SAN/1317-3Distribution Category UC-66g

USE OF GEOTHERMAL HEAT

FOR SUGAR REFINING

FINAL REPORTFOR PERIOD OCTOBER 1,1976 - MAY 31,1977

Principal InvestigatorRussell O. Peanon

MAY 1977

UNDER CONTRACT E(04-3)-1317

PREPARED FOR THEENERGY RESEARCH AND DEVELOPMENT ADMINISTRATION

DIVISION OF GEOTHERMAL ENERGY

TRWSYS7PfS AND £NERaV & Ih

ONE SPACE PARK, REDONDO BEACH, CALIFORNIA 90278 V ~

DJSTRIBUTlON Of THTS DOCUMENT IS UNUMltED

ACKNOWLEDGEMENTS

The Systems Engineering and Integration Division of TRW Defenseand Space Systems Group is the prime contractor to ERDA on this study.Russell O. Pearson is Principal Investigator and Project Manager.

Acknowledgement is expressed to the various members of theTRW Technical Staff named below for their contributions to thiseffort:

u

R. H. DouglassL. S. FriedmanP. T. FukunagaR. W. GriffithG. r~. Jaffee

J. M. KennedyH. L. MandelstamJ. S. ReitzelD. R. RevayC. T. Schumann

We also acknowledge the contributions of the various members ofHolly Sugar Corporation named below for their contributions to thiseffort:

G. W. Miles, Jr.L. P. OrleansH. Wilson

ii

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SUMMARY

The objective of this study was to assess the economic and technicalfeasibility of applying low grade geothermal heat «300°F) in the beet sugar

i' " ,

refining industry for both new factory construction and retrofit conversionof existing factories. The representative Holly Sugar factory at Brawley,California was utilized as a baseline primarily because of its centralizedlocation with respect to·the known and partially developed geothermal anom­alies at Brawley, East Mesa and Heber. Nominal values for the key parametersof the sugar refining process and typical values for the geothermal fluidparameters representative of geothermal resources in areas of existing orpotential future sugar factories were defined, promising points of applicationwere identified and conceptual designs synthesized for introducing the geo­thermal heat into the process. The design approaches were then quantifiedwith capital, operating and maintenance costs and comparative economic eval­uations were made with other fuels projected to 1995.

In parallel with the detailed study of process conversion to geothermalheat, the existing pattern and potential growth of the sugar refining industrywas assessed to estimate the potential market for new factory construction atsuitable areas as well as the potential for retrofit conversion of existingfactories. The environmental impact of other geothermal application conceptswas also'assessed and expected technological or industry/government policychanges which might affect the potential for conversion to geothermal heat wereidentified and evaluated.

Emphasis was placed on achieving results that would stimulate cOl1lllercialutilization of geothermal heat for beet 'sugarrefining and related processes.Major areas ,of concern were solicited from beet sugar industry representativesand plans were formulated for demonstration technology developments to resolveengineering and economic uncertainties identified in the process conversionanalyses and the expressed concerns of industry. The demonstrationcriiicalcomponents and subscale process. equipment are defined with supporting testhardware required for testing at the ERDA East Mesa Geotherma~ Component TestFacility located approximately 18 miles from the Holly Sugar factory at Brawley.

iii

Conclusions

The overall conclusion is that it is technically and economically fea­sible to utilize 300°F geothermal fluids in a beet sugar factory based onmodifications to existing process engineering concepts. A summary of studyconclusions, supporting this overall conclusion, is as follows:

(a) The technical feasibility of using 300°F (150°C) geothermal fluids inthe beet sugar refining process has been determined. Promising pointsof application are identified as follows:

(1) Conventionally throttled process medium pressure (25 to 30 psig)make-up steam could be retrofitted in an existing factory withgeothermally generated steam, resulting in 15 to 35% savings infossil fuel demands.

(2) New factories could utilize evaporators designed for 100% of 25psig geothermally generated steam supply.

(3) Beet pulp drying could be accomplished using geothermal fluidsdirectly and appear to offer the greatest opportunity for fossilfuel savings in that 30 to 50% of a total sugar factory fueldemand is used for drying.

(4) Nominally 100 tons of refrigeration is required for crystallizedand bulk sugar cooling which could be provided with geothermallyfired absorption cooling. This process could provide beneficialcascaded utilization of process or bulk drying geothermal effluents.

(b) Thirty-five of the fifty-five United States sugar beet factories arelocated in the eleven western states where Hydrothermal resources arelocated. Eleven of these factories are located within 100 miles ofpotential geothermal resources of 300°F or greater. The resource areasidentified in order of their estimated potential are as follows:

(1) Imperial Valley, California

(2) Southwest Idaho and adjacent parts of Oregon

iv

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(3) Southeast Idaho and adjacent parts of Utah

(4) Northern California

(5) Southern California

(6) Central Washington

(c) Economic evaluations indicate geothermal energy supply costs are competi­tive with fossil fuels for sugar factory cascade system and balanced seasonapplications: e.g., cost estimates based on a conceptually designedretrofit at the Holly/Brawley factory providing cascaded boiler and beetdryer operation with off season alfalfa drying, using the same dryers,indicates attractively competitive geothermal energy application costsof $1.73 as compared with 1976 fuel oil costs of $2.23 per million BTU's.

(d) A feasible accelerated development schedule for geothermal applicationto sugar refining was developed using the Holly/Brawley plant as a retrofitmodel. It appears that a retrofitted plant could start operation as earlyas the second quarter of 1980 considering sugar campaign time periods,technology developments, equipment and reservoir development lead times,if the test equipment designs were complete enough to order long leaditems in October of this year. If the October date is missed the earliestestimated operation would slip one year to second quarter 1981 asexplained in Section 11.

(e) There is little likelihood of any new beet sugar factories being built,near term, because without sugar legislation the sugar price is not highenough or stable enough to project return on investment. Hpwever, thefactories are energy intensive and with projected rising fossil fuelcosts factory operators have expressed an interest in retrofitting inareas where factories now exist and geothermal energy is readily available.

(f) Based on the study evaluations of retrofit potential at the Brawley factoryand the 7 potential factories identified, a fossil fuel savings of approxi­matelyl,606,OOO barrels of oil equivalent per year is projected with sugarfactories retrofitted to utilize geothermal energy. It is noted, however,that the total savings would be in excess of 3;000,000 barrels equivalentper year if off season uses, such as alfalfa dryi~g t were utilized as well.

v

(g) Representatives from the beet sugar refining industry indicated thatthere is a need for geothermal demonstration technology experimentsto resolve engineering and economic uncertainties identified in thisstudy. The sugar manufacturers contacted by TRW indicated they wouldrequire satisfactory sub-scale demonstration before proceeding withplans for retrofitting of a new plant. A demonstration experimentsub-scale configuration of the cascaded application satisfying theseexpressed needs is illustrated in Figure 1 and described in Section 11.

vi

<--

c

CYCLONESEPARATOR

ERDA EAST MESA

GEOTHERMAL COMPONENT

IE~)

FIGURE I

CASCADED BOILER/DRYER

DEMQNSTRATION EXPERIMENT

CONTENTS LPage

1. BASELINE SUGAR REFINING PROCESS 1-1

1.1 SUGAR-BEET PROCESS DESCRIPTION 1-41.2 PROCESS STEAM BALANCE 1-8

1.3 THERMAL ENERGY BALANCE 1-10

1.4 MECHANICAL POWER DEMANDS 1-10

1.5 NON-PROCESS HEAT DEMANDS 1-10

2. GEOTHERMAL RESOURCE CHARACTERISTICS 2-1

3. CONCEPTUAL DESIGNS AND PERFORMANCE ANALYSES 3-13. 1 POTENTIAL BASELINE APPLICATIONS 3-13.2 PROCESS APPLICATION CONCEPTS 3-23.2.1 REFINING PROCESS 3-23.2.2 PULP DRYING 3-43.2.3 MECHANICAL POWER GENERATION 3-93.2.4 REFRIGERATION 3-93.3 ENERGY SUPPLY SYSTEMS CONCEPTS 3-133.4 CONFIGURATION ANALYSES 3-133.4.1 PROCESS CONTROL AND OFF-DESIGN OPERATION 3-13

CONFIGURATIONS3.4.2 COMBINED FOSSIL FUEL/GEOTHERMAL 3-133.4.3 GEOTHERMAL RESOURCE VARIATIONS 3-133.4.4 HOLLY SUGAR-BRAWLEY FACTORY RETROFIT 3-193.4.4.1 STEAM GENERATION 3-193.4.4.2 PULP DRYING 3-253.4.4.3 CASCADING 3-313.4.4.4 RETROFIT 3-313.4.4.5 GEOTHERMAL APPLICATION POTENTIAL 3-36

4. CAPITAL, OPERATING AND MAINTENANCE COST COMPARISONS 4-14.1 SUGAR FACTORY CAPITAL COSTS 4-14.2 ENERGY SUPPLY COSTS 4-1

viii

CONTENTS (Continued)Page

4.2.1 WELLS-CAPITAL COSTS 4-1

4.2.2 TRANSMISSION COSTS 4-4

4.3 ELECTRICAL COSTS 4-4

4.4 BRAWLEY FACTORY RETROFIT CONCEPT 4-8

4.4.1 GEOTHERMAL BOILER 4-8

4.4.2 BEET PULP DRYER 4-8

4.4.3 CASCADE BOILER/DRYERS 4-8

4.4.4 TRANSMISSION PIPELINE COSTS 4-14

4.4.5 HOLLY/BRAWLEY RETROFIT COST SUMMARY 4-14

5. THE SUGAR PROCESSING MARKET 5-1

5.1 MARKET HISTORY 5-1

5.2 POTENTIAL MARKET IMPROVEMENTS 5-1

5.3 GEOTHERMAL APPLICATION POTENTIAL 5-3

6. ECONOMIC EVALUATIONS 6-1

6.1 FOSSIL FUEL COSTS 6-1

6.2 GEOTHERMAL AND FOSSIL FUEL COST COMPARISONS 6-4

7. ENVIRONMENTAL IMPACT ASSESSMENT 7-1

7. 1 SUBSIDENCE 7-3

7.2 SEISMICITY 7-6

7.3 ATMOSPHERIC IMPACTS 7-8

7.4 HYDROLOGICAL IMPACTS 7-147.4.1 QUANTITY 7-147.4.2 QUALITY 7-15

7.5 NOISE 7-16

7.6 EROSION AND LANDSLIDES 7-20

7.7 AESTHETICS 7-247.8 GEOTHERMAL VERSUS FOSSIL FUEL 7-25

8. CLOSELY RELATED PROCESSES 8-1

9. EFFECT/NEED FOR TECHNOLOGY/POLICY CHANGES 9-1

9.1 GEOTHERMAL LOAN GUARANTY PROGRAM 9-1

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ix

CONTENTS (Continued)

9.2 TAX POLICY9.3 TECHNOLOGY IMPROVEMENTS9.4 ENVIRONMENTAL AND ADMINISTRATIVE REGULATIONS

AND CONSTRAINTS10. TECHNOLOGY TRANSFER

11. FUTURE WORK PLAN11.1 INDICATION OF TECHNICAL AND ECONOMIC

FEASIBILITY11.2 ASSURANCE OF RESERVOIR CAPACITY11.3 ASSURANCE OF OPERATIONAL FEASIBILITY11.3.1 DEMONSTRATION TEST EXPERIMENTS11.3.1.1 BOILER EXPERIMENT11.3.1.2 DRYER EXPERIMENT11.3.1.3 IMPLEMENTATION PLANNING11-4 RECOMMENDATIONS

APPENDIX A GEOTHERMAL BOILER DESIGN STUDY

APPENDIX B PULP DRYER THERMODYNAMIC ANALYSIS

x

9-29-39-4

10-1

11-111-1

11-211-311-411-611-811-9

11-12

A-l

A-2

xi

~LIST OF FIGURES

CONTINUED

FIGURE PAGE

6-1 FOSSIL FUEL PRICE PROJECTIONS 6-26-2 FUEL PRICE PROJECTION Ca1PARISONS OF CASCADED 300°F AND

350°F GEOTHERMAL SYSTEMS TO FOSSIL FUELS 6-56-3 FUEL PRICE PROJECTION COMPARISONS OF 300°F CASCADED AND

CASCADED/OFF-SEASON SYSTEMS TO FOSSIL FUELS 6-66-4 FUEL PRICE PROJECTION COMPARISONS OF 350°F CASCADED/OFF-

SEASON SYSTEMS TO FOSSIL FUELS 6-77-1 GEOTHERMAL RESOURCE AREAS AND SUGAR BEET PRODUCING AREAS 7-27-2 GEOTHERMAL WELL FLOW EFFLUENT ALTERNATIVES 7-47-3 TECTONIC FEATURES OF THE WESTERN UNITED STATES 7-77-4 WELL CONFIGURATION ALTERNATIVES 7-117-5 PULP DRYER UTILIZATION ALTERNATIVES 7-127-6 SUGAR REFINING WASTE WATER UTILIZATION ALTERNATE 7-239-111-1 P&ID GEOTHERMAL ENERGY HOLLY DEMONSTRATION UNITS CASCADE 11-5

SYSTEM11-2 SUGAR DEMONSTRATION TEST EQUIPMENT ARRANGEMENT 11-711-3 DEMONSTRATION EXPERIMENT SCHEDULE 11-1011-4 ACCELERATED DEVELOPMENT SCHEDULE 11-11

xii

LIST OF TABLES

TABLE PAGE

1-1 HOLLY SUGAR BRAWLEY PLANT NOMINAL 1976 PROCESS STEAM 1-11BALANCE

1-2 HOLLY SUGAR BRAWLEY PLANT AVERAGE FUEL DEMAND 1976 1-12CAMPAIGN

2-1 U.S. BEET SUGAR FACTORIES (LISTED BY STATE) 2-2

2-2 POTENTIAL GEOTHERMAL ENERGY SOURCES FOR SUGAR REFINING 2-8

3-1 GEOTHERMAL POTENTIAL - SUGAR BEET FACTORY CHARACTERISTICS 3-3

3-2 CASE I AND CASE II CONSIDERATIONS 3-18

3-3 BRAWLEY FACTORY - GEOTHERMAL APPLICATION POTENTIAL 3-37

4-1 SUGAR BEET PROCESSING PLANT COSTS 4-2

4-2 NOMINAL ENERGY SUPPLY CAPITAL COST ESTIMATE (THIRD 4-3QUARTER 1976)

4-3 ANNUAL FIXED CHARGE RATE ASSUMPTIONS 4·5

4-4 ESTIMATED GEOTHERMAL PRICES (COSTS) 4-6

4-5 GEOTHERMAL ELECTRICAL GENERATION COSTESTI~~TES 4-7

4-6 25PSIG STEAM GENERATING COSTS WITH 300°F BRINE 4-9

4-7 25 PSIG STEAM GENERATING COSTS WITH 350°F BRINE 4-10

4-8 REPLACEMENT DRYER COSTS WITH 300°F BRINE 4-11

4-9 BRAWLEY RETROFIT COSTS WITH 300°F BRINE 4-12

4-10 BRAWLEY RETROFIT COSTS WITH 350°F BRINE 4-13

4-11 ENERGY SUPPLY COSTS WITH 300°F BRINE 4-15

4-12 ENERGY SUPPLY COSTS WITH 350°F BRINE 4-16

4-13 BRAWLEY RETROFIT COST SUMMARY 4-17

~

xiii

LIST OF TABLESCONTINUED

TABLE PAGE

6-1 FOSSIL FUEL AND GEOTHE~AL PRICE PROJECTIONS 6-9

7-1 FRACTIONS OF TOTAL GAS CONTENT 7-9

7-2 GASES ASSOCIATED WITH GEOTHERMAL STEAM AT THE GEYSERS IN 7-9VOLUME PERCENT

7-3 COMPARISON OF NOISE LEVELS BETWEEN GEOTHERMAL AND OTHER 7-17SOURCES

7-4 EFFECTS OF NOISE ON ANIMAL POPULATIONS 7-19

7-5 TOPOGRAPHIC DESCRIPTION OF GEOTHERMAL RESOURCE AREAS 7-22

7-6 ADVANTAGES AND DISADVANTAGES OF AGEOTHE~AL VERSUS A 7-26FOSSIL FUEL SYSTEM

xiv

1. BASELINE SUGAR REFINING PROCESS DESCRIPTION

The study objective is to assess the potential for use of geothermal heatin the sugar refining industry for both new factory construction and retrofitconversion of existing factories. In keeping with the objective, we haveselected the Holly Sugar factory at Brawley, California as the baseline forinitial analyses since the factory is:

a. Typically representative of the composite North American beet-sugarfactory flow diagram as displayed and described in "Beet SugarTechnology," Beet Sugar Foundation, Second Edition, 1971.

b. Located near the Brawley KGRA (see Figure 1-1), which makes it aprime candidate asa demonstration plant for future retrofit conver­sion to geothermal energy.· The Brawley KGRA contains tested produc­tion wells within 8 miles of the plant. Exploratory wells are alsobeing planned for mid-1977 completion within one mile of the plant,pending approval of a geothermal loan guaranty application to ERDA••

c. Located within 20 miles of the Heber and East Mesa KGRA's (seeFigure 1-1), which have sufficient reservoir definition to be con­sidered for new or.moved fa~tory locations. Each of these KGRA'shas 10 or more flowing wells for which abundant data on geothermalfluid characteristics is available.

d. Located approximately 14 miles from the ERDA East Mesa GeothermalComponent Test Facility, which could be used for pr~liminary demon­stration experiments prior to retrofit of the Brawley factory or newfactory locations in the area.

The Holly Brawley factory is a multimillion dollar facility which processesnominally 6,000 tons of sugar beets per. day. The plant produces approximately1,050,000 pounds of high-purity sugar per day, which is shipped as granulatedsugar in bulk or packaged form. Figure 1-2 is an aerial view of the Brawleyfactory with locaters on the main elements for subsequent discussion reference.

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t."'...,.... ,...

.......ARIZONA

GLAMISKGRA

NEVADA

MEXICO

0 ....' ....

CAliFORNIA

KEY MAP

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HOLLY / ....:·~"'-.S.4.SUGAR ./ ""~'"-..._...-

Y I I If, I lp I! ,1,5HILES

HEBER KGRA

HOllY SUGAR P

-------.-

FIGURE 1-1. MAP SHOWING HOLLY SUGAR PLANT AT BRAWLEY AND NEARBY KGRA's

(KGRA's from USGS Geothermal Land Classification Map 1975)

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F;gure 1-2. ~er;a1 V;ew of Holly Sugar Plant at Brawley, Californ;a

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In 1976. the Brawley factory campaign (operation) was from April 2 through ~

September 22. The factory is designed to slice a larger tonnage of beets thanon-line capability to process; therefore. excess· thick juices are stored forlate-processing; i.e •• April 2 to August 5 for beet slicing ~nd processing andAugust 5 to September 22 for refin~ng of stored thick juices. It is notedthat beet piling is limited to 20 hours duration under shade in Arizona andCalifornia. In the northwest. beets can be stored an average of 90 days;therefore. stored beets are utilized to smooth the factory flow. which formaximum economY. operates as close to capacity as possible at all times.

