AXG-9-29432-01 document.xls COMPARATIVE ANALYSIS OF for REMOVING NONCONDENS from FLASHED-STEAM GEOTHERM by Subcontrac Martin Vorum, and Eugene A. Fritzle Subcontract Number AX Under Prime Contract Number for Contrac Midwest Research National Renewable Energy
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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
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
AXG-9-29432-01 document.xls
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
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
AXG-9-29432-01 document.xls
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.
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
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
AXG-9-29432-01 document.xls
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
AXG-9-29432-01 document.xls
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
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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
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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
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SHADED CELLS ARE USER ADJUSTABLE
TECHNICAL AND FINANCIAL PERFORMANCE FACTORS
Annual Stream Factor 90% power plant percent of time on-line
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.
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
Sheet 2.2 Bases&Input
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general inflation, e.g. wages, materials, equipment, etc.
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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
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)
Base Case -- Power Steam Load
Estimate
With 2 stage SJAE with Interstage Direct Contact Condensers
Turbo Compressor
(3-stage)
See reboiler summary data at far right.
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.
Sheet 3.1 Main Case Summaries
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49,999 44,707 46,014lb/hr steam & gas 0 98,633 69,073
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).
Sheet 3.2 Sensitivity Case Summaries
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SENSITIVITY GROUP S - 3 -- HIGH TEMPERATURE, MID GAS 80 DEG. WET BULB
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.
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
FIGURE 90HIGH TEMPERATURE CASES -- TECHNICAL FIGURE OF MERIT
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.
AXG-9-29432-01document.xls Page 3.3.83 18:12:05
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Plot Data -- Engineering and Economic Figures of Merit versus Noncondensable Gas Levels
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)
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.
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.
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
FIGURE 90HIGH TEMPERATURE CASES -- TECHNICAL FIGURE OF MERIT
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.
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Plot Data -- Engineering and Economic Figures of Merit versus Noncondensable Gas Levels
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.
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
FIGURE 90HIGH TEMPERATURE CASES -- TECHNICAL FIGURE OF MERIT
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.
AXG-9-29432-01]document.xls
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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
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 for gas removal.
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 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.
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.
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)
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.
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
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
xx xx 92,000 10.6% 99,000 = raw gas + steam
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
gas & steam feed rates steam to vacuum flow to reboiler vent
reboiler feedsteam gas gas steamlb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr
xx xx 28,000 3.2% 29,000 = raw gas + steam
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
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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
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gas & steam feed rates steam to vacuum flow to reboiler vent
reboiler feedsteam gas gas steamlb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr
xx xx 115,000 8.2% 118,000 = raw gas + steam
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
gas & steam feed rates steam to vacuum flow to reboiler vent
reboiler feedsteam gas gas steamlb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr
xx xx 362,000 25.9% 390,000 = raw gas + steam
xx xx 168,000 12.0% 180,000
1,399,000 106,000 6,000 0.4% 104,000 98.0% 104,000 total = 1,505,000 6,000 = raw gas + steam 208,000 = raw steam + gas
xx xx 338,000 24.2% 363,000
xx xx 233,000 16.7% 250,000
gas & steam feed rates steam to vacuum flow to reboiler vent
reboiler feedsteam gas gas steamlb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr
xx xx 550,000 39.7% 621,000 = raw gas + steam
xx xx 270,000 19.5% 305,000
1,385,000 178,000 9,000 0.7% 175,000 98.0% 175,000 total = 1,563,000 10,000 = raw gas + steam 350,000 = raw steam + gas
3.4b % SteamUse
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xx xx 510,000 36.8% 576,000
xx xx 389,000 28.1% 439,000
3.4b % SteamUse
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gas & steam feed rates steam to vacuum flow to reboiler vent
reboiler feedsteam gas gas steamlb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr
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
gas & steam feed rates steam to vacuum flow to reboiler vent
reboiler feedsteam gas gas steamlb/hr lb/hr lb/hr % of feed steam lb/hr % of feed lb/hr
xx xx 274,000 32.8% 349,000 = raw gas + steam
xx xx 183,000 21.9% 233,000 = raw gas + steam
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
xx xx 234,000 28.0% 297,000 = raw gas + steam
xx xx 243,000 29.1% 309,000 = raw gas + steam
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
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16.7%28.1%73.2%
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.
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
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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.
geothermal source reservoir prolonged productivityproduction wells reduced replacementgathering system growth, durabilityall of above productivity/pressure loss
INFLUENCES OF THE CHOICE OF ALTERNATIVE METHODS FOR NONCONDENSABLE GAS REMOVAL
IN COMPARISON TO STEAM JET EJECTOR BASELINE SYSTEMS
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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.
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
5 CASES : HIGH TEMPERATURE, HIGH PRESSURE, HIGH GAS
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.
S2.2 ALTERNATE S2.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.
S2.3 ALTERNATE S2.3 -- replace the steam jet ejectors with biphase eductors.
S2.4 ALTERNATE S2.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.
PLACE HOLDER
5 CASES : LOW TEMPERATURE, LOW PRESSURE, LOW GAS
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.
S6.2 ALTERNATE S6.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.
S6.3 ALTERNATE S6.3 -- replace the steam jet ejectors with biphase eductors.
S6.4 ALTERNATE S6.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.
PLACE HOLDER
5 CASES : LOW TEMPERATURE, LOW PRESSURE, LOW GAS
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.
S9.2 ALTERNATE S9.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.
S9.3 ALTERNATE S9.3 -- replace the steam jet ejectors with biphase eductors.
S9.4 ALTERNATE S9.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.
5 CASES : HIGH TEMPERATURE, HIGH PRESSURE, HIGH GAS
BASE CASE S9 -- same as Base Case, substituting a
Sheet 4.1 Op'sDetails
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B-1
B1.1
B1.2
B1.3
B1.4
Case No.
OVERALL PLANT DEFINITION
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
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Case No.
B-2
B2.1
B2.2
B2.3
B2.4
OVERALL PLANT DEFINITION
P = PSIA
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
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
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Case No.
B-3
B3.1
B3.2
B3.3
B3.4
OVERALL PLANT DEFINITION
P = PSIA
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
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
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Case No.
B-4
B4.1
B4.2
B4.3
B4.4
OVERALL PLANT DEFINITION
P = PSIA
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
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
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Case No.
