looking at ejector efficiencies, the changes are rated as percent change in the payback period at the reduced ejector efficiency compared to that of the main case results. A positive percent values represents a reduction in the payback period, which is good. But beware of anomolous cases, e.g. comparing positive and negative payback estimates. A negative payback indicates the conversion case could never pay for itself, so any positive payback looks good by comparison. Also, a reduction in the payback period may be essentially meaningless when comparing two very large numbers or two negative numbers, for example -- neither option in such cases would be attractive for capital investment.

If actual steam jet ejector efficiencies do turn out to be about 15 percent, instead of the main-case basis of 23 percent, the economic argument for the alternative gas removal technologies would be better, showing modest to strong reductions in the payback periods to recoup capital costs. This occurs because at lower steam jet efficiencies, the gas removal options would realize higher reductions in the parasitic steam demand, yielding higher cost savings in operation.

The Relative Change parameter for the cases looking at the effects of different wet bulb temperatures is a simple ratio of payback periods. A fractional value would indicate that the alternative conditions result in shorter payback periods. A whole number or negative value of the Relative Change parameter indicates that the alternative technology loses ground compared to the same case at lower wet bulb temperature.

Raising the ambient wet bulb temperature always extends the payback periods for converting to alternative gas removal processes. Comparing negative payback values gives anomalous results.

Sheet 5. SensiComp


Page 5.316 10:22:2604/18/2023

TECHNOLOGY Produced Flashed Wet Steam JetFluid Steam Bulb Ejector

Temperature Gas Level Temperature Efficiencyppmv Percent

3-Stage Turbocompressor 550 49,900 60 1523

Reboiler 1523

Biphase Eductor 1523

Hybrid Ejector / Turbo. 1523


Reboiler 1523




Reboiler 6080




Reboiler 6080



oF oF

High-temperature cases at 50,000 ppmv gas loads in flashed geothermal steam, compar-ing 15 % versus 23 % steam jet ejector efficiencies.

Low-temperature cases at 10,000 ppmv gas loads in flashed geothermal steam, compar-ing 15 % versus 23 % steam jet ejector efficiencies.

Low-temperature cases at 10,000 ppmv gas loads in flashed geothermal steam, comparing different wet bulb temperatures.

High-temperature cases at 50,000 ppmv gas loads in flashed geothermal steam, comparing different wet bulb temperatures.

Sheet 5. SensiComp


Page 5.317 10:22:2604/18/2023

EFFECTS OF DESIGN AND SITE OPERATING PARAMETERS

This worksheet compares the performance of the gas removal technologies at discrete data points for changed assumptions about (1) the prevailing wet bulb temperature at a plant site, and (2) a reduced value of the net efficiency of conventional steam jet ejectors. The comparisons show the change in the technical and economic figures of merit for each noncondensable gas removal technology for alternative assumptions.

The first comparison tests the differences resulting from changing the assumed steam jet ejector efficiency from 23 percent to 15 percent. The 23 percent value is the basis for the main cases in this study. This parameter does not directly change the various alternative technologies' performance abilities. Instead, since the figures of merit are relative values that compare the performance of gas removal alternatives to conventional steam jet ejector systems, the change in ejector efficiency shows up ultimately as changes in the technical figure of merit and payback periods needed to recover the costs of conversion to the alternative gas removal systems.

The second change of conditions looks at a site ambient wet bulb temperature of 80 oF, compared to the value of 60 oF used in the main cases of this study. Raising the wet bulb temperature hinders the heat rejection system. It also imposes a higher backpressure on the power turbine, leading to increased brine and steam flows through the power system. There is not much evident change in vacuum system drive gas demand, but cooling system electrical loads tend to increase slightly.

The "Relative Change" parameter under the "Economic" heading below indicates the economic impact of changes in system operation at the alternative conditions. For the cases looking at ejector efficiencies, the changes are rated as percent change in the payback period at the reduced ejector efficiency compared to that of the main case results. A positive percent values represents a reduction in the payback period, which is good. But beware of anomolous cases, e.g. comparing positive and negative payback estimates. A negative payback indicates the conversion case could never pay for itself, so any positive payback looks good by comparison. Also, a reduction in the payback period may be essentially meaningless when comparing two very large numbers or two negative numbers, for example -- neither option in such cases would be attractive for capital investment.

If actual steam jet ejector efficiencies do turn out to be about 15 percent, instead of the main-case basis of 23 percent, the economic argument for the alternative gas removal technologies would be better, showing modest to strong reductions in the payback periods to recoup capital costs. This occurs because at lower steam jet efficiencies, the gas removal options would realize higher reductions in the parasitic steam demand, yielding higher cost savings in operation.

The Relative Change parameter for the cases looking at the effects of different wet bulb temperatures is a simple ratio of payback periods. A fractional value would indicate that the alternative conditions result in shorter payback periods. A whole number or negative value of the Relative Change parameter indicates that the alternative technology loses ground compared to the same case at lower wet bulb temperature.

Raising the ambient wet bulb temperature always extends the payback periods for converting to alternative gas removal processes. Comparing negative payback values gives anomalous results.

Sheet 5. SensiComp


Page 5.318 10:22:2604/18/2023

Figures of MeritTechnical Economic

Payback Relative Years Change

1.18 2.6 69%1.06 8.4 xx1.13 4.4 104%1.01 -100.9 xx1.04 6.1 55%1.02 13.5 xx1.09 1.2 41%1.05 2.1 xx

1.12 1.5 43%1.07 2.6 xx1.12 7.1 54%1.07 15.3 xx1.03 29.1 95%1.02 539.1 xx1.08 0.644 27.91%1.05 0.893 xx

1.03 5.4 xx1.04 11.2 2.10.99 -38.7 xx1.01 -14.2 0.41.03 7.6 xx1.03 8.5 1.11.02 1.5 xx1.03 1.9 1.3

1.04 2.6 xx1.07 4.8 1.81.04 15.3 xx1.07 43.4 2.81.01 539.1 xx1.02 -77.6 -0.11.04 0.89 xx1.05 1.28 1.4

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