1.1 Beet-Sugar Process Description

Extraction of sugar and the by-product dried beet pulp from sugar beets isan energy intensive process with approximately 14% of product cost attributableto fuel costs. Figure 1-3 indicates the study developed process flow diagramfor the baseline factory at Brawley. Figure 1-4 presents a simplified schematicof the manufacturing process flow integrated with the balanced boiler live steam.turbine exhaust steam and evaporator vapor transmission of heat to variousportions of the process. As an introduction to the reader unfamiliar with theindustry. the process may be conveniently separated into stages as illustratedin Figure 1-4 and described as follows:

a. Diffusion Stage. Sugar beet roots are thoroughly washed in preparationfor slicing and transported by flume from the receiving yard to theslicers. The beets are sliced into thin strips called cossettes. Theslicers require live steam at 150 PSIG. minimum. for blade cleaning.The cossettes are then immersed in hot water. leaching out the sugar bydiffusion. The temperature is raised for better extraction usingvapors formed in the second evaporator effect.

b. Juice Purification Stage. The raw diffusion juice is screened to removeany small particles of cossettes. and then heated to 175-185°F usingvapors formed in the third evaporator effect. The heated raw juiceis then purified by a process called carbonation in which lime andcarbon dioxide gas are added to precipitate the impurities in thejuice. Filtration and settling remove the solid particles and elim­inate impurities. The purified liquid is called thin juice and contains10 to 15% sugar solids.

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FIGURE 1-3

ISUGAR BEETS

FEED

LEGEND

400 PSIG LIVE ST~

150 PSIG LIVE STEM

45 PS IGEXHAUST

<15 PSIG VAPOR

ELECTRI ClTV

FUEL

-1-

-0-

-00-

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WASH

PR[HEAT

SLICE

FILTER

DIFFUSE

FILL f"iASSY

EVAPORATE

CARBOilATE

THIN JUICE

CRYSTALLIZE

PURCHASE

~-I{:1000 KW

3000 KW IlI

TURBINES Io GENERATOR Io COMPRESSOR I

00o WASHER PUMP -+-o FEED PUMP t-~

o DRAFT FAN II

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PACKAGED BULK GRMULAR LIQUID /"OlASSES

HOLLYIBRAWU:Y - BEET SUGAR PROCESSING FlOW DIAGIWI

Figure 1-4. Holly/Brawley Simplified Beet Sugar Processing Flow Diagram

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c. Evaporat~on State. The thin juice is then preheated using first andsecond vapors and exhaust steam and sent to the evaporators. The thinjuice is concentrated by evaporation in multiple-effect evaporators, withfive individual bodies or effects. The evaporators are arranged in aforward feed arrangement, with steam used for the first effect drawnfrom turbine exhausts, but for each succeeding effect the steam usedis that formed in the preceding effect by evaporation of water from thejuice. This system, developed by the beet-sugar industry is econom­ical since it allows multiple use of the same heat energy and resultsin decreasing temperatures and pressures as the juice proceeds throughthe effects. The thick juice outflow is concentrated by evaporation toa dissolved sugar solid content of 50 to 6~%.

d. Crystallization Stage. Further filtering insures that all solidparticles are eliminated. The sugar is then crystallized by pan boilingin vacuum pans. ~ow temperature pan boiling heat is provided by secondvapors to avoid carmeHzation. The resulting mixture of sugar crystalsand liquid from the pans is known as fillmass. The fi1lmass is spun andwashed in high-speed centrifuga1s to separate the sugar crystals fromthe 1iquid. The wet white sugar crystals are then sent to the dryer or granu­lator and from there to the cooler. The granulated sugar is then screenedand either sacked immediately, or stored in bulk bins to await furtherpackaging or bulk delivery.

e. Dryed-Pulp Manufacturing Stage. Wet pulp from the diffuser (~) ispressed in pulp presses to reduce the moisture content from 95 to 80%.The pressed pulp is then mixed with molasses, from the centrifuge (d)and dryed to a moisture content of about 10% by hot air in a pulpdryer. A conventional pulp dryer is direct-fired, with an induced­draft, parallel-flow, rotating~drum.Thedrum,approximately 12 feetin diameter by 60 ftlet long, contains baffles, which drop the pulp throughthe hot flue gases as the drum rotates. The pulp is moved throughthe drum by the flow of combustion gases as the drum rotates. Thedrums are normally gas-or oil-fired with products of combustionmixed with cooling gas to obtain a nominal entering temperature ofl200°F to prevent losses from pulp combustion. An induced draft fan

'-.I is located at the drum discharge, flowing through a cyclone separatorto recover small particles from the flue gases exiting at 230 to 2BooF.

1-7

The fuel used in the pulp drying Qperation accounts for 30 to 50%of the total fuel required by the entire beet factory in its dailyoperation while slicing beets.

1.2 Process Steam Balance

The beet-sugar refining process as described requires relatively largequantities of low-pressure process steam. Therefore, the sugar industry usuallyfinds it economical to generate its own electric power with a noncondensingsteam turbine generator, which exhausts steam at the pressure required by theprocess. Further, the need for process steam has made it normal practice topower other large horsepower loads with mechanically driven noncondensingsteam turbines to aid in balancing out the steam requirements in the wholeplant.

The design boiler steam pressure is determined by establishing the exhauststeam pressure to be used in the evaporator first effect and the amount ofpower to be generated by the turbine prime movers. The boiler steam pressureis then selected, which will allow generation of the required power, using

65 to 85% of process steam requirements. The remaining 15 to 35% of theboiler steam is then "made up" by throttling live steam into the exhaustsystem to prevent blow off of unused steam during off design operations.

Oil, gas and coal are used as fuels for the boilers. The beet sugarfactories in California are designed to use gas when available, and oil forstandby because of restrictions on coal firing. The sugar factories in Utahand Idaho have converted to and plan to use coal for future campaigns.

The nominal boiler and exhaust steam balances for the Brawley factory1976 campaign are indicated schematically in Figure 1-5. As indicated, thethrottled steam make-up is approximately 34% of exhaust steam demand~ It isnoted that this throttled steam make-up could be provided by retrofittedboilers heated with geothermal energy without upsetting the balanced fixedturbine exhaust system, as discussed further in Section 3.

1-8

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.F.lGURE..1-5

Detailed tabulated breakouts of the nominal live, exhaust and vaporsteam demands of the'Brawley factory are indicated in Table 1-1. Promisingpoints of application for geothermally generated steam are identified as those ~demands- totalling 34% of throttled steam, which can utilize steam as low as28 PSIG (272°F).

1.3 Thermal Energy Demands

The nominal thermal energy and fuel demands for the 1976 Brawley factorycampaign are shown 1n Table 1-2.

1.4 Mechanical Power Demands

Steam turbine prime movers for large mechanical loads are used in theBrawley factory. As indicated in Figure 1-5 the electrical generator, gascompressor, beet washer pump, boiler feed pump and forced draft fan are allpowered by steam turbines. By examination, all other motor loads were foundto be less than 100 horsepower thereby raising doubt as to the feasibility ofusing vapor turbines powered from a geothermal source.

1.5 Non-Process Heat Demands

No demands exist in the baseline plant for space heating or coolingwhich might be convertible to geothermal. However, approximately 100 tonsof refrigeration is required for crystallized and bulk sugar cooling whichcould be provided by geothenmally powered absorption or steam jet refrigeration.

1-10

(HOLLY SUGAR BRAWLEY PLANT

NOMINAL 1976 PROCESS STEAM BALANCE (LB/HR)

LIVE STEAMSII£HSON COOPER

EXHAUSTSTEAM BALANCE S T E P FIRST SECOND THIRD FIRST SECOND THIRn TOTALS

~ 47 PSIGVAPOll VAPOR VAPOR VAPOR VAPOR VAPO!l

400 PSIG 150 PSIG 30 PSIG 17 PSIG 12 PSIG 24 PSIG 14 PSIG 10 PS:G275°F 255°F 245°F 266°F 250°F 241°;'

PROCESS STEAM DEMANOS

1 GRANUlATOR 5.200

2 CRYSTALLIZERS 100

3 SWENSON THIN JUICE HEATER 3.400

4 SlIENSON EVAPORATORS 133.000

5 SIIENSON FIRST VAPOR MAKE-UP 10.400

6 TIIIN JUICE BOILER I L-. ~ 9.9DO

7 LOW RAW M£LTER L-- ~ 500

8 SECONO CAR8 HEATER 7.700

9 WHITE PANS 43.00010 CHAIN 01 FFUSER 3.600

11 THIN JUICE HEATER 3.40012 ·HIGH RAil PAIlS 10.000

13 HIGH RAil MELTER 90014 BLDIDER 3.000

15 DlAIN RAil JUICE HEATERS 17.00016 COOPER THIN JUICE HEATER 4.900·

17 COOPER EYAPORATORS 62.000

18 SLOPE 01 FFUSER 5.00019 LOW RAW PANS 5.10020 CONCENTRATOR 4.80021 SLOPE RAW JUICE HEATERS 12.10)22 THICK JUICE HEATER 1.10")23 DIFFUSER SUPPLY TANK 1.00)24 SLICERS n.50025 TOTALS 11.500 219.000 230.500

PROCESS STEAM SUPPlY

26 !'lAKE-UP FROM 400 PSIG LIVE 31 80027 !'lAKE-UP FROM 150 PSIG LIVE 45.500

28 GENERATOR TUR81 HE 85.000

2~ GAS 8L~ER TURBINE 23.000

30 BEET HASHER PUMP TURBINE 15.700

31 BOILER FEED PUl·" TURBINE 8.000

32 FORCED DRAFT FAN TURBINE 10.000

33 SlICER STEAM SUPPLY 11.500

34 TOTALS 11.500 219.000 230.500V~ '!.T~AN '!.II>PL Y

35 UNION BOILER 57.000

36 RILEY BOILER 73.300

37 COMBUSTION D1GR BOILER 100.200

3Il TOTALS 173.500 57.000 230.500

(

,-__",1 PROMISING POtlnS OF APPLICATION OF 6EOTIlERIW. S1"EM !o28 PSIG (2nOF) 'TABLE 1-1

EQUIVALENT FUEL D~~NDS

SLICING GAS OIL%OF PLANTBTUH DEMAND 106 CF/DAYBBL/DAY

138 x 106 24 3. 1 563

91.7 x 106 16 2.1 374

74.5 x 106 13 1.7 304

269 x 106 47 6.1 1098

573 x 106 100 13.0 2339

­I-N

TABLE 1-2 HOLLY SUGAR BRAWLEY PLANTAVERAGE FUEL DEMAND

1976 CAMPAIGN

400 PSI C.E. BOILER

400 PSI RILEY BOILER

150 PSI UNION BOILER

PULP DRYERS

TOTAL PLANT

NOTES: 1. BEETS SLICED 603, 364 TONS2. FUEL - BOILER HOUSE 10M THERMS

- PULP DRYERS 6M THERMS3. OPERATIONS - APR 2 TO AUG 5 -- SLICING (126 DAYS)

- AUG 5 TO SEP 22 -- JUICE (48 DAYS)4. ENERGY; 14% PRODUCT COST

2. GEOTHERMAL RESOURCE CHARACTERISTICS

Amajor part of beet sugar production in the United States comes fromthe eleven conterminous western states where hydrothermal resources areconcentrated. Thirty-five of the fifty-five beet factories listed in Table 2-1are in these eleven states.

Figures 2-1 and 2-2 provide an overall view of the geographic relationsbetw~en beet sugar production and geothermal resources in the western UnitedStates. Figure 2-1 shows the locations of sugar beet growing areas and beetsugar factories, identified by their number in Table 2-1. In Figure 2-2,the beet growing areas are shown together with the hydrothermal resourceoccurrences identified by the U. S. Geological Survey in USGS Circular 726,a most authoritative current catalogue. These hydrothermal systems arecharacterized by different symbols on Figure 2-2, to show their. estimatedresdurce temperatures and their relative sizes and status of development.The heavy contour lines on Figure 2-2 enclose areas in which all hot springslisted by Waring (ref. 2-1) have surface temperatures greater then 120°F.These areas contain most of the known hydrothermal resources, and are thebest prospective areas for new discoveries (ref. 2-2).

For converting existing factories to geothermal process heat, the exist­enceof a viable resource within a few miles is an economic necessity. Theconjunction of the Brawley field and the Holly factory. is the most favorableknown, since no other proven geothermal resource lies nearly so close to anexisting factory. (Resources may be found even closer to the factory thanthe existing Union wells 8 miles away, since the factory lies in the promisingoffset region between the Imperial and Brawley faults. McCulloch 011 Co.is currently preparing to drill a geothermal test well on land adjacentto Holly property.)

For new or relocated plants, however, it may well be .feasib1e to locatethe plant close to geothermal resources that 1ie.within economic shippingdistance of beet growing areas. This distance is of the order of 100 miles,varying considerably with terrain and available roads and railways, sincetransit time and expense are both important factors. Figure 2-3 shows areas

~ in which geothermal resources may lie within economic range of beet growing

2-1

Table 2-1

U. S. BEET SUGAR FACTORIES (Listed by State)

STATE LOCATION (City/Town) MAP LOCATION NO. COMPANY

Arizona Chandler 3 Spreckels

Cal ifornia Betteravia 9 UnionBrawley 6 HollyClarksburg 12 American CrystalHami 1ton Ci ty 4 HollyManteca 10 SpreckelsMendota 8 SpreckelsSanta Ana 5 HollySpreckels 7 SpreckelsTracy 13 HollyWoodland 11 Spreckels

Colorado * Brighton 20 Great Western

* Delta 21 HollyEaton 22 Great WesternFt. Morgan 19 Great WesternGreeley 16 Great WesternJohnstown 24 Great Western

* Longmont 17 Great WesternLoveland 15 Great WesternOvid 23 Great Wes·ternRocky Ford 14 American CrystalSterl ing 18 Great Western

Idaho Idaho Falls 27 Uand IMini ...Cassia 55 AmalgamatedNampa 26 AmalgamatedTwin Falls 25 Ama1gamated

Kansas Kemp-Goodland 28 Great Western

Michigan Bay City 41 Monitorcaro 37 MichiganCarroll ton 38 Michigan

* Will not operate in 19772-2

Table 2-1 (Continued)

\..) U. S. BEET SUGAR FACTORIES (Listed by State)

STATE LOCATION (City/Town) MAP LOCATION NO. COMPANY

Michigan .. Crosswell 39 Michigan(cont'd) Sebewaing 40 Michigan

Minnesota Crookston 43 American CrystalEas t Grand Forks 44 American CrystalMoorhead 42 Ameri can CrystalRenville 54 American Crystal

Montana Billings 29 Great WesternSidney 30 Holly

Nebraska Bayard 49 Great WesternGering 48 Great WesternMitchell 50 Great WesternScottsb1uff 47 Great Western

North Dakota Drayton 46 American CrystalHillsboro 45 Ameri can Crys ta1

Ohio Findl ay 53 Northern Ohi 0

Fremont 52 Northern OhioOttawa 51 Northern Ohio

Oregon Nyssa 31 Buckeye

Texas Hereford 1 Holly

Utah Garl and 2 Uand I

Washington Moses Lake 32 Uand IToppenish 33 Uand I

Wyoming Lovell 34 Great WesternTorrington 36 HollyWorland 35 Holly

2-3

L•

KANSAS

TEXAS

DAKOTA

14

•

.,.\ """'-,...... I ,

.... ....",1 "

/lEW MEXICO

•36 J

••~60,~!.eRES

"-"

............................ ""-

.... ---...........r-;----__.I / ------_. . CANADA

WrlAsHINc J2 / i'4 -·--------------r-··-·- --.\ / .I 64,0lXl ACIf i \,,........ 33 / NORTH

,-......... · ... -.. .. a-...... ( '': ,, I :

/ .' DAKOTA

/ I••" I\ ,7~0lXl ACRES ~_._ •• _._. __ •

~", ,.. •• __~J4 '

31 2$ IDAHO ....... _.:\: '}__"_ ,66,OlXl ACRES: I -. - -. -: SOUTH

.._ ! 27 / ~RES I\~ ICKES !-. -r-.- ; 2; 55 j ~ I

; -'--•.1__ ._ ~ ~ WYOMING ,

I i.~~_ IO,OlXlACRES :-.-- ••_-.

I 'I II I 68,. ACRESI l 6'., 0lXl ACRES" I ..a_ ...._ 50

I ' r-------·· JZ ...NEVADA I\. : :"

\. ! UTAH , 17

\ I I~: 21

\ i .I0,OlXl CRES

';6, 0lXl ACRES\ \. /. • !. I ----------_/ _\ [''\,: '--'-\ : ! ------

\} !\ I, ,.",' lRIZO/IA '

!I,I

i,/LEGEND """

. -',~_ Sugar Beet Acreage from

Goode1s World Atlas .~""XICO

• Factory locations fromBeet Sugar Development Foundation

..\

50 50 lGO

Wl.!onlUS

,'-.

150 100 t

Figure 2-1 Sugar Beet Growing Area and Factories (see Table 2-1)

2-4

l ..

KANSAS

NORTH

DAKOTA

SOUTH

DAKOTA

.\

"t

o

~: 10,001 ACRES

ACRESNEBRASKA

_.~~

-110 001 ACilES ,-------, ~

10,001 ACyESII

III

-·-r-·l__._._~;----------:: ,I :: II,,I,I

III

I,,_.J

I,,I:L.._.__. ..

~---- i:.~ hr~:------j

~. wYOMING iI·-AC-~ ,'_tu.UUU R\i" --_. __ ...._. __,

• VERY UK( SYSTEMS

• EYALU/.TED SfSTEMS• lIOII·EYALUilTED SYSTEMS

• J20<T<1OOFI> :lllO<T<_

$a<TC4OOI'

i)400;<T

O. IEvtRAL DEEP•. WELLS· 'LOW

TESTED

•I4WELU'LOW UttCIlITAIN011 LOW

HYDROTHERMAl. S~TEMS fIllII . .USGS Claaua 726

I<'CXlCO

lilT SPRIIlliS

SURfACE TEMPERAlURE

.IZOOF (49"C)

_lIVERS

Sugar Beet Growing Areas and Hydrotherma) Resources.2~5

--.. ..........--..,~ ._-..-..----r-r---

I I ._------_ CANADAI .--.-r t --.... ------- __I \I I. '.

\

LEGEND

SUGAR BEET ACREAGE

c::::J.~~

figure 2-2

..

u

l.

KANSAS

NORTH

DAlCOTA

SOUTH

DAlCOTA

14

•

IS

IACRES

l .. _ .. _,-._ .. _.. ...

I -.--

"'~THEP.tIlL SYSTE'tS FIlIIus~s Ct.C'Ilt.1t 721

MEXICO

i.I.

'1IOOIl • CO\lI

/\lIL~'d:OI'T

1'II'1II1,I(Ir-1".

I..!~~.~IRE'i e•

/.-. 'I .. - ..... -.... II _ .... - .... _ ... _,.... : .......-

~ ! -'-"-I VALLO e ----·-r:.-- ...: CALDI.... , :

I :: II : II NEw MEi('CO ! •

: I... !· i

! :"'" I. I"'-" -..-L._r"-.. ..i...:.-"-.. - .._ ..1"

'" \

..

................ -- .... --.....-(-;.-.-.._..

I , --._ CANADAI • ..-.--•. -_._

i \ ------·-i·--··--·· ...··i \ I,

~--r'_ I~.

/ :.' ...l,,,,, ..• \. • L.) 29 ,.,-"--"-,,

_·'\..··_·f'.~t~--·-~-·_··-!I ACIl£S t'i\~ ICRES !L ~ :: ~ I\"(OM'NG ,! lO.lXXl ACRES . i-·- .

llGENO

~. SlJG~CR£AG(

,,.\ "-'0"..... I •

-·oJ.' ", ..~

.:no~T<"

e.,<T<1IGF

._<T<_

....'<T

O_VIRAL DlI,WELLI· 'LOWTlmo

n IoIIWlL""" 'LOW UNCIITAIN

OIl"W

• fEIY LAP',e" ZYSlU1S

• Ei'lll~T[O m:r1tS• "jlJt·EVALuATED SYSTOtS

f2\SCALE or IIUS

lID

Figure 2-3 Selected Hydrothermal Resources Close to Beet Growing Areas.2-6

areas, marked by circles of 50- and 100- miles radius around resourcelocations. In order of their estimated potential, these areas are: TheImperial Valley in California; southwest Idaho and adjacent parts of Oregon;southeast Idaho and adjacent parts of Utah; northern California; southernArizona; and central Washington.