B-5
B5.1
B5.2
B5.3
B5.4
OVERALL PLANT DEFINITION
P = PSIA
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
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
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Case No.
B-6
B6.1
B6.2
B6.3
B6.4
OVERALL PLANT DEFINITION
P = PSIA
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
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
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Case No.
B-7
B7.1
B7.2
B7.3
B7.4
OVERALL PLANT DEFINITION
P = PSIA
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 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
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Case No.
B-8
B8.1
B8.2
B8.3
B8.4
OVERALL PLANT DEFINITION
P = PSIA
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 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
Sheet 4.1 Op'sDetails
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Case No.
S-1
S1.1
S1.2
S1.3
S1.4
OVERALL PLANT DEFINITION
P = PSIA
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
PLACE HOLDER PLACE HOLDER
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
PLACE HOLDER PLACE HOLDER
Sheet 4.1 Op'sDetails
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Case No.
S-2
S2.1
S2.2
S2.3
S2.4
OVERALL PLANT DEFINITION
P = PSIA
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
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
PLACE HOLDER PLACE HOLDER
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Case No.
S-3
S3.1
S3.2
S3.3
S3.4
OVERALL PLANT DEFINITION
P = PSIA
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
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
PLACE HOLDER PLACE HOLDER
Sheet 4.1 Op'sDetails
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Case No.
S-4
S4.1
S4.2
S4.3
S4.4
OVERALL PLANT DEFINITION
P = PSIA
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
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
PLACE HOLDER PLACE HOLDER
Sheet 4.1 Op'sDetails
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Case No.
S-5
S5.1
S5.2
S5.3
S5.4
OVERALL PLANT DEFINITION
P = PSIA
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
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.
PLACE HOLDER PLACE HOLDER
Sheet 4.1 Op'sDetails
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Case No.
S-6
S6.1
S6.2
S6.3
S6.4
OVERALL PLANT DEFINITION
P = PSIA
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
ALTERNATE S6.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.
ALTERNATE S6.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.
PLACE HOLDER PLACE HOLDER
Sheet 4.1 Op'sDetails
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Case No.
S-7
S7.1
S7.2
S7.3
S7.4
OVERALL PLANT DEFINITION
P = PSIA
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
ALTERNATE S7.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.
ALTERNATE S7.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.
PLACE HOLDER PLACE HOLDER
Sheet 4.1 Op'sDetails
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Case No.
S-8
S8.1
S8.2
S8.3
S8.4
OVERALL PLANT DEFINITION
P = PSIA
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
ALTERNATE S8.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.
ALTERNATE S8.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.
PLACE HOLDER PLACE HOLDER
Sheet 4.1 Op'sDetails
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Case No.
S-9
S9.1
S9.2
S9.3
S9.4
OVERALL PLANT DEFINITION
P = PSIA
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
ALTERNATE S9.2 -- a vertical-tube, falling film reboiler is installed after the flash separator.
ALTERNATE S9.4 -- use two stages of steam jet ejectors and a 3rd-stage turbocompressor.
Sheet 4.1 Op'sDetails
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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."
Sheet 4.1 Op'sDetails
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Case No.
B-2
B2.1
B2.2
B2.3
B2.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
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
P 113 803,000 = clean steam turbine feed reboiler vent
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
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."
Sheet 4.1 Op'sDetails
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Case No.
B-3
B3.1
B3.2
B3.3
B3.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
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
P 111 853,000 = clean steam turbine feed reboiler vent
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
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."
Sheet 4.1 Op'sDetails
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Case No.
B-4
B4.1
B4.2
B4.3
B4.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
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
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."
Sheet 4.1 Op'sDetails
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Case No.
B-5
B5.1
B5.2
B5.3
B5.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
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
P 23 1,291,000 = clean steam turbine feed reboiler vent
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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.182 18:12:07
04/17/2023
Case No.
B-6
B6.1
B6.2
B6.3
B6.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
PLACE HOLDER PLACE HOLDER
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
P 24 1,203,000 = clean steam turbine feed reboiler vent
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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.183 18:12:07
04/17/2023
Case No.
B-7
B7.1
B7.2
B7.3
B7.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
PLACE HOLDER PLACE HOLDER
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
P 25 751,000 = clean steam turbine feed reboiler vent
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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.184 18:12:07
04/17/2023
Case No.
B-8
B8.1
B8.2
B8.3
B8.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
PLACE HOLDER PLACE HOLDER
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
P 119 614,000 = clean steam turbine feed reboiler vent
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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.185 18:12:07
04/17/2023
Case No.
S-1
S1.1
S1.2
S1.3
S1.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
PLACE HOLDER PLACE HOLDER
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
P 114 750,000 = clean steam turbine feed reboiler vent
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
PLACE HOLDER PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.186 18:12:07
04/17/2023
Case No.
S-2
S2.1
S2.2
S2.3
S2.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
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
P 23 1,375,000 = clean steam turbine feed reboiler vent
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
PLACE HOLDER PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.187 18:12:07
04/17/2023
Case No.
S-3
S3.1
S3.2
S3.3
S3.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
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
P 128 860,000 = clean steam turbine feed reboiler vent
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
PLACE HOLDER PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.188 18:12:07
04/17/2023
Case No.
S-4
S4.1
S4.2
S4.3
S4.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
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
P 27 1,536,000 = clean steam turbine feed reboiler vent
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
PLACE HOLDER PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.189 18:12:07
04/17/2023
Case No.
S-5
S5.1
S5.2
S5.3
S5.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
PLACE HOLDER PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.190 18:12:07
04/17/2023
Case No.
S-6
S6.1
S6.2
S6.3
S6.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
PLACE HOLDER PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.191 18:12:07
04/17/2023
Case No.
S-7
S7.1
S7.2
S7.3
S7.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
PLACE HOLDER PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.192 18:12:08
04/17/2023
Case No.
S-8
S8.1
S8.2
S8.3
S8.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
PLACE HOLDER PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.193 18:12:08
04/17/2023
Case No.
S-9
S9.1
S9.2
S9.3
S9.4
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.194 18:12:08
04/17/2023
Case No.
FLASHED STEAM AND GROSS POWER AUXILIARY STEAM & ELECTRICITY DEMAND
Total Flow
lbs / hour lbs / hour lbs / hour
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
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.195 18:12:08
04/17/2023
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)
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.196 18:12:08
04/17/2023
Case No.