Table 2-2 summarizes some more detailed information on the geothermalresources of these areas. This information comes from various sources ofwhich the USGS Circular 726 is the best source for reservoir extent and heatreserves, which have been estimated from most of the publicly availablegeological and geophysical data. Considering resource temperature andsalinity, estimated reserves, state of resource development, and expectedease of transportation, the priority of Imperial Valley and southwestIdaho is clear from the data in Table 2-2. Geochemical evidence (ref. 2-3)suggests that southern Idaho may have widespread and abundant high-temperatureresources at depth, that are concealed by mixing with cold water near thesurface. If any large fraction of these suspected resources is proven bydrilling, this region may well take first place in the use of geothermalprocess heat for sugar beets and other agricultural processing.

2-7

NI0)

POTEIlTIAl 6£OTI£RlW. ENERGY SOUllCES FOR SUiAR REFIIIIIlG

RESOORCE TEPf TEI'IP SAlINITY AREAL HEAT DEEP IlEUS m'ERATOR OR IlAJOR LEASEHOUlERS BEET SUGAR FACTORIES III AREA('f) ('f) (PP!1) EXTENT RESERVES

IIlJ/'lBERED AS ON LOCATION /lAP6£OCHEIIICAl OEEP TDS (ACRES) (BIUIONTEI'IP lIEU USGS MILLION

TEll' ESTIMTE BTU)"

I!fERIA!. VAlLEY. "1Iq Of HEATS. tALlEDBllIA III PlACE

(USGS) AIlOYE

>EOO'F 25O'f

SAlTON SEA .- (__8000') 250.000 13.000A "IS -IS IlEUS PHILLIPS. SO. PAC. LANa CO•• S.CAL EDISON BRAWlEY (6), HOUY

BRAWlEY -- -IIOO'F 20-50.000 Q.5OOA -2 SIIEUS UIlION. Sf. OIL Of CAl.m

HEBER -- 390'F1~IS.ooo CHEVBON. MGi"A. REPUBliC. UNION(__5000') 12.000. -S 12 IlEUS

(FAIR FLllIIRATES)

390"F 7.000A 10 IlEUSU.S, BUREAU Of RECLAMTION

EAST 1l:$A -- (8000') 2-10.000 "3 REPUBLIC 6EOTHERML. MGi"A (FAIR FLllIIRATES)

SII..lIWIll!lYSSA mIl A!"Al6AIIATED_.

CRANE CREEK 36Q'F POSSIBLY -- 7.5OOA -2 110 IlEUS IW'PA (26), Al'ALGAl'lATEDIUH

IlEISER 32Q'F HIGItER -- 1.5OOA -2 110 DEEP IlEUS --VAlf II.S. (ORE.) 32Q'F - -- 12.000 -2 110 IlELLS --IIlUIlTAIII HONE - 35O'f

4800 ? ? 61!lf-BOSTIC 6Ul.F ENERGY &MINERALS (110 FlOO(9500')

8IlIlllEAII-6RAIElI m'F500.000\

UllCERTAIII110 OEEP IlEUS --

POSSIBLY " II 1116HER -- MY BE LAR6E

SE...1IWIl1 GARLANIl (2), Ull36Q'F 29rF RR6E II ERDA + COfISORTIUIl IUNI-CASIA (SS), AllAL6,

RAFT RIVER (Q-6000') 42000 S.OOO\ -I RR6E 12 (GOOD FlOII FRON IlEUS) TIIIN FAUS (25), AML6.

BRI6HNI CITY -1IOO'f 28S'f 6EOTHERlW. KINETICS (GI(J) IDAHO fAlLS(271, Ull(UTAII) UO.OOO') SS,OOO ? ? lJSV-DAVIS II (110 FlOO

N. CALlEllRlIIA HAIlILTON CITY (q), ItlUY6EYSERS - ~f STEAPl 17,OOOA -IS OYER 200 IlEUS

IIIIION • 8URl'Wf. SHEU l«lOOl.AIlD UJ), SPRECKELS

CALISTOGA 32Q'f m'F? I,OOOA 41 1 lIEU -2000' CAlIST06A POI£R CO. ~(12), AN. CRYSTAl(-2000')

IIllJ11lR II.S, 360"F 2B5'F 30,000 Q,OOO\ -1 1 lIEU 3600' CORIlERO MIIIIIlG CO. JW/TECA (10), SPRECII!LS(3600') (6O<ll FLOW>

PllR6AII SP6S. QlO"F ., 1.000\ '1 110 IlEUS -- TRACY (13), HOUY

WZ!IIA 305'F 60.000 PIlIl<9000')

liE~L KINETICS (61(1)6001\ "1CIMlUR - 3S2"f PIlI2 (6001I FLOlIIlAY BE OBTAIIlABLE) CIWIDl£R (3), SPRECKELS<10.500)

JmSII.III&IIIlUIItiIlIRE II.S. ~'F - ? ? ? 110 IlEUS - TllI'I'EIIISII <m

S'ftm ClC. WF - ? ? ? 110 IlEUS - PIlSES lAIIE (32)

Table 2-2. Potential Geothennal Energy Sources for Sugar Refining.

c c

REFERENCES

2-1 Waring, G. A., 1965, Thermal Springs of the United States and OtherCountries of the World, USGS Prof. Paper 492.

2-2 TRW Systems and Energy Group, for Electric Power Research Institute (EPRI),Final Report to press, December, 1975, Utilization of U.S. GeothermalResources (Technical Planning StudY 76-638).

2-3 White, D. E. and Wf11fams, D. L., Assessment of Geothermal Resourcesof the United States - 1975, Geological Survey Circular 726.

3. CONCEPTUAL DESIGNS AND PERFORMANCE ANALYSES

The purpose of Task 3 was to select the most promising points ofapplication for geothermal energy, in the baseline factory describedin Section 1 and evaluate the technical feasibility for factory retrofitutilizing the local hydrothermal resources of 300°F or less. Conceptualdesigns were synthesized and analyzed of alternate energy supplysystems providing geothermal fluids to the factory and of alternatesystems for retrofit or new factory extraction of heat from the geo­thermal fluid and transferring it to the major process loads.

The results of these design syntheses and analyses are describedbelow.

3.1 Potential Baseline Applications

There are many portions of the sugar refining process that operate attemperatures of less than 3000F; however. most of these low temperatureheating requirements are satisfied by evaporator vapors which are ineffect process heat tailings. as described in Section 1. Therefore. lowgrade (s 300°F) geothermal energy cannot be directly substituted forthese vapor heating supplies without upsetting the balanced boiler livesteam turbine exhaust steam and evaporator vapor heat transmission systemin a conventional beet-sugar factory. However.15 to 35% of exhaustis made-up bythrottl in91 ive boiler steam as descr.1bed in Section 1.In the Holly Brawley factory nominally 34% of the exhaust steam demandsare throttled live steam. Table 1-1 indicates these demands. totaling34%. which could utilize medium pressure. 25 to 28 PSIG (268 to 272°F)steam as potential for application of geothermallygenerated steam fromresource temperatures of ~300°F. The process steam demands for the Cooperevaporators. Cooper thin juice heater. thin juice boiler and low rawmelterare approximately 77.000 pounds of 28 PSIG steam per hour. Thisapproach is technically feasible with 30QoF geothermal fluids. and alsoeconomically competitive with fossil fuels as indicated in Section 6.Figure 6-3.

3-1

The beet pulp drying operation appears to offer the greatest oppor­tunity for fossil fuel savings in that approximately 47% of the total Brawleyfactory fuel demand is required as indicated in Table 1.;2. Various means ofutilizing geothermal heat in the pulp drying process were identified ande'xamined as described in subsequent Section 3.2.2. These investigations'indicate that length of conventional dryers or the dwell time must beincreased by a factor of 4to6 when utilizing geothermal energy.

3.2 Process Application Concepts

Geothermally heated process application concepts which were investigatedfor sugar refining, pulp drying, mechanical power generation and refrigerationare described below.

3.2.1 Refining Process

The retrofit potential for providing process steam in the Holly Brawleybaseline factory has been discussed in Section 3.1. The potential for pro­viding geothermal process heat in other factories is assessed in Table 3-1.Sugar beet factory characteristi cs are tabulated for factories adjacent tothe potentially attractive geothermal resource areas identified in Section 2.As shown, most of these factories require process steam exhaust temperaturessimilar to the baseline factory. On a retrofit basis,\'Je might expect toreplace 15 to 35% of exhaust make-up steam similar to the baseline case.However, it is noted that other geothermal resources and temperatures arenot as well defined as for the Brawley area which results in lower potentialranking as indicated in Table 3-1.

New factories can be designed with multiple-effect evaporators to

operate with 25 PSIG steam (~268oF).

3-2

R£Ft1t£IIC[D£SICllATlOII

33 I 14

I" IA4

3t I AS

LOCATIOII

TOPI'E1lISM val

STAIlOMIIDAILY SLICE(TOIIS/DAY)

6[IIERA'IOII(IQI)

1500

SOD23006000

55015003000

250 I 40

215 I215 I 3S400

230 II400 37230

EXlIAUSTTEMPERATURE

OC ·F

142 I 287

I

138 I 281

I139 I 283

GEOTHERMALINDICATOIl

(VITHI" 100 MILES)CHEllICAL MEASUREDTEMP ·F TEMP ·F

340 : ••

360 / ••••••

320 1"- -- _.320 1:··-·-

_._. -- 350

MOT SPRUleS llMLY

2 VELLS • LO FLOIIorEP (9.000 FT)

GEOTHEIIIW.FIELD

L0II6I!11lE

CIlAME Cit.WISER

'ALE N.S.IOJMTAIIIIIlII!E

lIAS"

S1IIDAHO

PllII'IAR!FUEL

6£OTHEIIIW.POTENTIAL

12

8

9

7

4

1

11

10OIL

OIL

OIL

OIL

OIL

SCAl

"CAL

SEIDAHO

ARIZCAAMOLER

RAn RlnR

SALTON SEABRAWLEY~EBER

EAST MESA

GEYSERSCALISTOGA

IIILIUR N.S.

ImGNt SPGS.

IRI6IWI CITY

3 RAn 11InR VELLS

GEYSERS onR 200 VEUS

SALTOIl SEA • 15 WLLSBRAWLEY - 5 VELLSHEBER - 12 VELLSMESA • 11 VELLS

I 8RI6lWI CITY - NO FLOII.

I 460

: I :::410 I .

•••••• : 305·352

360 I 297

I~oo I 285

I

...... I 600•.•••• 1, ;~

::.:: :: 'I 390

294

2~9

274

211

292

287

281

274

I146 I

I

134 I138 I134 I142 I

138 I'IU

Iml

•• ,'••• I 292

200 I 35

300 I 4S

200 I 20

" I400 I 47

I

595 I 45

200400300

m I 30

I 35

I 30

1~ I 40

3000

600

10002000

2500

1500250025003001500

4400

8500

3000

2400

3450

'XJOO

2700

, 4250

HOLLY

vir

SPRECmS

HOLLY

SPllEcms

NW./WMTEl)

var'

AM£R. CRYSTAL

lRA1lLEY

CHAIIOLER ,'"

CLARICSIURG

Mil FALLS

lII11r-CASrA6AIllAIlII .' ,

IMHO FALLS

HAMILTOIl CITY

lIOODl.AMD

3 I SS

4 IHI

n '$3

12 I Xl

WI

W

• ·BEET SUGAIl TECMHOL06't" (REF 3-1) .. BASIS 15-' APPROACH· 25 PSlGl!! I:FFEr.'f EVAPORATOR

Table 3-1

Two methods of extracting geothermal heat for ~e process were postulatedand analyzed as indicated in Figure 3-1. Alter~te HE-1A considered boilingpotable water in a geothermally heated boiler. to produce process steam.The second approach, Alternate HE-2A, is to utilize separated steam from thewell thus beneficially negating the bOller heat exchanger approach lossesof Alternate HE-1A. However, it is noted that the noncondensibles must beremoved and H2S neutralized. The approach of Alternate HE-1A is selectedas optimum for retrofit applications with remote wellheads requiringreinjection because of the ease in pumping and handling of the singlephase liquid.

Alternate heat extraction approaches with the process adjacent to, orremote from the wellheads are identified schematically in Figure 3-2. TheAlternateHE-1A-1A is selected as optimum for the same reasons as discussedwith respect to Alternate HE-1A above.

A representative schematic of providing geothermally generated make-upprocess steam to the Brawley baseline factory is shown as Option A inFigure 3-3.

3.2.2 Pulp Drying

Beet pulp drying appears to offer the greatest opportunity for fuelsavings in sugar beet factory operations. Pulp drying accounts for 30 to50% fuel demand and it is separate from integrated process steam requirements.The Brawley factory beet pulp nominal drying requirements when processing6,000 tons of beets per day are as follows:

u

SolidsWater

Totals

Wet Pulp20% 19.9 tons/hr80% 79.5 tons/hr

100% 99.4 tons/hr

Dry Pulp90% 17.9 tons/hr

9% 1.8 tons/hr100% 29.7 tons/hr

Several conceptual approaches were postulated and investigated asfollows:

J. Air Dryer Retrofit - One approach is to replace the gas/oilburners with geothermally heated air drying coils and increasethe dryer tube lengths (to increase dwell time) as shown as inFigure 3-4.

3-4

u

OR IRltIUTtOlllUIlIFF

---I'r------"---J'l.:­,

[ "zS TllfATIlEIn ('"",..) ...

SUUI "-, .'" suua I--~!)I('i"-~- ?f,--1l£_F_III_IIlG_:or-llX.lf-tf(~ Il£FIIIIIlG It..~~

J \.."--_= R'. '

lUI OFFOR IRRIIATlOlI

�..-----~I 11-------

J,,,- ..JI\:.JI~, I I

_mIlAn 1lE-1A(WITH Il£IlUEtrfOll)

"TOMB ME·18(lI11llllUI' ll£IIloJEtrIGll)

AI.TEaMTE 1lE-2A(IIITH lE'IloJEtrIOll)

SllElltO _!pTE 1lE-2I(lI11lIIUf IElIloJ[tTIOlI)

Figure 3-1 Well Flow/Effluent Handling Alternatives

WIen

PROCESS

.....--. CONDEfCSATE

DOIIt-HOlE PIMP(TYP)

PROCESS

PRODUCING WELl(TYP)

PROCESS

INJECTION PtJtIP

I1,1,I

INJECTION WELL(TYP)

II

/1'I

II

/1"­I

II

/1"I

ALTERNATE HE-1A-l ALTERNATE HE-1A-2PROCESS ADJACENT TO WElL HEADS

ALTERNATE HE-1A-1AREMOTE WELL HEADS

Figure 3-2 Heat Extraction Alternatives - Pumped Well With Reinjection

..........er_.

......"'1«111I

ellUl:lMCl......•1m"'"••

_.....

eLlMl,•.-

.­.............."'IIMel...

e ...,.........­.....

111111"

......_......

................ DWIo....

..., -.rt

01 ...-.....n_

-:--.....

­....

....-a.......--

"LL' 1.1.1 I.A'Llt "A"

.­...........

.....all.• lilia_a......e"""'"-

.........-...._.

--.ILL' 1'111 IIIILI' nat' _ III"I".L liT'''.'

........

----

­....

.,' ••• a

.J

Ffgure 3-3

GEOTHERMALFLUID

IN

NEW ROTARY WATER TUBE DRYERS

...

..

NEW ... COILS

EXISTING DRYERS

GEOTHERMAL FLUIDRETURN

Coo)I

00

PULPOUT

Figure 3-4 Pulp Dryer -- Option A (Holly Retrofit)

b. Rotary Water Tube Dryer - Rotary water tube (or steam tube)dryers, which are conventional to the chemical industry, asshown in Figure 3-5.

c. Rotary Air Dryer - Rotary air dryers, which are conventionalfor food, feed, fiber and fertilizer drying applications asshown in Figure 3-6.

d. HYbrids - HYbrid drying approaches investigated were the conveyorand autoclave drying approaches shown in Figure 3-7.

3.2.3 Mechanical Power Generation

As mentioned previously in Section 1, high pressure steam turbine primemovers are used in most sugar factories for loads over 200 HP. The mediumsteam pressures that would be available from 300°F geothermal sources would

.not be economic for this serivce. However, in any approach using a binary

system for power generation such as discussed in Section 3.4.2, a Rankinepower cycle could be considered for larger energy consumptive loads.

3.2.4 Refrigeration

Approximately 100 tons of refrigeration is required for crystallized andbulk sugar cooling in the Brawley factory. Geothermally fired absorptioncooling could easily be adopted. The absorption cooling is especially bene­ficial in that it could utilize cascaded geothermal effluents from theprocess or pulp drying applicationi e.g., Carrier Unit l6JB014 would produce100 tons of ref1rgeration using 31' GPM of 240°F geothermal effluent. Th;sflow is equl,valent to one-third the flow of a typical 1,000 GPM well.

3-9

VAPORDRUM

GEOTHERMALFLUIDINLET

t EOTHERIW.FLUID

OUTLETPRODUCT

DISCHARGE

HW TUBES

DRlER DRIYE

PULPFEED

CONVEYORWI....o

Figure 3-5 Pulp Dryer -- Option B (Rotary Water Tube Dryer)

c c

( (

DAMPER

, ,EXHAUST FAN

u

--------

3 PASS/3 CONCENTRICCYLINDER DRUMS

--

PULPINLET

I

-" ,., IIJ....L.I II I 1 I II I I I. -_... I1........., I

1;1 ~IJ~I:::..JS!r=-=-i ==.;;:==-L!- '" -IN t>"""""---~ U

GEOTHERMAlflUID

GEOTHERMALFLUID

our<J~------~

WI--

Figure 3-6 Pulp Dryer -- Option C (Rotary Air Dryer)

RETURN

GEOTHERMALFLUID IN

004 PULP

a\\ J

CONVEYORI-------------

Co\)I...

N

~ CONVEYOR DRYER

AUTOCLAVE

~ - AUTOCLAVE DRYER

t...........-- GEOTHERMAL

OUT FLUID

STEAM JETEDUcTOR

Figure 3-7 Pulp Dryers -- Option D (Hybrids)

c

3.3 Energy Supply System Concepts

The energy supply system is defined as the system including the pro­duction and injection wells, down-hole pump (if required) casing headequipment, interconnecting pipeline and process heat exchanger.

Alternate configurations considering directional drilling versusvertical drilling are shown in Figure 3-8. It has been determined, incosting studies developed by TRW for ERDA, that directionally drilledwells with horizontal throws up to 5,000 feet are competitive withvertical wells and buried interconnecting pipelines for sedimentary basindrilling as in the Imperial Valley, California

A typical field layout of the wells that might be required for processsteam make-up and pulp drying in a retrofitted plant is shown in Figure 3-9.

3.4 Configuration Analyses

3.4.1 Process Control and Off-Design Operation

In concepts .using 300°F geothennal heat for prncesssteam and pulp drying, . .

relatively close temperature approaches are required to maximize the utilization.Wide plus variations in temperature could be easily accommodated; howeve~minus

variations would probably be limited to <5°F. Use of geothermal fluids up to350°F would pennit expanding this lower temperature limiting variation to10 to 20°F.

3.4.2 Combined Fossil Fuel/Geothermal Configurations.

New sugar factory options should consider a combined fossil fuel/geothermalenergy system (Option C) or a total geothermal en'ergy system (Option B) asidentified and shown in Figure 3-10. .