B-2
B2.1
B2.2
B2.3
B2.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.197 18:12:08
04/17/2023
Case No.
B-3
B3.1
B3.2
B3.3
B3.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.198 18:12:08
04/17/2023
Case No.
B-4
B4.1
B4.2
B4.3
B4.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.199 18:12:08
04/17/2023
Case No.
B-5
B5.1
B5.2
B5.3
B5.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.200 18:12:08
04/17/2023
Case No.
B-6
B6.1
B6.2
B6.3
B6.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.201 18:12:08
04/17/2023
Case No.
B-7
B7.1
B7.2
B7.3
B7.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.202 18:12:08
04/17/2023
Case No.
B-8
B8.1
B8.2
B8.3
B8.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.203 18:12:08
04/17/2023
Case No.
S-1
S1.1
S1.2
S1.3
S1.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.204 18:12:08
04/17/2023
Case No.
S-2
S2.1
S2.2
S2.3
S2.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
stage turboPLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.205 18:12:08
04/17/2023
Case No.
S-3
S3.1
S3.2
S3.3
S3.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
stage turboPLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.206 18:12:08
04/17/2023
Case No.
S-4
S4.1
S4.2
S4.3
S4.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(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
stage turboPLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.207 18:12:08
04/17/2023
Case No.
S-5
S5.1
S5.2
S5.3
S5.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(at left)
PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.208 18:12:08
04/17/2023
Case No.
S-6
S6.1
S6.2
S6.3
S6.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(at left)
PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.209 18:12:08
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Case No.
S-7
S7.1
S7.2
S7.3
S7.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(at left)
PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.210 18:12:08
04/17/2023
Case No.
S-8
S8.1
S8.2
S8.3
S8.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(at left)
PLACE HOLDER
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.211 18:12:08
04/17/2023
Case No.
S-9
S9.1
S9.2
S9.3
S9.4
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(at left)
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."
Sheet 4.1 Op'sDetails
AXG-9-29432-01document.xls Page 4.1.212 18:12:08
04/17/2023
Case No.
AUXILIARY STEAM & ELECTRICITY DEMANDNET SALES
ELECTRICITY
Kilowatts Megawatts %
POWER LOSS TO
GAS REMOVAL
AUXILIARY ELECTRICITY
CW pumps, CT fans, brine
repressurization
deducting only auxiliaries at
left
Percent of "Unit Capacity"
(at left)
Sheet 4.2 EnFigMerit
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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.
Combined Brine & Steam Flow
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.
Sheet 4.2 EnFigMerit
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OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
MAIN CASE GROUP 2 HIGH TEMP/HIGH PRESSURE/MID GASB-2 2,288,000 T = 550 29,000 T 334 29,900
2-stage ejector P = 1124 P 113
B2.1 2,288,000 T = 550 29,000 T 334 29,9003-stage turbo P = 1124 P 113
B2.2 2,287,000 T = 550 29,000 T 334 29,900reboiler P = 1124 P 113
B2.3 2,288,000 T = 550 29,000 T 334 29,900biphase P = 1124 P 113eductor
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
2-stage ejector P = 1072 P 111
B3.1 2,284,000 T = 550 9,600 T 335 10,0003-stage turbo P = 1072 P 111
B3.2 2,284,000 T = 550 9,600 T 335 10,000reboiler P = 1072 P 111
B3.3 2,284,000 T = 550 9,600 T 335 10,000biphase P = 1072 P 111eductor
B3.4 2,284,000 T = 550 9,600 T 335 10,000hybrid P = 1072 P 111
Sheet 4.2 EnFigMerit
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OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
MAIN CASE GROUP 4 LOW TEMP/LOW PRESSURE/LOW GASB-4 5,418,000 T = 350 6,500 T 235 10,000
2-stage ejector P = 137 P 23
B4.1 5,418,000 T = 350 6,500 T 235 10,0003-stage turbo P = 137 P 23
B4.2 5,418,000 T = 350 6,500 T 235 10,000reboiler P = 137 P 23
B4.3 5,418,000 T = 350 6,500 T 235 10,000biphase P = 137 P 23eductor
B4.4 5,418,000 T = 350 6,500 T 235 10,000hybrid P = 137 P 23
Sheet 4.2 EnFigMerit
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OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
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
2-stage ejector P = 142 P 23
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
Sheet 4.2 EnFigMerit
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04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
MAIN CASE GROUP 6 LOW TEMP/LOW PRESSURE/HI GAS
B-6 5,365,000 T = 350 33,400 T 234 50,100
2-stage ejector P = 146 P 24
B6.1 5,365,000 T = 350 33,400 T 234 50,100
3-stage turbo P = 146 P 24
B6.2 5,354,000 T = 350 33,400 T 234 50,100
reboiler P = 146 P 24
B6.3 5,365,000 T = 350 33,400 T 234 50,100
biphase P = 146 P 24
eductor
B6.4 5,365,000 T = 350 33,400 T 234 50,100
hybrid P = 146 P 24
Sheet 4.2 EnFigMerit
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OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
MAIN CASE GROUP 7 LOW TEMP/LOW PRESSURE/VERY HIGH GAS
B-7 5,201,000 T = 350 108,500 T 232 149,200
2-stage ejector P = 170 P 25
B7.1 5,201,000 T = 350 108,500 T 232 149,200
3-stage turbo P = 170 P 25
B7.2 5,119,000 T = 350 108,500 T 232 149,200
reboiler P = 170 P 25
B7.3 5,201,000 T = 350 108,500 T 232 149,200
biphase P = 170 P 25
eductor
B7.4 5,201,000 T = 350 108,500 T 232 149,200
hybrid P = 170 P 25
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.219 18:12:08
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
MAIN CASE GROUP 8 HIGH TEMP/HIGH PRESSURE/VERY HIGH GAS
B-8 2,297,000 T = 550 99,700 T 333 99,600
2-stage ejector P = 1316 P 119
B8.1 2,297,000 T = 550 99,700 T 333 99,600
3-stage turbo P = 1316 P 119
B8.2 2,289,000 T = 550 99,700 T 333 99,600
reboiler P = 1316 P 119
B8.3 2,297,000 T = 550 99,700 T 333 99,600
biphase P = 1316 P 119
eductor
B8.4 2,297,000 T = 550 99,700 T 333 99,600
hybrid P = 1316 P 119
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.220 18:12:08
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OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
LOW EJECTOR EFFICIENCY
SENSITIVITY CASE GROUP 1 -- HIGH TEMP / HIGH GAS
S-1 2,291,000 T = 550 48,800 T 334 49,900
2-stage ejector P = 1177 P 114
S1.1 2,291,000 T = 550 48,800 T 334 49,900
3-stage turbo P = 1177 P 114
S1.2 2,289,000 T = 550 48,800 T 334 49,900
reboiler P = 1177 P 114
S1.3 2,291,000 T = 550 48,800 T 334 49,900
biphase P = 1177 P 114
eductor
S1.4 2,291,000 T = 550 48,800 T 334 49,900
hybrid P = 1177 P 114
Sheet 4.2 EnFigMerit
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OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
LOW EJECTOR EFFICIENCY
SENSITIVITY CASE GROUP 2 -- LOW TEMP / LOW GAS
S-2 5,418,000 T = 350 6,500 T 235 10,100
2-stage ejector P = 137 P 23
S2.1 5,418,000 T = 350 6,500 T 235 10,100
3-stage turbo P = 137 P 23
S2.2 5,418,000 T = 350 6,500 T 235 10,100
reboiler P = 137 P 23
S2.3 5,418,000 T = 350 6,500 T 235 10,100
biphase P = 137 P 23
eductor
S2.4 5,418,000 T = 350 6,500 T 235 10,100
hybrid P = 137 P 23
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.222 18:12:08
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
SENSITIVITY CASE GROUP 3 -- HIGH TEMP / MID GAS
S-3 2,505,000 T = 550 28,900 T 344 30,400
2-stage ejector P = 1124 P 128
S3.1 2,505,000 T = 550 28,900 T 344 30,400
3-stage turbo P = 1124 P 128
S3.2 2,505,000 T = 550 28,900 T 344 30,400
reboiler P = 1124 P 128
S3.3 2,505,000 T = 550 28,900 T 344 30,400
biphase P = 1124 P 128
eductor
S3.4 2,505,000 T = 550 28,900 T 344 30,400
hybrid P = 1124 P 128
WET BULB TEMPERATURE 80 oF
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.223 18:12:08
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
ppmv
GROSS PLANT FEED
(combined well flow to flash)
STEAM TEMPERATURE, PRESSURE & GAS CONTENT
Case No.
Combined Brine & Steam Flow
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
SENSITIVITY CASE GROUP 4 -- LOW TEMP / LOW GAS
S-4 6,251,000 T = 350 6,400 T 244 10,100
2-stage ejector P = 137 P 27
S4.1 6,251,000 T = 350 6,400 T 244 10,100
3-stage turbo P = 137 P 27
S4.2 6,250,000 T = 350 6,400 T 244 10,100
reboiler P = 137 P 27
S4.3 6,251,000 T = 350 6,400 T 244 10,100
biphase P = 137 P 27
eductor
S4.4 6,251,000 T = 350 6,400 T 244 10,100
hybrid P = 137 P 27
WET BULB TEMPERATURE 80 oF
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.224 18:12:08
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ENGINEERING FIGURES OF MERIT
OVERALL PLANT DEFINITION
MAIN CASE GROUP 1B-1
B1.1
B1.2
B1.3
B1.4
Case No.
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.
Percent of Gross "Unit Capacity" ratio of alternate case
resid. capacity to "base case" resid.
capacity
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.
RETURN
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.225 18:12:08
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OVERALL PLANT DEFINITION
Case No.
MAIN CASE GROUP 2B-2
B2.1
B2.2
B2.3
B2.4
MAIN CASE GROUP 3B-3
B3.1
B3.2
B3.3
B3.4
FLASHED STEAM AND GROSS POWER NET SALES
ELECTRICITY ( A ) ( B ) ( C )
B = 1 - ( A )
lbs / hour Megawatts Megawatts % %
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
Percent of Gross "Unit Capacity" ratio of alternate case
resid. capacity to "base case" resid.
capacity
RETURN
PLACE HOLDER PLACE HOLDER PLACE HOLDER
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
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.228 18:12:09
04/17/2023
OVERALL PLANT DEFINITION
Case No.
MAIN CASE GROUP 6
B-6
B6.1
B6.2
B6.3
B6.4
FLASHED STEAM AND GROSS POWER NET SALES
ELECTRICITY ( A ) ( B ) ( C )
B = 1 - ( A )
lbs / hour Megawatts Megawatts % %
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
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
1,203,000 = clean steam turbine feed
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
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.229 18:12:09
04/17/2023
OVERALL PLANT DEFINITION
Case No.
MAIN CASE GROUP 7
B-7
B7.1
B7.2
B7.3
B7.4
FLASHED STEAM AND GROSS POWER NET SALES
ELECTRICITY ( A ) ( B ) ( C )
B = 1 - ( A )
lbs / hour Megawatts Megawatts % %
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
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
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.230 18:12:09
04/17/2023
OVERALL PLANT DEFINITION
Case No.
MAIN CASE GROUP 8
B-8
B8.1
B8.2
B8.3
B8.4
FLASHED STEAM AND GROSS POWER NET SALES
ELECTRICITY ( A ) ( B ) ( C )
B = 1 - ( A )
lbs / hour Megawatts Megawatts % %
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
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
614,000 = clean steam turbine feed
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
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.231 18:12:09
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OVERALL PLANT DEFINITION
Case No.
S-1
S1.1
S1.2
S1.3
S1.4
FLASHED STEAM AND GROSS POWER NET SALES
ELECTRICITY ( A ) ( B ) ( C )
B = 1 - ( A )
lbs / hour Megawatts Megawatts % %
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
LOW EJECTOR EFFICIENCY
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
750,000 = clean steam turbine feed
968,000 50.0 35.8 28.5% 71.5% 1.04
968,000 50.0 37.2 25.6% 74.4% 1.09
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.232 18:12:09
04/17/2023
OVERALL PLANT DEFINITION
Case No.
S-2
S2.1
S2.2
S2.3
S2.4
FLASHED STEAM AND GROSS POWER NET SALES
ELECTRICITY ( A ) ( B ) ( C )
B = 1 - ( A )
lbs / hour Megawatts Megawatts % %
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
LOW EJECTOR EFFICIENCY
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
1,375,000 = clean steam turbine feed
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
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.233 18:12:09
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OVERALL PLANT DEFINITION
Case No.