3.4.3 Geothermal Resource Variations

Three representative situations were considered based on variations ingeothermal source fluid characteristics:

3-13

PROCESSFLUIDHEAT EXCHANGER(TVP)

I IS,'":11I"~

~- PRODUCING WELL (TVP)

-II

../I~

INJECTION WELL (TVP)1_....

-

WI-~

ALTERNATE A ALTERNATE B

DIRECTIONAL DRILLED VERTICAL DRILLED

c

(

Icr::~u:;)QZou

-W :ot:-I U

~ <Q..

-IN W......

~-'co (!J

gN

IU-I§!

=N.....-1800' DEPTH .....-2000' DEPTH

(!Jz

IU ~I-I

~§!

=QW

~~.....- W

N

~I-it)

5500' DEPTH

TOTALVERTICAL

DEPTH _._.:., -- .

(TYPo 3 WELLS) ~ (!J

z= ....\D VI

60' DEPTH N (5IU

~~VI

~M-

48- DEVIATION BOUNDARY

Figure 3-9

TYPICAL 5-SPOT PATTERN REINJECTION(12 PRODUCERS - 8 INJECTORS)

APPROX. 11 00 LIN. FT. "Mo

~lor--+----------------------;,L.-.:I---OF 7 INCH SCREEN ii';.;<

6500' OEm~" -I I

(Reference: "Planning an,d Design r 2000' THROW Iof Additional East Mesa Geothenna1 -Test Facilities". TRW contractwith ERDA

TYPICAL EAST MESA ,WELL SECT~

WELLHEAD LOCATION (ENERGY SUPPLY CENTER)

PRODUCING WELL BOTTOM-HOLE LOCATION

INJECTION WELL BOTTOM-HOLE LOCATION

SECTIONLINES (TYP)

(

'of­V1

• lIra ..ra-• 1Iff.' M'fIlT­.....ICI.............-..........-

.-.....• TllII"'IClIUTOS• "'."la_1UI• 1Il1ft".• MCUlIUTII.IoI.IIILtIl

.­.......e ... _ •......._-......

CIOLI.TCIIU

.MlMa""lll...........-...

.-.....• 1Il IClICA1IIS• .,IMII_IWlelllttt,.• IIIlIc.lllAlII• LlIIIf.1U

.lIfFUSlI• II ... ,.• IIIIIf~l1P.......1ll1lMa

lEA"D

.....,-

'ofs:

I~ I~"-__.L _--':/=-1 r-'----

"11" • _.. II' ,t.al'til.' ..... , "III""ClII)

", ... c - ·1.1 f, ... ,1-I',fll •• AL ".ClIS)C'IUIL 'ilL ""1) .."-­.......

--.._.,........---­..-!!!!!- ...­"'AClLmuDDAIn'MIIIT

MII.-nGMT..~,.......-Figure 3-10

c c

Case I

u

Resources under 300F - Typical of Imperial Valley.California, (Sedimentary)

Case II -- Resources under 300°F - Typical of Pacific Northwestand Mountain States (Volcanic)

Case III -- Resources between 300 and 350°F

Representative considerations for Cases I and II are indicated inTable 3-2.

The following conceptual designs. performance analyses and costs arebased on the assumption that well fluid salinities are 25.000 ppm or less.In the event brines of higher salinities are encountered '(e.g. Westmorelandor North Brawley well fluids). techniques other than chemical cleaning maybe required and maintenance costs must be adjusted accordingly.

3·17

Figure 3-8 Well Configuration Alternatives

TABLE 3-2. CASE I AND II CONSIDERATIONS

WI-0)

ISSUE

SALINITY (TDS)SOURCE TEMPRESOURCE LONGEVITY

HEAT EXCHANGERS

WELLS

CASE I

2.000 TO 300.000 TDS. 300 TO 400°F

• REDUNDANT FOR CYCLE/CLEAN• CONTINUOUS SCALE CONTROL

• LONG TERM/MANY WELLS EXPERIENCECERRO PRIETO. HEBER. EAST MESA .

• SAND SCREEN COMPLETION

CASE II

200 TO 800 TDS150 TO 350°FFRACTURE PERMEABILITY(LESS LIFE EXPERIENCE)

• LESS MAINTENANCE ANDCOST THAN CASE I

• HIGHER DRILLING COSTS• MAY REQUIRE STIMULATION

AND WORKOVER

• CLAW FOOT COMPLETION

PROCESS APPLICATION • INTERMEDIATE HEAT TRANSFER LOOPS • POTENTIAL USE CLEAN• PROMISING TEMP TECHNICAL STEAM DIRECTLY

FEASIBILITY .'. BORDERLINE TEMPTECHNICAL FEASIBILITY

cEFFLUENT • MUST REINJECT • POTENTIAL USE FOR

IRRIGATION

c

3.4.4 Holly Sugar - Brawley Factory Retrofit

Beet pulp drying and provision of medium pressure make-up processsteam have been identified as promising applications for geothermalheat in a beet sugar factory. Conceptual designs of boilers and dryerswere synthesized and analyzed which led to a selected cascaded boilerto dryer optimum configuration. This selected application approach wasthen adapted conceptually to a retrofit of the Holly/Brawley sugar fac­tory as described below.

3.4.4.1 Steam Generation

The 34% exhaust (approximately 75.000 lbs/hr) make-up steam at theHolly Brawley factory that would normally be supplied by throttling liveboiler steam can be supplied by a geothermal boiler. The preferreddesign would be to boil potable water in the boiler shell by flowingbrine through the boiler tubes. The one expected problem area ofscaling deposits on tube interiors can be satisfactorily covered byperiodic chemical cleaning.

II

A preliminary steam boil~r design and study was made by Southwestern. I

Engineering. This study was based on using 300°F geothermal brine todeliver 75.000 lb/hr of steam at 25.psig (268°F) with an 0.002 designfouling factor.

With 300°F brine and 1" 0.0. carbon steel tubes. computer runs showedoptimum velocities ranging from 4.3 to 7.4 ft/sec and brine pressure dropsranging from 3 to 9 psi. Boi;ler size varied from 78 to 84 inches in dia­meter and 43 to 49 feet in length as shown in Figure 3-1.

3-19

· 43' TO 49'

w,No

300°FBRINEINLET

~

25 PSIGSTEAM

°1ET

78" TO 84"

277°FBRINE

OUTLET

tCONDENSATE

RETURNBLOWDOWN

FIGURE 3-11

GEOTHERMAL BOILER75,OOO#/HR OF stEAM

(Reference: Append1 x A) ,

.'

The required brine flow is plotted versus boiler heat exchangersurface and cost in Figure~12. The optimum selection criteria isthe boiler surface providing the lowest geothermal brine flow rateand highest temperature drop (greatest energy use) because the wellsare significantly more costly than the boiler, by an order of magni­tude. The optimum configuration is a boiler with 20,300 square feetof heating surface with a brine inlet flow requirement of approximately2,600,000 1bs/hr (5,875 GPM) and a boiler brine outlet temperature of274.8°F. This brine flow demand could possibly be accomplished withfive geothermal production wells.

The San Diego Gas and Electric Company recently performed an ex­tensive test program on subsca1e heat exchangers using geothermalbrine of approximately 355°F and 14,500 ppm dissolved solids at Heber,California as work sponsored by the Electric Power Research Institute.These salinities are similar to those experienced at East Mesa andanticipated on the fringes of the Brawley anomaly near the Hollyfactory. The report, EPRJ No. 376 dated September 1975 is titled,"Test and Evaluation ofa Geothermal Heat Exchanger."

The tube (four)-in-she1l heat exchangers were assembled as foursections in series and three common tube materials - titanium, carbonsteel and 90% copper - 10% nickel were tested.

After 560 hours of testing, the titanium tubes showed no corro­sion and the carbon steel tubes showed slight pitting and decarburi­zation. After 200 hours, the copper-nickel tubes had some corrosionand it was evident they corroded at a much more rapid rate than thecarbon steel tubes.

3-21

3000 GEOTHERMAL BRINE25 PSIS STEAM BOILER

75,000 LBS/HR

..... ~ " . ·1i I

t, :I

21 .. ~.

:

19220

19180

18170

17160

16M 1500->< 15t: 140

14 .....en ,

I .. 130L&J ...Co.' 13 .. ..~c:: 120::;)

ien12 . .. . .. 1.. ..

11011 . . . .. .. ..,

!100

1090

9 ..

808

2 3 4 5 6

BRINE flOW - LBS X 106/HR

FIGURE 3-12 BRINE FLOW VS BOILER SURFACE/COST

3-22

The tests indicated that the scaling rate is primarily a func­tion of brine velocity and that a heat exchanger system will performbest at velocities of 5 to 7 ftlsecond and at a minimum brine exittemperature of 150°F. Pressure losses with scale deposit build-up isessentially the same in either titanium or carbon steel tubes and willnot be prohibitive over normal operating intervals. Heat transfercoefficients decline with time regardless of tube material and brinevelocity.

Figure 3-U indicates reduction of boiler capacity due to foulingwill be minimum at the selected design flow rate of 2,600,000 lb/hr.Anticipated boiler operations between cleanings is in excess of 30 days.

Final test results showed that carbon steel tubes would be entirelysatisfactory and very close to titanium tubes in performance character­istics. The choice of carbon steel tubes over titanium tubes in a fullsize exchanger will affect material cost savings of from 22 to 75%.Engineering and installation costs would be the same.

Up to 1/8" thick scale deposits can be removed by pumping a 50%caustic solution at room ,temperature through the heat exchanger tubingat a velocity of approximately 0.2 ft/sec for 15 to 30 minutes. Thiscould cause some degradation in mild carbon steel tubes and thereforean acid cleaning solution may be more appropriate. Solutions can bereclaimed and reused at least six times.

The recommended boiler configuration for development and demonstra­tion testing should include one inch 0.0. carbon steel tUbes. Longduration tests are required to establish scale buildup and performanceimpact with the design conditions identified for this application.

3-23

3000 F GEOTHERMAL BRINE

o .004 (DIRTY).....

"1' .. t· : - I .. r. .. II !

.• o. O' • : - - -~_. t· ... . ~

. . I . ZERO (CLEAN)I..... T

------------- .002 (DESIGN)

140

130

120

110

100

90

•c::80:c

::;:)

t;I 70

~ 60

50 ...... .. .0

I

'0'

j

40 ;

30 ,.. ... .

20 .;

.1;

10

o2 3 4 5 6

BRINE FLOW - HM LBS./HR.

FIGURE 3-13 BOILER CAPABILITY VS FOULING

3-24

~3.4.4.2 Pulp Drying

As previously stated, beet pulp drying, which accounts for from30 to 50% of plant fuel demand, offers a great opportunity for fuelsavings by switching to geothermal energy.

Many manufacturers of various types of cOlJ1llercial food/graindryers were contacted. While none had ever supplied dryers usinggeothermal brine at 300°F for drying, most felt it could be done andgave preliminary estimates of retrofit equipment. All were in agree­ment as to the necessity of a demonstration/test program on a subscaledryer to provide backup data for a full scale design. Most wereinterested in participating in the program.

Alist of the manufacturers contacted is as follows:

Rotating drum with brinecoil at air inlet

Rotating drum with brinetubes in drum

Rolling Tube

Continuous Conveyer

Fluid Bed

Desiccant Dehumidifier

Heil Co., Milwaukee, WisconsinApplied Equipment Co., Van Nuys, Calif.

Stansteel Corp., Los Angeles, CASwenson Evaporator Co., Harvey, Illinois

Sterns-Roger Co., Denver, Colorado

Proctor &Schwartz. Philadelphia. PA

Tailor &Co., Bettendorf, Iowa

Dry Air, Inc., Sunbury, Ohio

u

"Since conflicting performance predictions were received from someof the dryer manufacturers a separate analysis was performed in-houseto develop a better understanding of the process with low drying tem­peratures.

In order to predict the performance of a low-temperature dryer,it was necessary to obtain some properties of the pulp in the dryerwhich were not available in the literature. These properties are the

3·25

heat transfer between the drying stream and the pulp (Btu/hr-1b pu1p­OF) and the evaporation rate from the pulp (lb-H20/hr-psi-1b pulp).Approximate values of these two coefficients were obtained by analyz­ing present high-temperature dryers (Fi gure 3-14 and using the resu1t­ing values to predict 1CN- temperature dryer performance (Fi gure 3-15.

As expected, the results show that a 1CN-temperature dryer, whilecapable of delivering a product with the required moisture content, ismuch less effective than a high-temperature dryer. Specifically, forthe same volumetric flow of the drying stream, the rate of flow ofpulp is reduced by a ratio of five to six, and the reqUired residenceor dwell time of the pulp in the dryer is increased by a factor offour to five as indicated in Figure 3-16.

These results coincide with one dryer manufacturer's estimates ofa total of 16 dryers to replace the existing three fossil-fueled unitsat the Brawley factory.

The recommended drying approach considers a three pass rotatingdrum dryer (of the type manufactured by the Hei1 eo.) modified with ageothennally heated air drying coil as shown in Figure 3-17 Thisthree pass approach appears to accomplish the increased dwell timerequired with minimum overall space requirements.

Increased efficiency in the use of geothermal fluids for the beetpulp dryers can be accomplished by preheating the supply air with theheat energy of the dryer warm air exhaust. This can be accomplishedby placing a finned tube economizer coil in the 150°F dryer air exhauststream as shown in Fi gure 3-17 Water in the tubes would be heated to122°F and pump circulated in a closed pipe system to the finned tubesof a preheat coil located in the path of the air supply, upstream ofthe main geothenna1 brine heating coil. The preheat coil would heatthe 70°F air supply to 106°F. The water, now 78°F, would return to

the economizer coil to be reheated and the cycle repeated.

3-26

80 ~······t:::~~:~J.:~i:·::FTGl':::::.:n:::.::::r:;;nm;:~:::n:';~:::';fT::::::T

~70' ··:.:!~;i>;~:;:~~~~!f:~f~~~:·:":·T:T:ir:~:~~iiiF~~~~l~:~;r:~;:!~:::'~:

~ ::ilf~!r;J~:.j •.·:·;]·;·:·-.-Tt~4;~It;j':~'·r!~r40 . ·~;:.:.,::i::;::::-:~: ;..:...; :.:.i :: ;.:;~: ":.;..+_.;.~)..:.~:~~;;..:~~ ~:

: . " .: ,":.. : ," . ':.. ... ...• ; ;::;,": •.:~ ' .•••. : ':.~'.: .~.'" .,:' '-0. -' • :.• :': •...•~.' .:~"i:

. . .30 ·~L:·:····; ..;:;····:·:· -: ..··:·".·t· .~.; .. :: :-:~ : :.;, .·VAPOR

..

ACFM EXHAUSTLB PULP/FTLBPU~P/HR

20 .

10

. ,-.. .

.. .- ; ~ :. - __ :~ ~ ... . :-PULP

8 o . . ...... .. - .. .

. . .__ •••••••• 04. ••• ...... _ •••• ' ••

AT PULP TEMP

··~--~VAPOR.;' :~~.:..-, ..'. - - -.--

: ,<;:. .; : :..,.. : :. : PULP...... ...

__---~::::::::=::::--~ VAPOR

. . - .. ..: : :_._ : ... . ... .. . ..

.. :' '.. "... :........ -..... .:: .:;.;. ::.:, : .; ::_:. : :.., .'.". .. :;.: ,.: . :.. :

..........~~ ~_ ~~ ..;. ~ -~-: .. -; ": .: ;.; .. :": ::;.:..:.:~ .. :~..:.. ~.,~: ~ .~-

c.. 15050..'00

1

o 1200

1000

u.. .. .

, - .. , .50 a..- ........---;.....;.---~.....;..-

o 10 20 30 40 50

DRYER LENGTH - FT

FIGURE 3-14 HIGH TEMPERATURE DRYER TEMPERATURE &MOISTURE PROFILES3~27

. ... . ~ .... --.-..._--

..._._- '-'--'-.... ..

... ... .

.........._....--- .._.... --_..-.. . ... . , . ...

: : . " :; ':'~ - :.. .: .. ;: .. ::. .: ~ . :.. . ... .. :... ~.._~~_.~.~ .. ~~:-:--~~ .... :.:.:~ .._.. :':"~;'_.':7~

. PARTIAL PRESSURE IN VAPOR< .. ~ ... ;_._~_.;:~~~

~,,:~··:··r: ...:T: ::. ;..:~:~.~-;·:~;::::r:~. :::. ·~~··::r~:::~:·r·~:;-·:· :;.::: :::.:.::::~" ~.. :. ~~._:~ _: ~.. :. ~. _; .- _-~_ :._ :'._:. r. "~"f:-~:'~':" .;. :.;.:.--".~ -:": ~_ :·.'·7~f~~;.:·~

'; .•• "',0_"",,: .::.::.:<~~.;' .:,::,; .... : ~:::~:::,:- ::-::. ,', _..

o . ...~.:::_.~ ;-: ':~::~i-:: :.- : -:··:'-~.7· .. :.~_:.:: .-

30

. '~7"~'~ . -:. ... ~.: ... 0 .....~~ ._~ ••• t... •• :.~. ~;..: ': ••. :" : ••~_ ...~.-:~ •• ~:. :+'~:;~~'~':~-r~ _::-:- :':7~~:+::~.... ,. .. . , : : :.:::::..:.: : :, ..: :.. : .:.~:;.::.::::: :·:··::i·~:: .. :;·:.c:~:::;;·

::- 200··:·L. :"·-r::·7'-··:-~:-::~-0q~··~:>~:~:::~+:;<+~+H

~ ~~::f:;.f-<h:[~<: :... :···::'-:L~_:~.:t::.:it~:L:j;:;;~:j·tt.L:t::~s~~;i:~T:~j~~ell: ~::::::::n.::::-t.·:i~··:i- . ..:.. :.;-:- : ::. ::.:.:.:: .. ::: .:::.: :..i 150 ::~:~~IlTF~r~· :~:..L:; :=~~t:.lL :(~:.,;.:: ::::;. :!:::.: :; ..:;;:::~d.L)L0U:J ::~~r:w

~

50 ~tr;~3"t,':~;~~IH{~~ff:CJ~E~f:} ';~f,~It ~~~o 10 20 30 40 50

DRYER LENGTH - FT

0.7

0.8

0.5

0.6

0.3

0.4

0.2

0.1 250

FIGURE 3-15 LOW TEMPERATURE DRYER TEMPERATURE l MOISTURE PROFILES

3-28

EFFECT OF INLET TEMPERATUREON LOW TEMPERATURE DRYER PERFORMANCE

DRYER SPECIFICATIONS:100,000 ACFM EXHAUST

80~ MOISTURE INLET9~ MOISTURE OUTLET

132.5 LB PULP/FT50 FT LONG, 10.5 FT DIAM

200

150

.._-~_ ..;~~::~ ..... ~ ....:.. ~.,; ;. -.. -:.. ~. :_,:~.,;.:.:..~~~ .._. : .:...... :-....-.. .:.

• : • • • • • • • • • :..., < .:;. '.. : ~:. • ~: ••• : ~;

~ ...

.-100

2 ....

1

o ..~ : ..

4

3 - a::::c: .0,_,,,

. ... '. . . .. .

300

. ... .. . . .. _......... . ..o • • • •. . .. . . .,

":" ..: ~ .....; .... '"..... ~ .....".... .. ... .: ...~ ..: .. :".. . .. . . ..

• 0" •••• ,. ••••• •• • .. .. . . ... ': ~... :..:'.!.::;:~~:: ;..~.:;

. . . ... "~"'-~-"~':"'.' : .. ~.~.. ; .. :..... : .... :.:-.....~,. .,. -.

200

7 . .