S-3
S3.1
S3.2
S3.3
S3.4
FLASHED STEAM AND GROSS POWER NET SALES
ELECTRICITY ( A ) ( B ) ( C )
B = 1 - ( A )
lbs / hour Megawatts Megawatts % %
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
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
860,000 = clean steam turbine feed
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
WET BULB TEMPERATURE 80 oF
Sheet 4.2 EnFigMerit
AXG-9-29432-01document.xls Page 4.2.234 18:12:09
04/17/2023
OVERALL PLANT DEFINITION
Case No.
S-4
S4.1
S4.2
S4.3
S4.4
FLASHED STEAM AND GROSS POWER NET SALES
ELECTRICITY ( A ) ( B ) ( C )
B = 1 - ( A )
lbs / hour Megawatts Megawatts % %
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
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
1,536,000 = clean steam turbine feed
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
WET BULB TEMPERATURE 80 oF
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.235 18:12:09
04/17/2023
ECONOMIC FIGURE OF MERIT
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
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
lbs / hour (at 15% steam quality)
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.
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.236 18:12:09
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
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
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.237 18:12:09
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OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
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
2-stage ejectors P = 1072 P 111
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.238 18:12:09
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OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
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
2-stage ejectors P = 142 P 23
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
2-stage ejectors P 146 P 24
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
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.239 18:12:09
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
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
compressorPLACE HOLDER PLACE HOLDER PLACE HOLDER
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.240 18:12:09
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
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
2-stage ejectors P = 170 P 25
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
compressorPLACE HOLDER PLACE HOLDER PLACE HOLDER
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
2-stage ejectors P 1,316 P 119
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
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.241 18:12:09
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
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
PLACE HOLDER PLACE HOLDER PLACE HOLDER
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.242 18:12:09
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
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
2-stage ejectors P 1,177 P 114
S1.1 ALTERNATIVE A 2,291,000 T 550 48,800 T 334 49,900 968,000
3-stage turbo- P 1,177 P 114
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
biphase eductor P 1,177 P 114
S1.4 ALTERNATIVE D 2,291,000 T 550 48,800 T 334 49,900 968,000
hybrid turbo- P 1,177 P 114
compressorPLACE HOLDER PLACE HOLDER PLACE HOLDER
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
2-stage ejectors P 137 P 23
S2.1 ALTERNATIVE A 5,418,000 T 350 6,500 T 235 10,100 1,446,000
3-stage turbo- P 137 P 23
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
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.243 18:12:09
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
weight (ppmw) as
CO2
oF, PSIA
biphase eductor P 137 P 23
S2.4 ALTERNATIVE D 5,418,000 T 350 6,500 T 235 10,100 1,446,000
hybrid turbo- P 137 P 23
compressorPLACE HOLDER PLACE HOLDER PLACE HOLDER
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.244 18:12:09
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
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
2-stage ejectors P 1,124 P 128
S3.1 ALTERNATIVE A 2,505,000 T 550 28,900 T 344 30,400 1,001,000
3-stage turbo- P 1,124 P 128
compressor
S3.2 ALTERNATIVE B 2,505,000 T 550 28,900 T 344 30,400 1,001,000
reboiler P 1,124 P 128 860,000
S3.3 ALTERNATIVE C 2,505,000 T 550 28,900 T 344 30,400 1,001,000
biphase eductor P 1,124 P 128
S3.4 ALTERNATIVE D 2,505,000 T 550 28,900 T 344 30,400 1,001,000
hybrid turbo- P 1,124 P 128
compressorPLACE HOLDER PLACE HOLDER PLACE HOLDER
SENSITIVITY CASE GROUP S - 4
LOW TEMPERATURE / LOW GAS CONTENT
S-4 BASE CASE 6,251,000 T 350 6,400 T 244 10,100 1,615,000
2-stage ejectors P 137 P 27
S4.1 ALTERNATIVE A 6,251,000 T 350 6,400 T 244 10,100 1,615,000
3-stage turbo- P 137 P 27
compressor
S4.2 ALTERNATIVE B 6,250,000 T 350 6,400 T 244 10,100 1,615,000
reboiler P 137 P 27 1,536,000
S4.3 ALTERNATIVE C 6,251,000 T 350 6,400 T 244 10,100 1,615,000
biphase eductor P 137 P 27
S4.4 ALTERNATIVE D 6,251,000 T 350 6,400 T 244 10,100 1,615,000
80 oF WET BULB TEMPERATURE
80 oF WET BULB TEMPERATURE
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.245 18:12:09
04/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
TOTAL FLOW
Configuration
P = PSIA ppmv lbs / hour
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
lbs / hour (at 15% steam quality)
parts per million by
weight (ppmw) as
CO2
oF, PSIA
hybrid turbo- P 137 P 27
compressor
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.246 18:12:09
04/17/2023
ECONOMIC FIGURE OF MERIT
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
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.
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.
RETURN
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.258 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
RETURN
$ 68,000 -38.7
$ 412,000 7.6
$ 380,000 1.5
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.259 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
RETURN
MAIN CASE GROUP 3N/A N/A
$ 208,000 11.4
$ 8,000 -23.3
$ 348,000 7.7
$ 180,000 1.5
MAIN CASE GROUP 4N/A N/A
$ 832,000 2.6
$ 860,000 15.3
$ 224,000 539.1
$ 660,000 0.9
PLACE HOLDER
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.260 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
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
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.261 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
RETURN
$ 336,000 33.3
$ 1,992,000 1.2
PLACE HOLDER
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.262 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
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
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.263 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
RETURN
$ 680,000 4.5
PLACE HOLDER
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.264 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
RETURN
LOW EJECTOR EFFICIENCY
SENSITIVITY CASE GROUP S - 1
N/A N/A
$ 1,972,000 2.6
$ 1,360,000 4.4
$ 476,000 6.1
$ 940,000 1.2
PLACE HOLDER
LOW EJECTOR EFFICIENCY
SENSITIVITY CASE GROUP S - 2
N/A N/A
$ 1,424,000 1.5
$ 1,456,000 7.1
$ 364,000 29.1
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.265 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
RETURN
$ 920,000 0.6
PLACE HOLDER
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.266 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
RETURN
SENSITIVITY CASE GROUP S - 3
N/A N/A
$ 368,000 11.2
$ (180,000) -14.2
$ 404,000 8.5
$ 280,000 1.9
PLACE HOLDER
SENSITIVITY CASE GROUP S - 4
N/A N/A
$ 576,000 4.8
$ 564,000 43.4
$ 176,000 -77.6
$ 452,000 1.3
80 oF WET BULB TEMPERATURE
80 oF WET BULB TEMPERATURE
Sheet 4.3 $ FigMerit
AXG-9-29432-01document.xls Page 4.3.267 18:12:09
04/17/2023
$ / year
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
FIGURE OF
MERIT
Sales value of unexpended
power
PAYOUT PERIOD
"simple payback" (years)
RETURN
4.3a Alt $ FigMerit
AXG-9-29432-01document.xls
Page 4.3a.268 18:12:0904/17/2023
ECONOMIC FIGURE OF MERIT ---- NET PRESENT VALUES
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
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
GROSS PLANT FEED (combined well flows entering flash to produce steam for a 50 MW turbine/generator)
STEAM PRESSURE AND TEMPERATURE
Combined Brine & Steam Flow
T = oF Combined
Brine & Steam Gas Conc'n.