4

6

5

3

250VAPOR INLET TEMP __ OF

FIGURE 3-16 EFFECT OF INLET TEMPERATURE ON LOW TEMP DRYER PERFORMANCE3-29

FIGURE 3-17

GEOTHERMAL SUGAR BEETPULP DRYER

AIREXHAUST

c

CYCLONESEPARATOR

DRYPULP

DRIVE

FAN

1500F

12~F

- OTA:ING ~:~: .-:p:I I

DRYER --.. I I__ III I

l,..1=~~..d..l.- ---- I I_:.:-_~-.:.: ---~:~ _~..J

277° OR3000FBRINEFROM

BOILER BEETOR WELL PULP

HEATING-...COIL

c

TOREINJECTION

WEll

AI-R PREHEAT700F COIL 106°F

IfCo)o

This system reduces the required heat for the main heating coiland results in a lower geothermal brine flow rate which translatesinto a lesser number of the costly geothermal wells having to bedrilled. Energy savings of twenty percent can be realized by theaddition of a heat recovery system at each pulp dryer.

3.4.4.3 Cascading

Geothermal fluid can be used most advantageously by cascadingfrom one type of usage requiring the high initial temperature into asecond type of usage able to use a lower temperature. Cascading canutilize more thermal energy and therefore result in. higher efficienciesand the lowest cost per million BTU·s.

Cascading at Holly/Brawley can be accomplished from steam boilersto beet pulp dryers as indicated in Figure 3-18. The brine would firstbe used in the boilers to produce the required amount of 25 psig steam(from water other than the brine). From there the existing brine. nowatalower temperature of around 275°F. would be run through the mainheating coils of each beet pulp dryer to heat incoming atmospheric airto 250°F. The heated air would then move and mix through the rotatingdrum dryer to absorb the entrained moisture and dry the pulp. Thebrine. now down to 140°F. would be returned to a reinjection well.

3.4.4.4 Brawley Sugar Factory Retrofit

Brine pipelines from offsite supply and reinjection wells. (Figure3-l9 could be run underground along the south shoulder of theeast-west private road of the Holly property adjacent to fenced northfactory boundary as shown in Figures 3-21 and 3-21. Branch takeoffs fromthese main headers would be routed underground to the retrofitted geothermalsteambotlers and bank of sixteen geothermal pulp dryers. Manual andautomatic valving together with distribution and by-pass pipe mani-folding would be provided to allow the dryers to operate as a cascadedownstream of the steam boilers or independent of the boilers as

3-31

AIREXItAUST

DRYPULP

DRIVE

12~F

-------=--------~-l- ---- -------, I

- IOTATING DRIJl __::

DRYER I I, I, I

l----,--::;,.L- - - - _::-: - _:l\ :t:=:...::=<:::;;.-, ~__~.J-

215°F BEETPULP

AIR PREKEAT KEATING06°F --

100F COil COil

CONDENSATE_....."- .-.JRETURN

TOREINJECTION

WEllS140"F

Figure 3-18 cascade Boiler to Beet PulpDryer Schematic

r r

w•ww

• w

\ ,

I

\

,,

\

__IFUI------ .-

... - ................

McCULLOCHPRODUCTION WELL

I I,~INJECTION

-

28

•=

•

FIGURE 3-19 PLANNED GEOTHERMAL WELL DRILLING(Pendi~9 ERDA approval of pending geothermal loan guaranty application)

"_,,, T lreTJ20f"'IT PLAN____ T TJIIIt

\IOLVII ~.."J. __ -----

. Bl?INE o;,uPPLYCOt-J1'l2oL ,. 1C'EINJEOION~1.jE:MATIC.

Figure 3-20

r

c

Figure 3-21 Aerial View Holly Retrofit Concept

(

shown schematically in Figure 3-10. Either boiler or any dryer could <-.Jibe shut down without affecting the operation of the remaining boileror dryers. Flow control and motor operated valves for proper cascadebrine flow balance from the boilers via the reinjection pipeline toreinjection well and to dryer brine supply would all be contained ina covered grade level concrete valve pit. Pressure control valveswould be located in the end of the brine supply-reinjection loopfor both the boilers and dryers to provide flash preventing backpressure.

The location for the geothermal dryers has been selected forloading convenience of other than beet pulp drying (e.g., alfalfa)and the need of a larger area to accommodate the sixteen units. Theexisting pulp presses would have to be relocated adjacent to the newdryers and new conveyors would be installed to move the wet pulp fromthe slicing area to the presses as shown in Figure 3-10. Dried pulpwould be collected from the dryers on a covered conveyor and routedto a covered shed housing the relocated pelletizer. From there thepellets would be moved on a covered conveyor to the outdoor pelletstorage area.

3.4.4.5 Brawley Factory. - Geothermal Application Potential

The retrofit and new factory potentials for geothermal applica­tions to the Holly Sugar, Brawley Factory are shown in Table 3-3.As shown, the retrofit potential reduction of fuel oil demands isapproximately 65% and new factory potential reduction approximately·86%.

3-36

TABLE 3-3 ~OLLY SUGAR BRAWLEY FACTORY - GEOTHERMAL APPLICATION POTENTIAL

CAMPAIGN EQUIVALENTFUEL DEMANDS RETROFIT POTENTIAL NEW FACTORY POTENTIAL

BARRELS GEOTHERMAL GEOTHERMALFACTORY DEMAND % OF OIL 300°F BBL/OIL 300°F BBL/OIL

LIVE STEAM TO SLICERS (1 r 2.2 7,730 ---. 7,730 * (PART) 2,300 {COM;')

TURBINE EXHAUST STEAM TO PROCESS (2) 20.4 71,820 71,820 *THROTTLED MAKEUP STEAM TO PROCESS (2) 25.1 88,180 * *ELECTRICAL GENERATION (2) 10.2 35,580 35,580 35,580

wI

TURBINE MECHANICAL DRIVES (2) 1.9 6,840 6,840 6,840w......

SUGAR COOLING REFRIGERATION (2) 0.8 2,840 * *PULP DRYERS (1) 39.4 138,350 * *

TOTALS 100.0 351,340 121,970 44,720

(1) 126 DAYS IN 1976 HOLLY/BRAWLEY CAMPAIGN

(2) 174 DAYS IN 1976 HOLLY/BRAWlEY CAMPAIGN

3.0 REFERENCESu

3--1 R. A. McGinnis. Beet-Sugar Technology. Beet Sugar Development Foundation.

3-38

4.0 CAPITAL. OPERATING AND MAINTENANCE COST COMPARISONS

Total costs of candidate geothermal application approaches have.beendeveloped for comparison with conventional fossil-fuel supply costs. Thetotal geothermal costs are developed to include effects of capital. operatingand maintenance costs. The annual fixed charge rate of 21.6% was calculatedusing commercial money rates. depreciation factors and tax rates of fourthquarter 1976 as a present value basis. Geothermal costs are developed indollars per million BTU's as a comparison basis with the fossil fuels;e.g•• Brawley·fuel oil costs for the 1976 campaign were $2.23/106 BTU's.The costs developed in this task as inputs for the economic evaluations ofTask 6 are based on the retrofit Brawley factory conceptual designs describedin Section 3 and summarized in the following sections.

4.1 Sugar Factory Capital Costs

Capital costs for a typical sugar beet processing plant are shown inTable 4-1. Cost data was obtained from Holly Sugar and apply to a typicalplant processing 6000 tons of sugar beets per day such as the Holly plant atBrawley. Capital costs shown in Table 4-1 have been escalated to 1976prices. As this table depictS. a typical plant can cost approximately 64million dollars.

4.2. Energy Supply Costs

The capital costs of supplying geothermal energy to the sugar refiningprocess can be divided into those capital costs associated with wells andtransmission of the geothermal fluid to the sugar refining process.

4.2.1 Wells - Capital Costs

Energy supply costs for a typical geothermal system are based on capitalcost estimates developed for East Mesa geothermal fluids in previous TRWstudies for the Bureau of Reclamation (Ref. 4-1). ERDA (Ref. 4-2) and theNational Science Foundation (Ref. 4-3). These costs are shown in Table 4-2.As indicated. these costs are based on well. piping and pump costs. Theestimated cost factors for land acquisition. exploration and environmental

~ impact represent approximately 9 percent of the total. The costs shown inTable '4-2 apply to a geothermal system and injection wells all drilled

4-1

Table 4-1 SUGAR BEET PROCESSING PLANT COSTS

(TYPICAL 6,000 T/DAY PLANT - 1976 COSTS)

APPROXIMATECOST %

BEET END OPERATIONS = $16 ,000 ,000 25

SUGAR END OPERATIONS cc 12,160.00 19.tloI

NPULP PRESSING AND DRYING = 7,680,000 12

STEAM AND POWER GENERATION = 7,680,000 12

SUGAR STORAGE AND HANDLING = 7, 680,000 12

SITE IMPROVEMENTS = 12,800,000 20

(LAND, WELLS, FIRE PROTECTION, ROADS,DRAINAGE, MISC. BUILDINGS)

TOTAL = $64,000,000 100

u Table 4-2. NOMINAL ENERGY SUPPLY CAPITAL COST ESTIMATE(Third Quarter 1976)

Item Description .. Cost Basis

1 Production Well and Tree $400,000 Vertical6,500 ft depth2,000 ft 13-3/84,500 ft 9-5/81,000 ft slottedGravel pack20 acre spacing

2 . Injection Well (Prorated) 266,700 Ratio 3:2

3 Sub-Total (ST) $666,700

4 Piping 66,670 f I: 0.10

5 Downho1e Pump 72,000 1,000 GPM20 MD60% EFF

·6 Injection Pump (Surface) 47.500 1,000 GPM20 MD .60% EFF

7 Land Acquisition (leasing, 40,000 f = 0.06fees)

8 Exploratory Holes (3 or 4 13.300 f I: 0.02Success) .

9 Surface Exploration 20,000 f II: -.03

10 Environmental Impact 13,300 f =0.02

Total Capital Cost. $939,500

per 1.000 GPM

Note: Total f I: 1.41 (basis 2 to 6 production wells)f I: Well factoredest1mate after Tester (Ref. 4-4).

4-3

vertically to a depth of 6500 feet. pumping 1000 gallons of 3500F fluidper minute. Capital costs shown in this table are for the third quarterof 1976 (Ref. 4-2 and 4-4). As can be seen. the capital costs for thistype of system would be slightly less than one million dollars.

Table 4-3 shows assumed annua' fixed charge rates for geothermal fluids.For estimating purposes. the fixed costs of the energy supply system wereassumed to be an annual fixed charge rate on the capital investment requiredfor wells. The assumed annual fixed charge is 21.6 percent and includesminimum acceptable returns on capitalization (debt and equity) income taxes(California and Federal) and miscellaneous factors including estimatedadministrative and general expenses. insurance. ad valorem taxes and adepreciation sinking fund annuity.

An example of the translation of estimated capital costs and assumed annualfixed charge rates into comparative prices (costs) are shown for East Mesageothermal fluids as tabulated in Table 4-4. The energy value potential foruse of geothermal fluids. such as East Mesa. is favorable when compared tocurrent most probable fuel costs such as the Brawley fuel oil costs for the1976 campaign of $2.23/106 BTU's.

4.2.2 Transmission CostsTransmission pipeline costs are demand dependent and are therefore

developed in conjunction with application cost evaluations as describedin paragraph 4.4.4.

4.3 Electrical Costs

To assist in comparing costs between a total geothermal system. a totalfossil fuel system and a combined fossil fuel/geothermal system. electricalgenerating costs for 3000F and 3500F brines are presented in Table 4-5.This economic data can be used for evalutating the replacement of thefollowing:

• total replacement of the fossil fuel boiler system (geothermalenergy provides both process heat and electrical energy)

• partial replacement of the fossil fuel boi"ler system (geothermalenergy provides only process heat)

• no replacement of the fossil fuel boiler system (fossil fuelprovides both process heat and electrical energy)

4-4

~•U't

(

Table 4-3 ANNUAL FIXED CHARGE RATE ASSUMPTIONS

ASSUMPTION * RATE (%)

COST OF f«>NEY --FRACTION OF CAPITAL IN BONDS 42%

INTEREST RATE ON BONDS 8% 3.4

FRACTION OF CAPITAL IN EQUITY 58% --RETURN ON EQUITY 15% 8.7

TAX RATES -- 5.3

MISCELLANEOUS

ADMINISTRATION AIlD GENERAl}

INSURANCE 3.5

ADVALOREM TAXES .

SINKING FUND (DEPRECIATION) 20 YR 0.7

21.6%

* REF. 4-5

(

Table 4-4 ESTIMATED GEOTHERMAL PRICES (COSTS)

ASSUME

• DEMAND FACTOR OF 80 PERCENT (7,008 HRS/YEAR)

• HEAT EXTRACTED 350°F TO 250°F AT 1,000 GPM

THEN

ANNUAL FIXED CHARGES ( 939,500 x 21.6% ) = $28.96.e:.. 7008•0\

MAINTENANCE ( 939,500 x 0.5% ) = 0.677008

OPERATING PUMPS (500 KW AT 30 MILLS/KWH) = 15.00

FLUID COST/HR OF OPERATION $44.63

GEOTHERMAL FLUID COST (250°F to 350°F) = $ 0.89/106 BTU

\

(Table 4-5 GEOTHERMAL ELECTRICAL GENERATION COST ESTIMATES

WtLLHEAD TEMPERATURE -- 300°F 350°F 400°F....................................................... I '.......... .. , •••• .. ..

UNIT PLANT COST(l) FOR 50MWeNET PLANT $520/KW $490/KW $460/KW••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••

ESTI~ATED UNIT COST(l) FOR 5MWe NET PLANT (ADD 50%(3»

WATER RATE, LB/HR PER KW

UNIT WELL COST(l) AT $1.25 PER LB/HR(2)

TOTAL UNIT COST(l).po

~ DIRECT CAPITAL COSTS(l) FOR 51~e NET PLANT &WELLS

TOTAL CAPITAL COSTS FOR 5MWe (AOD 25% FOR ENG.,AlJrt1IN., ESCALATION)

$780/KW $735/KW . $690/KW(3)

275 150 110

$345/KW $190/KW $140/KW

$1125/KW $925/KW $830/KW

$5.6 M $4.6 M $4.2 M

$7.0 M $5.8M $5.2 M

•••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••

MILLS/KWH AT 80% PLANT FACTOR,20% CAPITAL CHARGE

44 36 34

(1) DIRECT CAPITAL COSTS ONLY Ref. 4-6

(2) E.G., A $500 KWELL FLOWING 400K LB/HR

(3) SOURCE: HAWAIIAN ELECTRIC ESTIMATES

Table 4-5 shows costs of electricity generated from geothermalenergy. The data in this table applies to the total geothermal systemonly since both the energy for process heat and electrical generationwould be replaced.

4.4 Brawley Factory Retrofit Concept

The following costs were developed as inputs for the economicevaluations of Section 6 based on the retrofit Brawley factory conceptualdesigns described in Section 3.

4.4.1 Geothermal Boiler

The costs of generating the make-up steam for the Brawley factorywith different boiler configurations, is indicated in Table 4-6 for thestudy criteria, 300°F geothermal brines. As indicated, lower brineflows have a more beneficial cost impact than boiler first costs asdeveloped in Figure 3-2. Also, it is noted that the minimum cost($4.40/106 BTU'S) with the boiler as the sole brine user, is not com­petitive with fuel oil costs of $2.23/106 BTU's. However, with geothermalbrines at 350°F, as shown in Table 4-7, the single use boiler costs of$1.76/106 BTU's look particularly attractive.

4.4.2 Beet Pulp Dryer

The costs of drying beet pulp with rotary air dryers using geothermalbrines at 300°F are shown in Table 4-8 for a range of supply air andbrine outlet temperatures. As noted, the costs are marginally competitivefor all applications considered.

4.4.3 Cascade Boiler/Dryers

Tables 4-9 and 4-10 show what happens when either 300°F or 350°Fbrine is cascaded first through the 25 psig steam boiler and then throughthe beet pulp dryers. In these modes the cost per million BTU's is $3.10for 300°F brine and $2.22 for 350°F brine. The economics really lookattractive if the cascaded dryers can be operational beyond the sugar

4-8

Table 4-6SUGAR BEET REFINING - 25 PSIG STEAM GENERATOR

300°F GEOTHERMAL BRINE -- 75,000 LB/HR STEAM

~..

BRINE HEAT BRINE BOILER WELLS PUMPING BOILER TOTAL COSTFLOW LOAD COSTS COST COSTS PERI/HR BTUH AT TEMP SURF. COST 3ft/KWH MILLION BTU'S

GPM x 106 our SQ FT EA NO. COST$x 106 Of $/HR $/HR $/HR* $/HROF x 103 $ x103

..

5 10879 70.05 13.6 286.4 10.35 98.5 10 545.5 23.4 15.8 584.7 8.35

4 8703 70.05 17 283 11.5 10.3 8 436.4 18.7 16.9 472 6.74

.'

'.

3 6727 70.05 22.7 277.3 14.3 138 6 327.3 14 17.8 359.1 5.13

'.'

.2.7 5875 70.05 25.2 274.8 20.3 192 5 272.7 12.6 22.5 307.8 4.40

Costs are based on 21.6% AFC and 3.960 hours (5-1/2 months) operation.*. .Includes 35% installation, est. piping, valving, instrumentation and 2% yearly maintenance.

"""•-o

Table 4-7SUGAR BEET REFINING - 25 PSIG STEAM GENERATOR

350°F GEOTHERMAL BRINE -- 75,000 LB/HR STEAM

BRINE HEAT BRINE BOILER WELLS PUMPING BOILER TOTAL COSTFLOW LOAD COSTS COST COSTS PER#/HR BTUH AT TEMP SURF COST

COST 3¢/KWH MILLION BTU'S

x 106 GPM x 106 of OUT SQ FT EA NO. $/HR $/HR $/HR* $/HR $?$ X10~of x 10'01

.

1 2243 70.05 66.7 283.3 7 70 2 109 4.8 9.3 123.1 1.76

1.2 2691 70.05 55.6 294.4 5 50 2 109 5.8 7.7 122.5 1 .68

1.4 3139 70.05 47.7 302.3 4.4 44.3 3 163.6 6.8 7.4 177.8 2.54

1.6 3588 70.05 41.j 308.3 4.3 42.5 3 163.6 7.7 7.4 178.8 2.56

Costs are based on 21.6% AFC and 3,960 hours (5-1/2 months) operation.

*Includes 35% installation, est. piping, valving, instrumentation and 2% yearly maintenance.

c c

"..I-..-..

Table 4-8

Sugar Beet Pulp Replacement DrYers

300°F Fluid - Holly/Brawley

Airflow Temp. Flow No. Coil Rows/Dryer. Flow No.Est(4) Est(S)

Est(6)Heat CostTemp. per Brine Brine No. Brine Geo. Cost Cost· load perAir Dryer Out per R-21 R-24 Dryers Total Wells Dryers Wells· Cost Total MillionOF Dryer Total Total Total Total BTUH6SCFM OF

GPM 10'6"l 11 ' l 12' LGPM Total

$ x 106 $ x 106 $/hour x 10 $

200 428 14 14 12 5564 5 5 629.6 2.46

290(1) 82.714 170 329 18 16 14 13 4277 4 3.25 4 552.4 255.5 2.16

140 267 22 22 20 3471 3 3 475.3 1.86

200 394 10 10 8 5516 5 5 648.3 2.56

270(2) 83.828·· 170 303 12 12 10 14 4242 4 3.5 4 571.1 253.5 2.25

140 246 14 14 12 3444 3 3 494.0 1.95

, 200 360 8 8 6 5760 5 5 685.8 2.59

250(3) 85;135 170 277 8 8 8 16 4432 4 4 4 608.5 264.8 2.30

140 225 10 10 10 3600 3 3 531.5 2.01

(1) 4.2 units to replace one existing dryer.(2) 4.56 units to replace one existing dryer.(3) 5.11 units to replace one existing dryer.(4) Based on $250,000 each including coil.