Flash Condition
s
Gas Content
lbs / hour (at 15% steam
quality)
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 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
AXG-9-29432-01document.xls
Page 4.3a.269 18:12:0904/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
Case No. Configuration
P = PSIA ppmv
GROSS PLANT FEED (combined well flows entering flash to produce steam for a 50 MW turbine/generator)
STEAM PRESSURE AND TEMPERATURE
Combined Brine & Steam Flow
T = oF Combined
Brine & Steam Gas Conc'n.
Flash Condition
s
Gas Content
lbs / hour (at 15% steam
quality)
parts per million by
weight (ppmw) as CO2
oF, PSIA
biphase eductor P 1,124 P 113
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
AXG-9-29432-01document.xls
Page 4.3a.270 18:12:1004/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
Case No. Configuration
P = PSIA ppmv
GROSS PLANT FEED (combined well flows entering flash to produce steam for a 50 MW turbine/generator)
STEAM PRESSURE AND TEMPERATURE
Combined Brine & Steam Flow
T = oF Combined
Brine & Steam Gas Conc'n.
Flash Condition
s
Gas Content
lbs / hour (at 15% steam
quality)
parts per million by
weight (ppmw) as CO2
oF, PSIA
MAIN CASE GROUP 3HIGH TEMPERATURE/PRESSURE AND LOW GAS CONTENT
B-3 BASE CASE 2,284,000 T = 550 9,600 T 335 10,000 2-stage ejectors P = 1072 P 111
B3.1 ALTERNATIVE A 2,284,000 T = 550 9,600 T 335 10,000 3-stage turbo- P = 1072 P 111compressor
B3.2 ALTERNATIVE B 2,284,000 T = 550 9,600 T 335 10,000 reboiler P = 1072 P 111
B3.3 ALTERNATIVE C 2,284,000 T = 550 9,600 T 335 10,000 biphase eductor P = 1072 P 111
B3.4 ALTERNATIVE D 2,284,000 T = 550 9,600 T 335 10,000 hybrid turbo- P = 1072 P 111compressor
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
PLACE HOLDER PLACE HOLDER
4.3a Alt $ FigMerit
AXG-9-29432-01document.xls
Page 4.3a.271 18:12:1004/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
Case No. Configuration
P = PSIA ppmv
GROSS PLANT FEED (combined well flows entering flash to produce steam for a 50 MW turbine/generator)
STEAM PRESSURE AND TEMPERATURE
Combined Brine & Steam Flow
T = oF Combined
Brine & Steam Gas Conc'n.
Flash Condition
s
Gas Content
lbs / hour (at 15% steam
quality)
parts per million by
weight (ppmw) as CO2
oF, PSIA
MAIN CASE GROUP 5LOW TEMPERATURE/PRESSURE AND MID GAS CONTENT
B-5 BASE CASE 5,395,000 T = 350 19,700 T 234 30,100 2-stage ejectors P = 142 P 23
B5.1 ALTERNATIVE A 5,395,000 T = 350 19,700 T 234 30,100 3-stage turbo- P = 142 P 23compressor
B5.2 ALTERNATIVE B 5,391,000 T = 350 19,700 T 234 30,100 reboiler P = 142 P 23
B5.3 ALTERNATIVE C 5,395,000 T = 350 19,700 T 234 30,100 biphase eductor P = 142 P 23
B5.4 ALTERNATIVE D 5,395,000 T = 350 19,700 T 234 30,100 hybrid turbo- P = 142 P 23compressor
PLACE HOLDER PLACE HOLDER
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
PLACE HOLDER PLACE HOLDER
4.3a Alt $ FigMerit
AXG-9-29432-01document.xls
Page 4.3a.272 18:12:1004/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
Case No. Configuration
P = PSIA ppmv
GROSS PLANT FEED (combined well flows entering flash to produce steam for a 50 MW turbine/generator)
STEAM PRESSURE AND TEMPERATURE
Combined Brine & Steam Flow
T = oF Combined
Brine & Steam Gas Conc'n.
Flash Condition
s
Gas Content
lbs / hour (at 15% steam
quality)
parts per million by
weight (ppmw) as CO2
oF, PSIA
MAIN CASE GROUP 7LOW TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
B-7 BASE CASE 5,201,000 T = 350 108,500 T 232 149,200 2-stage ejectors P = 170 P 25
B7.1 ALTERNATIVE A 5,201,000 T = 350 108,500 T 232 149,200 3-stage turbo- P = 170 P 25compressor
B7.2 ALTERNATIVE B 5,119,000 T = 350 108,500 T 232 149,200 reboiler P = 170 P 25
B7.3 ALTERNATIVE C 5,201,000 T = 350 108,500 T 232 149,200 biphase eductor P = 170 P 25
B7.4 ALTERNATIVE D 5,201,000 T = 350 108,500 T 232 149,200 hybrid turbo- P = 170 P 25compressor
PLACE HOLDER PLACE HOLDER
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
PLACE HOLDER PLACE HOLDER
4.3a Alt $ FigMerit
AXG-9-29432-01document.xls
Page 4.3a.273 18:12:1004/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
Case No. Configuration
P = PSIA ppmv
GROSS PLANT FEED (combined well flows entering flash to produce steam for a 50 MW turbine/generator)
STEAM PRESSURE AND TEMPERATURE
Combined Brine & Steam Flow
T = oF Combined
Brine & Steam Gas Conc'n.