(5) Based on $1.000,000 each.(6) Includes: Cost of dryers &wells @21.6% AFC &

pumping cost @3t/KWH - (no operation, pump orpipe transport costs) 4 months (2880 hoursJ/yroperation.

-Ilo,....N

Table 4-9

HOLLY/BRAWLEY CASCADED GEOTHERMAL SYSTEM

300°F BRINE

COSTS -HEAT USED

$ x 103CASCADE BTU's x 10"SEQUENCE $WELL*

EAOI TOTAL WELLS BOILER DRYER OPER'G* ft'NT* OPER TOTAL* PER MILLIONBTU's

Boiler - 5-1/2 Mos 2.774 0 7.738.979 5,000 386.4 5,622 49.9 2,783 3.10

Beet Dr,y - 4 Mos 6.205 235 112.44

Boiler - 5-1/2 Mos 2.774 0 7.73

Beet Dry - 4 Mos 6.205 18.286 5,000 386.4 5,622 587.83112.44 72.9 3,158. 1.73

Alfalfa Dry - 6 Moc 9.308

*Operatin9 and Maintenance costs are yearly, as is the total. WelT, Boiler and Dryer costs are totalcapital (installed). Yearly cost was calculated at 21.6% AFC.

Based on four boilers (192,000 x 1.2/4) @$5],600 each.

-I!Io,-(AI

Table 4-10

HOLLY/BRAWLEY CASCADED GEOTHERMAL SYSTEM

350°F BRINE

COSTS -HEAT USED

$ x 103CASCADE BTU's x 10"SEQUENCE $WELL*

EACH TOTAl WELLS BOILER DRYER OPER'G* MNT* OPER TOTAL* PER MILLIONBTU'S

Boiler - 5-1/2 Mas 2.774 0 2.728.911 3,000 135.8 4,567.81 29.5 1,978. 2.22

Beet Dry - 4 Mas 6.137 191.04 91.36 01

Boiler - 5-1/2 Mas 2.774 0 2.72

Beet Dry - 4 Mas 6.137 18.117 3,000 135.8 4,567.81 477.61 91.36 53.64 2,288. 1.27

Alfalfa - 6 Mas7~

9.206

*Operatin9 and Maintenance cos·ts are yearly, as is the total. Well, Boiler and Dryer costs are totalcapital (installed). Yearly cost was calculated at 21.6% AFC.

beet campaign for other drying such as alfalfa. If these dryers can bekept 1n use for 10 months out of the year, the cost per million BTU'sdrops cost effectively to $1.73 for. 300°F brine and $1.27 for 350°F brine.This last mode is identified as the optimum approach for the use of geo­thermal energy in sugar refining.

4.4.4 Transmission Pipeline Costs

Transmission pipeline costs per mi 1e of buried insulated pipelineare summarized for each Brawley retrofit concept using 300°F and 350°Fbrines in Tables 4-11 and 4-12 respectively.

4.4.5 Holly/Brawley Retrofit Cost Summary

The costs of Brawley factory retrofit applications using 300°F and350°F geothermal brines, from wells located adjacent to the plannedMcCullogh wells, are summarized 1n Table Table 4-13.

4-14

l

Table 4-11

HOLLY/BRAWLEY GEOTHERMAL ENERGY SUPPLY COSTS

300°F BRINE

Item

I

No. : No. ,FlowWells j Dryers; GPM

HeatBTU's

Time! I Pipe & I: Pipe Pumping PlJq)s* Total

Mos. Hrs.· In. $ $ . $1 Mile Pipe$/BTU x 106

1. Stearn 5 i 5875I

2.774 x 1011 5-1/2 3960 \ 14I

99.870 893.400 310.12580.000

1.12

.,.,­c.n

2. Drying

3. Cascade

4. CascadeAlfalfa

3

5

5

13 ! 3471;,

16 !158753312

I

16 5875! 3312

I

112.774 x 10116.205 x 108.979 x 1011

112.774 x 101115.513 x 1018.287 x 1011

4 2880! 12II

5-1/2 3960 i 144 2880

5-1/2 3960 1410 7200 .4-1/2 3240!

jI

42.912 813.120 233.66670.000

99.870 893.400 310.12580.000

99.870 893.400 356.19046.065 80.000

145.935

0.38

0.35

0.20

*Total Capital x 21.6% =AFC + Pumping =Total

AI-0\

Table 4-12

HOLLY/BRAWLEY GEOTHERMAL ENERGY SUPPLY COSTS

350°F BRINE

Time Pipe & 1 Mile PipeNo. No. Flow Heat Pipe Pumping PUl!IPs'* TotalItem Wells Dryers GPM BTU's Mos. Hrs. In. $ $ $ $/BTU x 106

1. Steam 2 2243 2.744 x 1011 5-1/2 3960 12 38,129 813,120 228,883 0.8370,000

2. Drying 2 13 2171 6.14 x 1011 4 2880 12 26,840 813,120 217,594 0.3670,000

3. Cascade 3 13 3139 11 5-1/2 3960 12 14,553 813,120 248,220 0.282.774 x 10113471 6.137 x 10 4 2880 42,912 70,000

8.911 x 1011 57,465

4. Cascade 3 13 3139 11 5-1/2 3960 12 107,280 813,120 298,034 0.172.774 x 1011Alfalfa 3471 15.343 x 10 10 7200 70,000

18.117 x lOll 4-1/2 3240

'*Total Capital x 21.6% • AFC+ Pumping • Total

lTable 4-13

HOLLY/BRAWLEY RETROFIT SUMMARY

CAPITAL, OPERATING AND MAINTENANCE COSTS

Cost $/Mi11ion BTU's*

2-1/2 Mile Transnrlssion

M1Der Mumer .In-Situ Pipe Piping Totalof Wells of·Dryers Wells Size Cost Cost

300°F Brine

Sugar Refining (5-1/2 Monthst

• Make-Up Steam 5 4.40 14" 2.80. 7.20I- Pulp Drying 3 13 3.06 12" 0.95 4.01.....Cascade Boiler to Dryer 5 16 3.10 14" 0.88 3.98

seasonal

Cascade Sugar (5-1/2 months) 1 5 16 1.73 14" 0.50 2.23Alfalfa Drying (4-1/2 months-) f350°F Brine

Sugar Refiri1ng 15-1/2 Months>'

Make-Up Steam 2 1.76 12" 2.08 3.84Pulp Drying 2 13 2.69 12" 0.90 3.59Cascade Boiler to Dr,yer 3 13 2.22 12" 0.70 2.92

seasonal

Cascade Sugar (5-1/2 months) 3 13 1.27 12" 0.43 1.70Alfalfa·Drying (4-1/2 months)

•1977 costs, including amortized capital and operating and maintenance costs of wells, equipment andpipel1nes. .,

4.0 REFERENCES

4-1 Study of the Geothermal Reservoir Underlying the East Mesa Area,Imperial Valley, California, TRW Systems and Energy for U.S. Bureauof Reclamation, December 1976, Report No. 28859-6001-RU-00.

4-2 Planning and Design of Additional East Mesa Geothermal Test FacilitiesjPhase 1B), TRW Systems and Energy for ERDA, October 1976, ReportNo. 28653-6002-RU-00.

4-3 Experimental Geothermal Research Facilities Study (Phase 0), TRWSystems and Energy for ERDA, December 1974, Report No. 26405-600l-RU-OO.

4-4 Milora, S. and Tester, J., Geothermal Energy as a Source of ElectricPower, 1976, the MIT Press.

4-5 Bloomster, C. and Knutsen, C., the Economics of Geothermal ElectricityGeneration from Hydrothermal Resources, 1976, Battelle Pacific NorthwestLaboratory Report BNNL-1989.

4-6 Utilization of U.S. Geothermal Resources, TRW Systems and Energy forElectric Power Research Institute, December 1976, Technical PlanningStudy 76-638.

4-18

u

5.0 THE SUGAR PROCESSING MARKET

5.1 Market History

From 1934 to 1974. sugar prices were held stable as a result of a legis­lated Sugar Act. Since 1974. when the Act officially expired. prices haveno longer been regulated and stable. but have been fixed by supply and demand.

To compound this price stabilization problem. world forecasts shows thatthis will be the third year in a row with sugar production higher than consumption.Currently. the U.S. grows approximately 65 percent of our sugar requirement. Mostother sugar producing nations have protective programs. which benefit both theproducer and the consumer. Any excess sugar that is produced enters theworld market.

Several other factors will have an effect on the current sugar market.First. corn sweeteners share of the market has increased faster than theoverall market growth. Second. a survey conducted by the U.S. Departmentof Agriculture on January 1.1977 shows that beet producers anticipate a7 percent decrease in planting intentions. Last. the new association directoryshows a reduction of at least 3 beet processing plants for 1977 operations.The instaoi1ity of prices reflected in the current market. coupled withthe worldwide overproduction-of sugar. has r~su1ted in a grim outlook forthe sugar' industry.

5.2 Potential Market Improvements

In January. 1977. TenoRonca1io (Democrat-Wyoming) introduced a newSugar Act to Congress • The Act is similar to OlJe introduced in September.197u in the House of Representatives(HR 15485)~:~ In addition to the promul­gation of new legislation. it is possible thatgtf1:~ President could imposean import quota on sugar to raise and stabili~~f~j1:s price.

'. ·-,·r~-~~·,~j}-·

The United States International Trad~~e6.romission is currently conducting, ,.~_, ".-';0'

hearings to ascertain the effect of quantiti:eS,of foreign imported sugar~ - ~ -"', :"': ':~,_.;~

'at low prices on the domestic industry. F1ncU:ngs"are to be reported to'. '.'. - -,

the President. ',,'",i{ j.'f~

, ' I {,}' ;

5-1

uU.S. representatives have complained to the Commission that refined

sugar is being sold at prices under the cost of growing and processing thebeets. To make a living, they feel that sugar prices will have to improve.Without relief, farmers may be forced to switch from beets or cane to othercrops that sell at more stable prices. However, factory owners do not havethe option to convert their processing plants to some other process. Theyfeel that some type of relief and protection is necessary for both theconsumer and the producer during shortages and surpluses. U.S. representativeshave stated that a sugar import quota would ease this problem by allowinghigher prices for domestic sugar. Generally, the industry feels that importsare the cause of the problem and that only an import quota will improve sugarprices.

Foreign representatives stated to the Conmiss1on that it is not theworldwide overproduction of sugar that is hurting the market. They feelthat the lower market is due to a decrease in consumption and the influx ofhigh fructose corn syrup, and that this has hurt the industry worldwide.They would approve of U.S. legislation which would establish quotas andwhich would guarantee fair prices across the board. Perhaps an InternationalSugar Agreement would be effective in solving this problem.

Based on tests conducted by the Canadian government over the past threeyears on laboratory rats, saccharine was found to cause malignant bladdertumors in t~ese test animals; therefore, unsafe for human consumption. Asa result, the U.S. immediately announced that it would ban saccharine dueto the provisions of the Delaney Clause of the Federal Food Drug andCosmetic Act. Both the U.S. and Canada are planning to phase saccharineout gradually. Immediately after the ban was announced, the sugar marketfluctuated mildly; however, this effect did not last very long.

Basically, there are two groups of people who use saccharine. First,is the group of people who medically are unable to ingest sugar or evenhigh fructose corn syrup. Second, is the group of people who use saccharineto stay thin by eating low carbohYd~ate or sugar free foods.

In the U.S., per capita consumption of saccharine is about 8 pounds or ~

about 5 million tons for the ~ntire U.S. With the saccharine ban, it is possible

5-2

that at most an additional 2-3 pounds of sugar might be consumed per capitain the U.S. The impact to the sugar industry is expected to be minimal, ifany. Certainly. the ban would not result in enough economic motivation tocause the sugar industry to construct a new geothermally-fired sugar processingplant.

To stabilize sugar prices. President Carter recently approved sugarsubsidies of up to 2 cents per pound. The subsidy is to be given to sugarbeet and cane growers whenever the market price of sugar falls below 13.5 centsper pound. Since the money is to be paid by the U.S. Treasury Department. itshould have no effect on the price paid by consumers. In turn. it is alsonot enough of an incentive to justify large capital expenditures on the partof the sugar industry at this time.

5.3 Geothermal Application Potential

Under existing conditions as described above and as iterated by each of theindustry representatives contacted (Reference Section 10), there is little likeli­hood of any new beet sugar facilities being builtin the geothermal potentialareas of the western United States. Costs are high, and without sugar legislationthe sugar price is not stable enough to project return on investment. However,there would be retrofit potential in areas where factories now exist and geothermalenergy is readily available.

5-3

6. ECONOMIC EVALUATIONS

In Section 4, several economic bases were established. This sectionutilizes this data in cost comparisons and economic evaluations.

6.1 Fossil Fuel Costs

Currently, various types of energy sources are utilized by the sugarindustry to supply energy for the refining process and the generation ofelectricity. These fuel sources include natural gas, residual fuel oiland coal. Figure 6-1 illustrates an estimate of the cost of these fuelsas well as liquefied natural gas (LNG). These fuel costs have been pro­jected to the year 1995 and are based on a combination of price increasesdue to general inflation and demand/supply influences. To account forgeneral inflation, fuel costs have been escalated at the rate of six per-cent per year according to the Office of Management and Budget inflationestimates. Influences on fuel prices due to demand/supply have been accountedfor by various estimates. In order to make direct comparisons of the differ­ent types of fuels, costs have been converted to dollars per million Btu's.

Coal is currently utilized to supply the process and electrical energyneeds for the sugar industry in western states other than California. Airpollution regulations prohibit the burning of coal in California. The fuelcost shown in Figure 6-1 is based on the price paid for coal by U&I in1976, escalated at 6 percent per year. Since coal reserves are consideredplentiful and the demand Jairly stable, the future price of coal is not ex­pected to be influenced by demand/supply, but only by general inflation.However, it should be noted that the demand for coal may rise as a result ofincreased coal burning and gasification and liquefaction programs, dependingon the energy policies of the present administration.

In California, since it is prohibited to burn coal and the supply ofnatura1 gas· is dwi ndli ng" res idua1 fuel oil (RFO) is the energy source cur­rently being utilized in the sugar industry. Natural gas has been severelycurtailed to industrial users in the past two years and trends indicatethat the curtailment will continue to increase as supplies of natural gas

~ diminish. Thus, industrial users, who no longer see natural gas as a re11-

6-1

0\I

N

a.oo

7.00

6.00

5.00

3.00

2.00

1.00

1975 1980 1985YEAR

FUEL PRICE PROJECTIONS

1990 1995

NATURAL GAS - CONSII£R (INDUSTRIAL) PRICESFOR GAS IN CALIFORNIA ­ECONOf!ICS Of OIL AND GAS FORUSE IN CALIFORNIA. S.H. CLARK

LNG - smtIETlC EUW CDlfRCIALI-lAlImlPROGRNI. VOL. III.AND S.H. CLARK

RESIDUAL FUELOIL (RFO) - LON SUlfUR AIEL Ol~

ELECTRIC UTILITIES STUDY.TRW SYSTEJIlS AND· ENERGY•

COAL - 1976 U&l I.:OSTS ESCALATEDa 6VYEAR

cFigure 6-l-Fossil Fuel Price Projections

u

able energy source, are being forced into switching to RFO to meet energyneeds. This switching trend to RFO will probably continue until 1984. In1985, as shown in Figure 6-1, RFO and LNG are expected to become economi­cally competitive with each other.

The natural gas curve shown in Figure 6-1 is based on prices man­dated by the Federal Power Commission (FPC). As of January 1, 1977, theFPC set the price of new gas - gas supplies discovered, committed or putinto production to interstate markets after January 1, 1975 - at $1.42 perthousand cubic foot (MCF). In addition, the FPC mandate allows producersto raise the price of new gas by another 4 cents per MCF per year. Itshould be noted that $l.OO/MCF·1s roughly equivalent to $l.OO/MMBtu. Sincethe supply of natural gas is decreasing, prices will increase due to bothgeneral inflation and demand and supply influences. It seems likely thatprices will increase faster than the 4 cents per year1ncrease allowed bythe FPC. Gas prices may possibly be deregulated by the FPC and thus besubject to market pressures. If so, gas prices would be determined bysupply and demand. Because of these factors, for 1977, the $1.42 priceset by the FPC has been included on Figure 6-1. ~For subsequent years,S. H.Clark's (ref 6-1) estimate of gas prices to industrial users hasbeen included. Clark's estimate is based onthe.price of natural gasdetermined by general inflation as well as by supply and demand. It shouldbe noted that the $1.42 price for new gas has been used since "old" gas hasnot been available to industrial users.

The RFO curve shown in Figure 6-1 is derived from ,a previous TRW studyperfo~ed for ERDA (ref 6-2). In this study, price projections were basedon the Gulf Stanford Research Institute and the FEA-PIES models. Price pro­jections are for low sulfur residual fuel oil delivered to California users.The price of foreign crude oil is dete~.ined by the Organization of PetroleumExporting Countries (OPEC). Estimates of future crude oilprfces are difficultto ascertain since prices are often'determined by political decisions. Thedemand for crude oil is growing and it is not expected that OPEC will increaseproduction at the pace necessary to meet the projected demand. The TRW studyhas estimated that world-wide RFO prices will rise at 'a rate of 2 percent peryear in real te~s (supply/demand) more than the general worldwide rate ofinflation, which has been included in the RFO curve.

6-3

6.2 Geothermal and Fossil Fuel Cost Comparisons

In Section 4, it was determined that providing 300°F geothermal heat toeither the boiler or the beet pulp dryer only, without cascading, was noteconomical. Further, it was established that the most attractive adaptationof geothermal energy to the sugar refining process is a system in which heatis cascaded from the boiler to the beet pulp dryer.

Therefore, this section utilizes the economic data developed in Section 4for various combinations of sugar refining systems and geothermal fluidtemperatures to determine which system appears to be the most economical. Inaddition, each system is compared to the fossil fuel price projections devel­oped in Section 6.1 to determine when geothermal energy will be competitivewith fossil fuels. Systems to be analyzed and compared include:

1) Cascade - 300°F Geothermal Fluid

2) Cascade/Off-Season Use - 300°F Geothermal Fluid

3) Cascade - 350°F Geothermal Fluid

4) Cascade/Off-Season Use - 350°F Geothermal Fluid

Figures 6-2 through 6-4 show price projections of each of the four alter­native geothermal systems in comparison to fossil fuel price projections.Costs have been projected to the year 1995 in order to show when geothermal energywill become economically competitive with any fossil fuels (coal, naturalgas, oil or LNG).

All geothermal curves have been derived by first estimating the 1976 costof proViding geothermal energy to the refining process for each of the foursystems. Second, the derived geothermal costs were escalated from 1976 to1980 at the 6 percent inflation rate set forth by the Office of Managementand BUdget. 1980 is the earliest possible point in time for initial operationas determined in Section 11. Until operation begins in 1980, all associatedcosts will be subject to inflation; however, after 1980, only overhead andmaintenance costs will be influenced by inflation. The rationale for thiswas developed in Section 4 and data is incorporated in Figures 6-2 through 6-4.

'l

8.00

7.00

6.00

5.00

3.00

2.00

1.00

1975

INITIAL OPERATION

1980 1985YEAR

F\IEl PRICE PROJECTIONS

1990

/,

1995

LEGEND

NATURAL GAS - COftSUI'ER (INDUSTRIAL>' PRICESFOR GAS IN CAliFORNIA ­ECOffOJIIICS OF OIL AM &AS fORUSE IN CALIfORNIA. S.H. ClARK

lllG - Sl'I(1lIETIC alas f1J1IQCIAU-ZAIIaN PROGlWI. VOL. IU.NID S.H. CLARK

6EOTHERMAl - CASCADED fRalI BOILfR TODRYER 6£OllIERMlSll6AR REfUtiNG ONtY (5-112 PI>S.>

figure 6-2 - Fuel Price Projection Comparisons of Cascaded 300°F and350°F Geothermal Systems to Fossil Fuels

8.00

1.00

6.00

5.00

3.00

2.00

1.00

1975

INITIAL OPERATION

19841 1985YEAR

AIEL PRICE PROJECTIONS

1990

/,

1995

NATURAL GAS - CONstftR (INDUSTRIAL> PRICESFOR GAS IN CALIFORNIA ­ECONOf!JCS OF OU AND GAS FORUSE IN CALIFORNIA. S.H. CLARK

UfG - smt/ETIC RIELS ClJI£RCIAU-ZAIIJlfl. E'.ROGRAPI. VOL. III.AND S.H. CLARK

RESIDUAL FUELall (RFO) - LOW SUlFUR AIEL Ol~

ELECIB.IC UTILITIES snmy.TRW SYSTEPIS AND ENERGY.

COAL - 1976 U&I COSTS ESCALA1£Da 6%/YEAR

GEOTHERML - CASCADED FROft BOIlER TODRYER GE01llElWlSUGAR REFINING (5-112 PIlS.>

GEOTHERPoAL - CASCADE SUGAR REFINING(5-11~ PIlS.)OfF-SEASON AlFALFADRYING (q-lIL lIDS.)

r

Figure 6-3 - Fuel Price Projection Comparisons of 300°F Cascaded andCascaded/Off - Season Systems to Fossil Fuels

c

6EOTHERPIAL -CASCADE SUGARREfINING (5-11; fIlS.)OFF-SEAson ALFALFADRYING (4-112 fIlS.)

RESIDUAL FUELOIL (RFO) - llnf SUlFUR AIEl OIL,

ELECI8.I.C....UIJLIIIES snmy.TRW. SYSWtS AND ENERGY.

COAL - 1976 USI COSTS ESCALATEDa 6VvEAR.

- CONSlI£R (INDUSTRIAL> PRICESFOR &AS .IN CALIFORNIA ­ECONOPIICS OF OIL AND GAS FORUSUILfAUf.DmtJA. S. H. CLARK

-~ZAJJJlfl PROGRAM. VOl.. 11(.

AND S.H. CLARK

NATURAL GAS

,/lftG

6EO~l - 3SOOf

INITIAL OPERATION

1.00

7.00

2.00

8.00

5.00

5.00

3.00

0\I.....

1975 1980 1985YEAR

RJEL PRICE PROJECTIONS

1990 1995

Figure 6-4 - Fuel Price Projection Comparisons of 300°F and 350°F Cascaded/Off­Season Systems to Fossil Fuels

•

Projected cost data for the four geothermal systems and each of the fossilfuels are shown in five year increments in Table 6-1.

Figure 6-2 shows the differences in cost between a 300°F and a 350°Fgeothermal system, both of which incorporate cascading heat from the boilerto beet pulp dr,yer for 5-1/2 months, the length of the sugar campaign. Ascan be seen from this figure, a 300°F cascading system would not be economi­cally competitive with fossil fuels until after 1985, while a 350°F cascad­ing system would be competitive shortly after initial operation.

The difference in projected costs between a cascaded and a cascaded/off-season system for 300°F geothermal fluids is shC7tln in Figure 6-3. Acascaded/off-season system applies to a cascaded one that is used for sugarrefining for 5-1/2 months and for off-season use, such as alfalfa drying, for4-1/2 months. From this figure it can be seen that although a 300°F cascadedgeothermal system would not be economical until after 1985, a 300°F cascaded/off-season system would be economical from initial operation of the system.

Figure 6-4 compares the costs of the 300°F and 350°F cascaded/off-seasongeothermal systems to the costs of fossil fuels. As this figure indicates,the most economical combination of the geothermal alternatives is a 350°Fsystem that cascades heat from the boiler to the beet pulp dryer during the5-1/2 months of the sugar campaign and that is used for off-seasonal uses,such as onion or alfalfa drying for an additional 4-1/2 months. This type ofsystem not only appears to be the most economical geothermal system, but alsoappears to be more economical than any of the fossil fuels.

6-8

(

TABLE 6-1 - FOSSIL FUEL AND GEOTHERMAL PRICE PROJECTIONS($/MM8tu)

FUEL TYPE

(

LIQUEFIED GEOTHERMAL GEOlHERMAL GEOTHERJlAL GEOTH ERrt1ALNATURAL RESIDUAL NATURAL CASCADED - CASCADED- CASCADED/OFF CASCADED/OFF

YEAR GAS FUEL OIL COAL GAS 300°F 350°F SEASpN 300°F SEASON 350°F

1976 1.42 2.10 1.38 2.70 3. 10 2.22 1.73 1.27

1980 2.44 2.89 1.74 3.20 3.91 2.80 2.18 1.60

1985 4.25 4.21 2.33 4.00 4.32 3.09 2.41 1.77

1990 7.05 6.19 3. 12 5.25 4.77 3.42 2.66 1.95

1995 11.82 9.09 4.17 7.00 5.26 3.77 2.94 2.16

The LNG curve shown in Figure 6-1 has been derived from two sources.The 1976 point on the curve is based on a formula developed by StanfordResearch Institute for the Synthetic Fuels Commercialization Program(Reference 6-3). The latter part of the curve is based on price projec­tions for LNG estimated by S. H. Clark (ref 6-1).

\

6-10

6.0 REFERENCES

6-1 S. H. Clark, California Energy - The Economic Factors - Invited Paperson Cali forni a' s Future Energy Sources, "Economics of 011 and Gas forUse in California", 1976.

6-2 Electric Utilities Study, An Assessment of New Technologies from a 'Utility Viewpoint, TRW Systems and Energy, November, 1976.

6-3 Recommendations for a Synthetic Fuels Commercialization Program, bySynfuels Interagency Task Force to the President's Energy ResourcesCouncil, June, 1975.

6-11

7.0 ENVIRONMENTAL IMPACT ASSESSMENT

Application of geothermal heat to the sugar refining process will resultin environmental impacts. This section assesses the major potential impactsassociated with the design alternates for use in sugar refining processes atthe previously identified resource areas. Only m~jor impacts are discussedand include the following:

• subsidence.• seismicity• atmospheric impacts• hydrological impacts• noise• erosion and landslides• aes theti cs

Several design alternates were presented in Section 3. In addition,six geothermal resource areas have been identified for their potential appli­cation to the sugar refining process, as described in Section 2. Figure 7-1shows the geographical location of each of these areas have been identified as:

• Southern California: Salton Sea, Heber, Brawley and' East Mesa.• Northern California: Geysers, Calistoga, Wilbur Hot Springs and

Morgan Springs.• Southwest Idaho: Crane Creek, Weiser, Vale Hot Springs, Mountain

Home, Bruneau-Grandview.• Southeast Idaho: Raft River, Brigham City• Arizona: Chandler• Washington: Longmire Hot Springs,Sumit Creek.

Some detailed environmental assessments and studies have been performed on thespecified geographical areas. For the interest of the reader, several of thesestudies are cited in the beginning of the reference section, references 7-1through 7-11.

The final selection of a geothermal system will be influenced in partby the environmental impacts as well as by the technical and economic feasibilityassociated with each design alternate. This section evaluates the environmentalimpacts of the design alternates with respect to the resource areas in orderto facilitate the selection of the design alternate with the least potential

~ impact. In addition, this section also includes a brief comparison of theadvantages and disadvantages of a fossil fuel system versus a geothermalsystem.

7-1

u

l.

NORTH

DAKOTA

ItXAS

SOUTH

DAKOTA

..._... - .. - ...

!j_ .... _ .._ ..._--

HYC")MIltIU. 'YST(ttS c--..· !I!~ C1~~..A' 7H

It'(X/CO

",'.LEGEND

~. SUC~ca£AC£

.""<T<_

• ... < T <_... < T<_

t>-<TO .VlJlALOEI'

WlLLI"PLOWTUTlD

A I4WELLI~ 'Ll*UfOCUT_

Cll LOW

• It.. LM'JI SYSTlMS

• 1YM.IlATlD S'STIJI$• "'..E'Al.U'![D SYSTDS

.I

'. ........ _'\...... I •

"'...J'-' "\,,\

uFigure 7-1 Geothermal Resource Areas and Sugar Beet Producing Areas.

7-2

7.1 Subsidence

Withdrawal of large volumes of geothermal fluids over long periods oftime can result in subsidence of the ground surface. When fluids are removedfrom a groundwater aquifer, in which withdrawals exceed recharge, the pressureof the reservoir decreases, which can cause land subsidence.

In general, subsidence results from the combination of (1) the compressi­bility of the reservoir, (2) the reduction of pressure in the reservoir,and (3) the thickness of the producing formation. As the fluid pressuredecreases, stresses are increased followed by compaction of the compressiblebeds of the aquifer. The magnitude of the subsidence also depends on thetime the increased pressure has been applied and the past history of stress.Generally, subsidence is irreversible.

In a dry-steam field, like The Geysers, subsidence is not likely tooccur since the reservoir rocks and not the steam, bear the overburden weight.However, in a hot water field like the Imperial Valley, the water providessupport for the overburden. In such areas, reducing aquifer pressures couldcause subsidence.

Subsidence has· previously been associated with the pumping of freshgroundwater, the exploitation of oil and gas reservoirs and the withdrawalof geothermal fluids from Wairakei, New Zealand and Cerro Prieto, Mexico.At cerro Prieto, subsidence of up to 7 inches has been measured 7 milesoutside of the well (ref. 7-1). Subsidence can be prevented or minimizedby maintaining fluid levels with reinjection.

In the application of geothermal resources to the processing of sugarbeets, there are four wellflow/effluent handling alternatives which mayinfluence subsidence. These four alternatives are shown in Figure 7-2.In Alternate HE-1A (With Reinjection), the geothermal fluid is passed througha heat exchanger and returned to the ground via a reinjection well. Sincethe cycle is closed and the fluid is not diminished, no subsidence is expectedto occur. However, if the fluid was injected into a porous aquifer or onethat is faulted, the fluid could move into nearby z~nes, thereby decreasingreservoir pressure and causing some subsidence. In Alternates HE-18 (Without

7-3

NON-CONDENSIBLE GASES

• SUBSIDENCE• DEPLETION OF RESOURCE• SEISMICITY

OR IOIGATIc.I

• SALINITYTEMPERATURE

o TOXI C CHEMI CAL:• EROSIONltII OFF

llOlI-coNOEJfSllIL£EDtJCTOR (TYP) [ "zS 11l£A11IEIIT (TYP,...) ---.

!'.:'?t SUGAR_-1A..~,/~ REFlIIIII&

I--__....J ... e N ISI;,......----'• N -CONDENSIBLE• A THETICS

~STEAM SEPARATOR(TYP)

RIIIl OfF

" OR IRRIGATION• SALINITY

--r.L.r-~~_-.., •..--T,EMPERAT..;;.UR;.;.;;E:..,..I-,- ~_OXIC

CHEMICALS• EROSION

• SUBSIDENCE• DEPLETION OF RESOURCE• SEISMICITY

I I~I\.JI~ J ~

I I

IJI\...

I

.....I~

----=::!.-_-------ALTEIlMTE /lE-1A

(lI1TH REIIIoJECTION)NoTEIlMTE 1IE-18

(lI1T1lllU1' REIIIoJECTIc.I)ALTERIIATE /lE-lA

(lI1TH RElI1oJECTIc.I)SIL£l!CEI 8,TEIIlATE HE-n

(ltITIlOlIT REIIIoJECTIc.I)

SELF FLlllIJlI& IlEUS

6EOTllERIIAL RESOIJRCE UTILllATIc.IlIElL FLOII/EFFLUENT IWlIIlIII& ALTEIlMTlYES

Figure 7-2 Geothermal Well Flow/Effluent Alternatives

c

Reinjection) and HE-2B (Without Reinjection), no reinjection is planned andall fluid is to be used for surface purposes (surface purposes include irri­gation, runoff, space heating, desalinization, etc., and are discussed underHydrological Impacts, Section 7.4). Both Alternates HE-1B and HE-2B mayresult in substantial subsidence, as well as depletion of the resource.Although Alternate HE-2A (With Reinjection) is designed for reinjection,subsidence still may occur, since some of the fluid is lost in the sugarrefining process. Therefore, to maintain reservoir pressure and minimizesubsidence, make up or additional water must be reinjected into the reservoiralong with the unconsumed geothermal fluid. Because of the nature of thesugar refining process, this make up water can be supplied from the processwaste water. Reinjection can maintain reservoir pressure and maximize reservoirlife.

Of the six geographical areas studied for potential application of geo­thermal resources to the sugar refining process, two areas, the ImperialValley and central Washington, pose special problems with respect to subsidence.Land use in the Imperial Valley is primarily agricultural. Due to the aridclimate, an extensive irrigation system has been designed and constructed,so that tile canals and drains slope approximately 5 feet/mile {ref• 7-12).In addition, the deltaic sediments of the Imperial Valley are relatively un­consolidated and imcompetent, and are dependent upon the pore pressure of thewater for support. It has been estimated that the Imperial Valley alreadysubsides naturally at a rate of 1 foot per century, which is probably due to.its naturally occurring tectonic activity. Therefore, subsidence could seriouslyaffect the ability of the irrigation .systemto functi()n.

In central Washington. subsidence may result from the development of geo­thermal resources. State law prohibits· the injection of liquid wastes. exceptunder extenuating circumstances. Generally. liquid ,wastes are treated aspoint sources subject to the National Pollutant Discharge Elimination System(NPDES) stipulated by federal requlations. To date. there have been notest cases pertaining to injection of geothermal fluids. State officialsfeel that it is possible that this type of injection might be interpretedas an extenuating circumstance. however, regulations will have to be promul­gated which apply specifically to geothermal resources (ref. 7-13).

7-5

7.2 Seismicity

Changes in reservoir pressure ma.{ result in instabilities that increaseseismic activity. Such instabilities, caused by pressure reduction fromthe production of fluids or pressure increases due to injection, have occurredin the Wilmington Oil Field, California, the Baldwin Hills Oil Field, californiaand RangelY Oil Field, Colorado. Also, se,ismic activity has been associatedwith wastewater injection at the Rocky Mountain Arsenal in Colorado. Theseearthquakes have not been damaging. Mognitudes have generally been be~ow

4.5 on the Richter Scale, which is considered minor.

It has been stated that seismic triggering is associated with an increasein fluid pore pressure in rocks. In dry-steam fields, earthquakes shouldnot be triggered since withdrawal of the geothermal steam reduces pore pressure.In a hot-water field, water removal has the same effect; however, seismicitymay be increased by the redistribution of fluid pressure. Since geothermalareas are linked to areas of seismic activity, it is possible that the assoc­iated faulting system may be a route for the fluids to redistribute andrecirculate within the aquifer. Thus, to minimize subsidence and seismicactivity, geothermal brines should be reinjected at pressures lower thanthose known to trigger earthquakes. Reinjection at lower pressures shouldhelp relieve stresses gradually (ref. 7-14).

Figure 7-3 shows the tectonic features of the Western United Statesin relation to those areas of sugar beet production and geothermal resources.As can be seen, the Imperial Valley is an area that is seismically active.The Valley is traversed by several mador faults and has experienced manyearthquakes. In 1975 and 1976, the Brawley area experienced a swarm of minorearthquakes, sometimes as many as 1 or 2 per hour, and it should be recognizedthat geothermal activities could increase this natural process.

7-6

KANSAS

.l.

SClUlH

NEBRASKA

,..... lID

KILl'" ..US

..,

M[XICO

ICIITUS

...CMlI(,lnms• • ,•

@ @ <

• • • •.,.,Jl:l All. or 1lioOt...,VfW.'.W IOCd

uFigure 7-3 Tectonic Features of the West~rn United States.

Smith &Shaw, Coffman &Hake][Sources: King,

7-7

7.3 Atmospheric Impacts

Air pollution will increase as a result of geothermal development.Emissions produced during the exploration, testing and construction phasesare different from those produced during the operation phase.

Atmospheric impacts associated with field development result fromconstruction of roads, clearing the site, movement of heavy equipment ontothe site, operation of gasoline and/or diesel-powered vehicles and equip­ment, and construction of facilities and pipelines, etc. In general,emissions produced by field development will primarily be particulatematter, contributed to the atmosphere by wind erosion following removalof the area's vegetative cover. The amount of pollutants emitted frominternal combustion engines is expected to be minimal in comparison topollution currently emitted in most of the six areas. Local degradationof air quality may occur during field development; however, the overalleffect is expected to be small.

Development and operation of the well itself also results in atmosphericimpacts. Geothermal liquids and steam usually contain substantial amountsof non-condensible gases and vapors, which are released when there is a lossof fluid pressure or condensation of steam. These gases and vapors usuallyamount to less than 3 percent of the total steam fraction, although theamount can vary. It has ueun estimated that the steam at the world's fivelargEst geothermal power plants contains from 0.15 to 30% non-condensi~le

gases (ref. 7-15).

Non-condensible gases include carbon dioxide, (C02), hydrogen sulfide(H2S) , methane (CH4),ammonia (NH3) hydrogen (H2) and nitrogen (N2). Vaporsconsist of boric acid (H3B03) and mercury (Hg). Table 7-1 shows the fractionof the total gas content of typical geothermal steam.

For example, at the Geysers non-condensible gases form about 1 percentof the total steam fraction. Of this, about 80 percent is CO2 and 4.5percent 1s H2S. Table 7-2 shows the content of various gases associatedwith geothermal steam production at The Geysers. Emissions at The Geysers

7-8

TABLE 7-1 FRACTIONS OF TOTAL GAS CONTENT(ref.7-15)

CONSTITUENT PERCENT

CO2 78.0 - 95.0

H2S 1.0 - 17.0

H2 1.0 - 13.0

CH4 0.0 - 12.0

N2 0.2 - 9.0

NH3 0.0 - 1.7

ARGON. ETHANE{TRACE AMOUNTSH3B03• HC1.

HF. S02

TABLE 7-2 GASES ASSOCIATED WITH GEOTHERMAL STEAMAT THE GEYSERS IN VOLUME PERCENT1ref. 7-1)

CONSTITUENT VOLUME PERCENTH2O 98.045

CO2 1.242

H2 0.287

CH4 0.299

N2 0.069

H2S 0.033

NH3 0.025

P3P04 0.018

7-9

result from the well during bleeding and venting, from gas ejector vents onthe condensers, and from the cooling towers. About 20-30 percent of thenon-condensibles is reinjected with the condensate and the remainder isreleased to the atmosphere.

The primary gaseous emission problem at The Geysers and at othergeothermal developments has been H2S. The human level of toxicity forH2S is 20 ppm, which has been exceeded at geothermal fields. In addition,the odor of H2S,which is that of rotten eggs, 1s detectable at .025 ppm.

H2S abatement systems include sulfur recovery systems such as a ClausPlant or Stretford unit. Abenefit of util izing a sulfur recovery systemis that the recovered elemental sulfur can be sold, which helps to offsetthe expenditures of installing the abatement system. Pacific Gas and Electric(PG&E), who operates the power plants at the Geysers, plans to install theStretford Unit on all future plants to reduce "2S emissions. PG&E expects"2S emissions to oe reduced by 90% with this abatement system and to meetCalifornia air quality standards.