Flash Condition
s
Gas Content
lbs / hour (at 15% steam
quality)
parts per million by
weight (ppmw) as CO2
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
PLACE HOLDER PLACE HOLDER
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
PLACE HOLDER PLACE HOLDER
4.3a Alt $ FigMerit
AXG-9-29432-01document.xls
Page 4.3a.274 18:12:1004/17/2023
OVERALL PLANT DEFINITION FLASHED STEAM AND GROSS POWER
Case No. Configuration
P = PSIA ppmv
GROSS PLANT FEED (combined well flows entering flash to produce steam for a 50 MW turbine/generator)
STEAM PRESSURE AND TEMPERATURE
Combined Brine & Steam Flow
T = oF Combined
Brine & Steam Gas Conc'n.
Flash Condition
s
Gas Content
lbs / hour (at 15% steam
quality)
parts per million by
weight (ppmw) as CO2
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
PLACE HOLDER PLACE HOLDER
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
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 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.
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
MAIN CASE GROUP 2N/A N/A N/A
12,600,000 $ 504,000 $ (130,000)
1,700,000 $ 68,000 $ (5,040,000)
10,300,000 $ 412,000 $ (400,000)
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
ECONOMIC FIGURE OF
MERIT
Net Unexpended Power Available
for Sale
Sales value of unexpended
power
NET PRESENT VALUE
Kilowatt-hours per year
NPV at end of term
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 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
AXG-9-29432-01document.xls
Page 4.3a.283 18:12:1004/17/2023
$ / 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"
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
ECONOMIC FIGURE OF
MERIT
Net Unexpended Power Available
for Sale
Sales value of unexpended
power
NET PRESENT VALUE
Kilowatt-hours per year
NPV at end of term
9,500,000 $ 380,000 $ 1,100,000
4.3a Alt $ FigMerit
AXG-9-29432-01document.xls
Page 4.3a.284 18:12:1004/17/2023
$ / 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"
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
ECONOMIC FIGURE OF
MERIT
Net Unexpended Power Available
for Sale
Sales value of unexpended
power
NET PRESENT VALUE
Kilowatt-hours per year
NPV at end of term
MAIN CASE GROUP 3N/A N/A N/A
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
MAIN CASE GROUP 4N/A N/A N/A
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
PLACE HOLDER PLACE HOLDER
4.3a Alt $ FigMerit
AXG-9-29432-01document.xls
Page 4.3a.285 18:12:1004/17/2023
$ / 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"
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
ECONOMIC FIGURE OF
MERIT
Net Unexpended Power Available
for Sale
Sales value of unexpended
power
NET PRESENT VALUE
Kilowatt-hours per year
NPV at end of term
MAIN CASE GROUP 5N/A N/A N/A
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
PLACE HOLDER PLACE HOLDER
MAIN CASE GROUP 6N/A N/A N/A
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
PLACE HOLDER PLACE HOLDER
4.3a Alt $ FigMerit
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$ / 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"
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
ECONOMIC FIGURE OF
MERIT
Net Unexpended Power Available
for Sale
Sales value of unexpended
power
NET PRESENT VALUE
Kilowatt-hours per year
NPV at end of term
MAIN CASE GROUP 7N/A N/A N/A
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)
PLACE HOLDER PLACE HOLDER
MAIN CASE GROUP 8N/A N/A N/A
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
PLACE HOLDER PLACE HOLDER
4.3a Alt $ FigMerit
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$ / 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"
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
ECONOMIC FIGURE OF
MERIT
Net Unexpended Power Available
for Sale
Sales value of unexpended
power
NET PRESENT VALUE
Kilowatt-hours per year
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
PLACE HOLDER PLACE HOLDER
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
PLACE HOLDER PLACE HOLDER
4.3a Alt $ FigMerit
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$ / 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"
VALUE OF UNEXPENDED PARASITIC POWER AS A
SALABLE PRODUCT
ECONOMIC FIGURE OF
MERIT
Net Unexpended Power Available
for Sale
Sales value of unexpended
power
NET PRESENT VALUE
Kilowatt-hours per year
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
PLACE HOLDER PLACE HOLDER
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
80 oF WET BULB TEMPERATURE
80 oF WET BULB TEMPERATURE
4.3b Present Values
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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 =
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
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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)
MAIN CASE GROUP 1HIGH TEMPERATURE/PRESSURE AND HIGH GAS CONTENT
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
MAIN CASE GROUP 2HIGH TEMPERATURE/PRESSURE AND MID GAS CONTENT
B2.1 ALTERNATIVE A $ 2,400,000 $ 504,000 $ 120,000 - $ - $ - $ 120,000 3-stage turbo-compressor
B2.2 ALTERNATIVE B $ 5,394,000 $ 68,000 $ 270,000 - $ - $ - $ 270,000 reboiler
B2.3 ALTERNATIVE C $ 2,262,000 $ 412,000 $ 113,000 - $ - $ - $ 113,000 biphase eductor
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
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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)
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
MAIN CASE GROUP 3HIGH TEMPERATURE/PRESSURE AND LOW GAS CONTENT
B3.1 ALTERNATIVE A $ 1,740,000 $ 208,000 $ 87,000 - $ - $ - $ 87,000 3-stage turbo-compressor
B3.2 ALTERNATIVE B $ 5,593,000 $ 8,000 $ 280,000 - $ - $ - $ 280,000 reboiler
B3.3 ALTERNATIVE C $ 2,119,000 $ 348,000 $ 106,000 - $ - $ - $ 106,000 biphase eductor
B3.4 ALTERNATIVE D $ 300,000 $ 180,000 $ 15,000 - $ - $ - $ 15,000 hybrid turbo-compressor
MAIN CASE GROUP 4LOW TEMPERATURE/PRESSURE AND LOW GAS CONTENT
B4.1 ALTERNATIVE A $ 2,040,000 $ 832,000 $ 102,000 - $ - $ - $ 102,000 3-stage turbo-compressor
B4.2 ALTERNATIVE B $ 7,812,000 $ 860,000 $ 391,000 - $ - $ - $ 391,000 reboiler
B4.3 ALTERNATIVE C $ 4,313,000 $ 224,000 $ 216,000 - $ - $ - $ 216,000 biphase eductor
B4.4 ALTERNATIVE D $ 600,000 $ 660,000 $ 30,000 - $ - $ - $ 30,000 hybrid turbo-compressor
4.3b Present Values
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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)
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
MAIN CASE GROUP 5LOW TEMPERATURE/PRESSURE AND MID GAS CONTENT
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
B5.3 ALTERNATIVE C $ 4,259,000 $ 344,000 $ 213,000 - $ - $ - $ 213,000 biphase eductor
B5.4 ALTERNATIVE D $ 1,200,000 $ 1,620,000 $ 60,000 - $ - $ - $ 60,000 hybrid turbo-compressor
MAIN CASE GROUP 6LOW TEMPERATURE/PRESSURE AND HIGH GAS CONTENT
B6.1 ALTERNATIVE A $ 9,600,000 $ 2,972,000 $ 480,000 - $ - $ - $ 480,000 3-stage turbo-compressor
B6.2 ALTERNATIVE B $ 7,210,000 $ 3,720,000 $ 361,000 - $ - $ - $ 361,000 reboiler
B6.3 ALTERNATIVE C $ 4,200,000 $ 336,000 $ 210,000 - $ - $ - $ 210,000 biphase eductor
B6.4 ALTERNATIVE D $ 2,400,000 $ 1,992,000 $ 120,000 - $ - $ - $ 120,000 hybrid turbo-compressor
4.3b Present Values
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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)
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
MAIN CASE GROUP 7LOW TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
B7.1 ALTERNATIVE A $ 34,680,000 $ 1,808,000 $ 1,734,000 - $ - $ - $1,734,000 3-stage turbo-compressor
B7.2 ALTERNATIVE B $ 5,434,000 $ 5,708,000 $ 272,000 - $ - $ - $ 272,000 reboiler
B7.3 ALTERNATIVE C $ 3,877,000 $ 512,000 $ 194,000 - $ - $ - $ 194,000 biphase eductor
B7.4 ALTERNATIVE D $ 8,400,000 $ 1,016,000 $ 420,000 - $ - $ - $ 420,000 hybrid turbo-compressor
MAIN CASE GROUP 8HIGH TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
B8.1 ALTERNATIVE A $ 12,360,000 $ 884,000 $ 618,000 - $ - $ - $ 618,000 3-stage turbo-compressor
B8.2 ALTERNATIVE B $ 4,592,000 $ 144,000 $ 230,000 - $ - $ - $ 230,000 reboiler
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
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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
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RECURRING ANNUAL COSTS CASH FLOW RESULTS -- CONSTANT-DOLLAR ANNUAL AND DISCOUNTED CUMULATIVE NET PRESENT VALUES
MAIN CASE GROUP 1HIGH TEMPERATURE/PRESSURE AND HIGH GAS CONTENT
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
MAIN CASE GROUP 2HIGH TEMPERATURE/PRESSURE AND MID GAS CONTENT
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
MAIN CASE GROUP 3HIGH TEMPERATURE/PRESSURE AND LOW GAS CONTENT
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
MAIN CASE GROUP 4LOW TEMPERATURE/PRESSURE AND LOW GAS CONTENT
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
MAIN CASE GROUP 5LOW TEMPERATURE/PRESSURE AND MID GAS CONTENT
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
MAIN CASE GROUP 6LOW TEMPERATURE/PRESSURE AND HIGH GAS CONTENT
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
MAIN CASE GROUP 7LOW TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
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
MAIN CASE GROUP 8HIGH TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
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
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:
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
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CASH FLOW RESULTS -- CONSTANT-DOLLAR ANNUAL AND DISCOUNTED CUMULATIVE NET PRESENT VALUES
MAIN CASE GROUP 1HIGH TEMPERATURE/PRESSURE AND HIGH GAS CONTENT
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
MAIN CASE GROUP 2HIGH TEMPERATURE/PRESSURE AND MID GAS CONTENT
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
MAIN CASE GROUP 3HIGH TEMPERATURE/PRESSURE AND LOW GAS CONTENT
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
MAIN CASE GROUP 4LOW TEMPERATURE/PRESSURE AND LOW GAS CONTENT
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
MAIN CASE GROUP 5LOW TEMPERATURE/PRESSURE AND MID GAS CONTENT
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
MAIN CASE GROUP 6LOW TEMPERATURE/PRESSURE AND HIGH GAS CONTENT
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
MAIN CASE GROUP 7LOW TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
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
MAIN CASE GROUP 8HIGH TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
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
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:
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
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CASH FLOW RESULTS -- CONSTANT-DOLLAR ANNUAL AND DISCOUNTED CUMULATIVE NET PRESENT VALUES
MAIN CASE GROUP 1HIGH TEMPERATURE/PRESSURE AND HIGH GAS CONTENT
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
MAIN CASE GROUP 2HIGH TEMPERATURE/PRESSURE AND MID GAS CONTENT
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
MAIN CASE GROUP 3HIGH TEMPERATURE/PRESSURE AND LOW GAS CONTENT
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
MAIN CASE GROUP 4LOW TEMPERATURE/PRESSURE AND LOW GAS CONTENT
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
MAIN CASE GROUP 5LOW TEMPERATURE/PRESSURE AND MID GAS CONTENT
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
MAIN CASE GROUP 6LOW TEMPERATURE/PRESSURE AND HIGH GAS CONTENT
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
MAIN CASE GROUP 7LOW TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
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
MAIN CASE GROUP 8HIGH TEMPERATURE/PRESSURE AND VERY HIGH GAS CONTENT
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
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 :
(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
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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
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
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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.
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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
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Installation Factor : 1.50 24 - inch compressor $ 360,000
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
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$ 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
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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
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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
3-Stage Turbocompressor 350 10,100 60 1523
Reboiler 1523
Biphase Eductor 1523
Hybrid Ejector / Turbo. 1523
3-Stage Turbocompressor 550 30,400 60 2380
Reboiler 6080
Biphase Eductor 6080
Hybrid Ejector / Turbo. 6080
3-Stage Turbocompressor 350 10,100 60 2380
Reboiler 6080
Biphase Eductor 6080
Hybrid Ejector / Turbo. 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
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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.