Application of geothermal heat to the sugar refining process willresult in increased atmospheric impacts during the field development phase,as well as the operational phase, although most of these impacts are expectedto be minor. DUring the field development phase, there are several possiblealternatives which could be implemented. These alternatives, shown inFigure 7-4 and 7-5, include directional drilling, vertical drilling, adjacentwellheads and remote wellheads. As shown in Figure 7-4, a well that isdirectionally drilled will result in fewer surface impacts since the productionand injection wellheads can be placed close enough to the process fluidheat exchanger so that no pipeline is needed to uring the fluid to theexchanger. Vertically drilled wells will require a pipline system to trans­port the geothermal fluid to and from the heat exchanger and to the injectionwellhead. A system that uses pipelines to transport geothermal fluids willincrease particulate (dust) emissions and pollutants emitted from internalcombustion engines as a direct result of surface erosion and increasedvehicle usage; however, effects should be localized and temporary.

7-10

c (UNDERGROUND PIPELINE FOR TRANSPORTATION OF FLUIDS

• AESTHETICS• HABITAT DESTRUCTION - REMOVAL OF VEGETATION• INCREASEDNOISE 1

• INCREASED PARTICULATES• INCREASED EROSION

1I

.../1"...

INJECTION .WELL (TYP)-~

-

Io4--PRODUCING WELL (TYP)

PROCESSFLUIDHEAT EXCHANGER(TYP)

....,I--

ALTERNATE A ALTERNATE B

DIRECTIONAL DRILLED VERTICAL DRILLED

Figure 7...4 Well Configuration Alternatives

. ------

UNDERGROuND PIPELINE'- ..... FOR TRANSPORTATION

OF FLUID~ • AESTItETICS

• HABITAT DESTRUCTION-REMOVAL OF VEGETATION

• INCREASED NOISE• INCREASED PARTICULATES• INCREASED EROSION

PULP DRYERCOIL (TYP)

INJECTIONJPUMP (TYP)- -

..... PRODUCINGI.... WELL (TYP)N

-

~-

INJECTION-~WELL (TYP)------------

-

-I I

"J:'- ../1,,-- - ----~, I __-_ALTERNATE HE-1A-2A

(ADJACENT WELL HEADS)ALTERNATE HE-1A-1A(REMOTE WELLHEADS)

c Figure 7-5 Pulp Dryer Ut11ization Altematives

c

It has been established in recent TRW studies, for ERDA and the Bureauof Reclamation, that directionally drilled wells, with horizontal throwsup to one mile, are economically competitive with vertical wells and buriedinsultated overland piping.

Placement of the wellhead may also result in similar atmosphericimpacts. Figure 7-5 shows two alternatives, adjacent wellheads and remotewellheads, that can be applied to the refining process. An undergroundpipeline will probably have to be constructed for systems where the well­head is located remotely to the process for aesthetic reasons; Thus, impactswill be greater for the remote wellhead system than for the adjacent wellheadsystem since more surface area will be disturbed.

Atmospheric impacts from the operational phase will primarily be anincrease in the emissions of non-condensible gases in connection with therefining process itself. Figure 7-2 shows four alternatives for well flow/effluent handling. Because the geothermal fluid is fully contained in aclosed system, no emissions are expected. In a flashed system with rein­jection, Alternate HE-2A, non-condensible gases are emitted during theprocess, which can be treated in an abatement system. If the geothermalfluid is not reinjected, as in Alternate HE-2B, non-condensible gases areemitted during condensation of the geothermal fluid and from the silencerwhen the fluid is brought to atmospheric pressure. In the first instance,the gases can be treated similarly to the previously discussed alternate(Alternate HE-2A). Gases from thesl1encer will also probably be treated.

7-13

7.4 Hydrological Impacts

In this section, the hydrological impacts resulting from applying geother­mal fluids to the sugar refining process are discussed and include impacts toboth surface and groundwater quantity and quality. Similar to atmosphericimpacts, the impacts to the hydrological cycle vary with each phase of develop­ment.

7.4.1 Quantity - Utilizing geothe~alfluids for sugar processing may affectgroundwater and surface water supplies. The extent to which supplies will beaffected will depend on the exact design of the system, the geology of thearea, the integrity of the well casings and the ultimate disposal of the fluids,etc.

The groundwater· regime may be altered if adequate protection and controlmeasures are not taken during development of the field. For example, if ageothermal reservoir is overlain by a productive freshwater aquifer it ispossible that the fresh water aquifer can be contaminated if drilling throughthe various horizons causes the geothe~al fluids to mix with the freshwaterfluids. If the different horizons are not kept separate from each other byproper cementing of the casing in either the production or reinjection well,it is possible that the freshwater aquifer could be contaminated, especiallyif the geothermal fluid is highly saline or mineralized.

Also, spills and blowouts could have a negative effect on surface watersupplies. For example, if hypersaline waters were accidentally dischargedinto a freshwater course, the ultimate use of the freshwater course could bealtered since the water might be too saline for use.

In many regions, groundwater is a supplementary supply to surface waters.If the resource were contaminated, the overall available quantity of wateruseable for purposes such as drinking or irrigation, could be adversely affected.This is also true for surface water supplies which could potentially be polluted.Much of the Southwest's water supply is already allocated by treaty or law.Changes to this established system could have far reaching effects to economiessuch as agriculture, that rely on a dependable water supply.

7-14

7.4.2 Qua1ity- Geothermal fluids often contain significant quantities ofdissolved solids including sodium, calcium. potassium, magnesium, andchloride. In addition, the fluids often have significant concentrationsof heavy metals, such as iron, manganese, copper,lead, mercury, zinc andstrontium. The total dissolved solid (rOS) content of geothermal fluids canrange from 200 milligrams per liter (mg/l) to over 250,000 mg/1. Water witha TOS content less than 1500 mg/1 is generally considered potable. TheImperial Valley geothermal fluids are highly saline with TOS concentrationsranging from 2000 mg/1 to over 250,000 mg/1 (at the Salton Sea). However,the fluid in Southwest Idaho (at Mountain Home) is considered to be potablewith TDS concentrations abou~ 800 mg/1. Major potential hydrological impactsinclude increased siltation and sedimentation of surface water. from roadconstruction and drilling site excavation, contamination of surface watersfrom spills or blowouts, accidental contamination of freshwater aquifersfrom improper casing, and degradation of the resource.

In areas where the quality of the brine is low, reinjection of thebrine is usually a convenient means of disposal. It should be noted thatdisposal by evaporation means that a liquid waste disposal problem wouldbe traded for a solid waste disposal problem. To evaporate 126 million gallonsof geothermal brines at a rate of 6 feet/year, a 65 acre evaporation pondwould be required. This is roughly equivalent to the amount of brine producedfrom a well flowing at 1000 g.p.m. operating for 5.5 hours per day (ref. 7-1).Residual solid waste would then be disposed of in an approved disposal site.Even if evaporation were used as a means of disposal, contamination of theground water resources would be possible if the brines leached into the so11.The Bureau of Reclamation has used a plastic 1ined holding pond to allowwaste waters to evaporate without infiltrating into the soil.

7-15

7.5 Noise

Noise generated from geothermal development has been a problem sincethe first steam wells were completed. Noise from geothermal development,which is similar to that from other industrial operations, varies in inten­sity, duration, and freql,.lency with the various phases (i .e., drilling,testing, and full operation). In gen~ral, noise levels decrease withdistance and vary with humidity, vegetation type, topography, wind direct­ion, etc. Geothermal operations which generate noise include:

• Site clearing• Road and facility construction• Well drill i ng• Well venting and bleeding

In addition, it is possible that loud noise could be generated if steamlines or wells should break or rupture. Noise will be generated, no matterwhich well or wellhead configuration shown in Figures 7-4 and 7-5 are utilized.Of the four well flow/effluent handling alternatives shown in Figure 7-2, itis the flashed system without reinjection, Alternate HE-2B, that will generatethe most noise as the water is brought down to atmospheric pressure prior torelease as runoff. It should be noted that a silencer will be used to reducenoise to acceptable levelsi however, the noise will still be continuous.

Table 7-3 presents a comparison of noise levels generated at the Geysersand from other sources. Few noise measurements from geothermal fields otherthan the Geysers have been made. As Table 7-3 shows, noise levels associatedwith geothermal development can be excessive and can pose significant environ­mental impacts. For example, the noise from air drilling rivals that generatedfrom the takeoff of a jet aircraft and the threshold of pain. Noise levels thatare excessive can pose a health and safety hazard to employees, can be objectionalto residents or people visiting the area and can disrupt wildlife distributionand patterns. Table 7-4 presents theresults of noise tests on various types ofanimals, including swine, cows and poultry. It should be noted that although

7-16

TABLE 7-3 COMPARISON OF NOISE LEVELS BETWEEN GEOTHERMAl AND OTHER SOURCES(refs. 7-14, 7-16, 7-17)

NOISE LEVEL (dBA) DISTANCE (ft)SOURCE...•....••......•••..........•.......•....•... ...••............ ..............................

THE GEYSERSDRILLING OPERATION (AIR) 126 25DRILLING OPERATION (AIR) 55 1500MUFFLED TESTING WELL 100 25MUFFLED TESTING WELL 65 1500STEAM LINE VENT 100 50STEAr~ LINE VENT 90 250

COMPARATIVE LEVELSJET AIRCRAFT TAKEOFF 125 200THRESHOLD OF PAIN 120 AVERAGEDRILLING RIG (AIR) 102 50UNMUFFLED DIESEL TRUCK 100 50LOUD MOTORCYCLE 95 50ROAD BUILDING EQUIPMENT 80 - 90 50USAF RECOMMENDED MAXIMUM 85 --STREET CORNER IN ALARGE ClTY 75 AVERAGENORMAL SPEECH 65 1STEAM EXITING BLOOIE WITH MUFFLER 60 50STEAM WELL VENTING-STANDBY 60 (AT SOURCE)ACCOUNTING OFFICE 60 --RESIDENTIAL AREA AT NIGHT

..40 AVERAGE

BROADCASTING STUDIO 25 --THRESHOLD OF HEARING 0 --

....•••........•..•......•........••.........•..•.............•...••......................................•..

\..j * DECIBEL ASCALE: A DECIBEL IS THE UNIT FOR MEASURING SOUND INTENSITY. ONE DECIBELCHANGE IN SOUND IS THE SMALLEST DIFFERENCE IN SOUND INTENSITY THAT THE HUMAN EARCAN DETECT.

7-17

noise levels can be excessive, most of the noise is temporary. However, ifa steam field or a flashed system without reinjection is utilized, than acertain amount of noise will be generated permanently. Noise can becontrolled by use of mufflers.

In all six resource areas, the noise generated from geothermal operationsis expected to have a minor effect upon the surrountling areas; however, innorthern California, Washington and southeast Idaho, the impacts could be moresevere. For example, the Geysers development has produced noise of sufficientloudness to have caused complaints to be made to the various developmentcompanies, the Pacific Gas and Electric Co., the Lake County Air PollutionControl District and the California State Office of Noise Control.

At The Geysers, unmuff1ed sound pressure levels of over 130 dBA have beenmeasured at a distance of 100 feet from well outlets. Under the right conditions,this sound can be heard for miles. Generally, absorption of sound at all frequ­encies tends to increase with increasing air temperature and decreasing moisturecontent. In studies on the noise emitted from The Geysers operations, it wasfound that the ambient noise level that exists when the wells are not venting isvery low (in the vicinity of 28-35 dBA). The noise emitted when the well isbeing vented is low frequency and audible at great distances. During the winterwhen strong temperature inversions and higher relative humidities occur, theproblem is compounded, since the sound waves are bent downwards. The steepterrain of the Geysers area can contribute to a reduction in the noise levelsdue to the tendency of the ridges to diffract the sound waves. It should berecognized that because The Geysers area is primarily devoted to geo-thermal development, with a low background noise level, the people livingnear the development are very likely to complain about the noise (ref. 7-18).

If the geothermal field at Longmire Hot Springs, Washington were to beapproved for development, it is unlikely that excessive noise would be tolerated,since Longmire Hot Springs is situated in a National Park. Even if the resourcewere developed adjacent to the National Park, excessive noise levels would pro­bably not be tolerated.

7-18

( (

TABLE 7-4 EFFECTS OF NOISE ON ANIMAL POPULATIONS (ref. 7-17)

SWINE

TRIALS

5

~ULTIPLE 15-SECOND EXPOSURE. 4. 8 ORII,(;RE TIMES .UUSPECIFIED

DAILY 6 A. M. - 6 P.M.

SEVERAL DAYS

SOUND SIMULATION

120 - 130 dB; AIRCRAFT CONTROLAT 70 dB AIRCRAFT130 dB AT 300 - 600 Hz

100 - 120 dB AT 200 - 5000 Hz

120 - 135 dB

93 dB

EFFECT

NO INJURY TO GROSS ANATOMY OF ORGANOF CORTIINCREASE IN HEART RATE

SOWS: NONE; PIGLETS: HUDDLING.SQUEALINGNO IMPACT ON MATING; HEAVIER PIGLETSAT BIRTH; MODIFIED WEANINGCASTRATED MALES: ALDO STERONISM ANDWATER AND SODIUM RETENTION

...................-..... . .~'iILKCO:-:S

PASTURED NEAR AIR FORCE BASES

PAPER BAG EXPLOSIONS -2 MINUTEfR£QUEUCY D~RING MILKING

UNSPECIFIED

UNSPECIFIED

NO MILK PRODUCTION; DIFFERENCES AMOUNGCOWS AT VARYING DISTANCES FROM FIELDNO MILK GIVEN DURING EXPLOSIONS;70% AFTER 30 MINUTES

......••....•••.•.•............•.....•.•..........•...••••••.••..•.......•...•••••.•••.•••••.•.••••••.••......•.......••...........•" .................••..POULTRY EGG INCUBATION WITH SOUND. 8 IN 20 AIRCRAFT NOISE 120 dB

MINUTES. 8 A.M. DAILY AriD 8 P.M. - \8 A.M. EVERY 3rd NIGHTBR~~DING HENS SUBJECTED TO SOUND UNSPECIFIED

CHICKS UNDER NOISE FROM 8 A.M. - 8 P.M. AIRCRAFT NOISE 80 - 115 dB ATDAILY AND 8 P.M. - 8 A.M. EVERY 3rd 300 - 600 HzNIGHT•

NONE

8 OF 9 HENS QUIT BROODING; ONLY 1 OF12 EGGS HATCHED BY REMAINING HENNONE

..•.•.•... ...............................................•.... ......•..•................•...........•.... .............•....••••..........••••..•••••••...:·iINi< SERIES OF SONIC BOOMS .

6 SONIC BOOr~ IN 10 DAYS

z z485 Hz 2.0 lb/ft - 0.5 lb/ftGRADIENTUNSPECIFIED

INCREASED LIl"TER SIZE

NONE --~

The two resource areas considered in the southeast Idaho area areRaft River in Idaho and Brigham City in Utah. The Raft River is relativelyuninhabited and ambient noise levels are low. The Raft River geothermalarea is known to be a nesting site for the Peregrine falcon and the ferri­ginous hawk. Both are considered rare or endangered species. The noisethat would be generated from geothermal development in this area, especiallythat generated from drilling, may have a negative impact on these species.

The site near Brigham City is located a number of miles outsi~e of thecity in a predominantly agricultural area, with low levels of ambient noise.Some rare or endangered species have been seen near the geothermal site,including the humpback club, Colorado River Squawfish, Woundfin, Peregrinefalcon, black footed ferret and the Utah prairie dog. Excessive noise fromgeothermal operations may have deleterious impacts on these species.

7.6 Erosion And Landslides

Development of geothermal resources in areas of steep terrain and unstablesoils may result in both landslides and excessive soil erosion. In areas wherethere is steep terrain, excavation of the land is required during constructionto provide room for drilling sites, roads, facilities, pipelines, etc. Theamount of soil erosion tends to increase when natural slopes are cut and filledsince slopes are made more steep and the vegetative cover is removed. As aresult of the loss of vegetation cover, the soil is no longer protected from theimpacts of precipitation. This leads to an increase in stream siltation and thesuspended sediment load, as well as to an increase in wind erosion and potentialflash floods. When construction is completed and the slope is rehabilitated withnew vegetation, sediment, siltation and other erosional problems are usuallyreduced. However, it should be noted that there will always be an increase in soilerosion from surface disturbances.

It has been estimated that for areas like The Geysers, where the terrainis steep, approximately 1 to 3 acres of cut and fill land is needed to provideanough room for drilling operations. The amount of land disturbed by accessroads and pipelines is shown in the following table (ref. 7-1):

7-20

u

TYPE OF EXCAVATION

Primary RoadsSecondary RoadsPipelines

WIDTH OF EXCAVATION

50 Feet30 Feet40 Feet

Landslides, known to occur as a result of geothermal development, canbe a serious problem on steep slopes underlain by weak bedrock. For example,the California Division of Mines and Geology has estimated that at theGeysers, approximately 50 percent of all facilities are situated on unstableslopes. Although some soils in The Geysers area is stable (Los Gatos andMaymen), much of the soil is the Yorkville series, considered to be highlyunstable and to have poor slope stability. In fact, portions of the bedrockhave been weakened by faulting, fracturing and alteration from the geothermalresource. In 1973, the Happy Jack Well No.7 was broken at a depth of 35 feetfollowing heavy rains and presumably a small landslide. The well is stilluncontrolled. Excavation of new sites and facil fti es may trigger movement ofslope material, even if sound engineering practices are used.

Topographic descriptions of the six resource areas are listed in Table7-5. With the exception of northern California and Washington, which arelocated in mountainous areas with steep slopes, the resource areas are locatedon ei ther f1 at desert or valley .1 ands • Thus, it appears that eros iona1 prob1emswill be more severe in the Northern California and Washington areas where thegeothermal fields are located beneath steep slopes.

Generally, in the application of geothermal heat to sugar beet processing,all proposed alternatives will result in some erosion problems. Systems, suchas those shown in Figures 7-4 and .7-5, that utilize underground pipelines totransport geothermal fluids from the reservoir to the process will cause greatersurface disruptions and will result in more erosion impacts than systems wherethe wellhead is located adjacent to the process. Asystem not designed forreinjection of the fluid will also cause greater erosion than a system that isdesigned for reinjection, especially if the fluid is allowed to flow onto theground into natural drainage pathways (See Figures 7-2 and 7-6). In addition,

1-21

TABLE 7-5 TOPOGRAPHIC DESCRIPTION OF GEOTHERMAL RESOURCE AREASu

RESOURCEAREA

NORTHERNCALIFORNIA

SOUTHERNCALI FllRNIA

SOUTHWESTIlJAHO

SOUTHEASTIDAHO

ARIZONA

WASHINGTON

TOPOGRAPHIC DESCRIPTION

THE NORTHERN PART OF THE GEYSERS KGRA IS FLAT TO ROLLING LAND. THESOUTHERN PORTION IS MOUNTAINOUS. WITH STEEP SLOPES. ROCKY OUTCROPSAND STREAM CANYONS. THE MAYACMAS MOUNTAINS PASS THROUGH THE SOUtHERNPORTION AND SLOPES RANGE FROM 30 - 40%. KGRA HAS SEVERAL VALLEYS.TWO MAN-MADE LAKES AND SEVERAL NATURAL LAKES.

THE KGRA'S IN THE IMPERIAL VALLEY ARE ALL ON FLAT DESERT LAND. ~tICH

IS IRRIGATED AND USED FOR AGRICULTURE. THE IRRIGATION SYSTEM AND THEFIELDS HAVE BEEN LAID TO SPECIFIC GRADES.

THE BRIGHAM CITY SITE IS IN AWIDE FLAT VALLEY BORDERED BY THE WASATCHMOUNTAINS ON THE EAST. THE RAFT RIVER SITE IS IN AVALLEY THAT ISGENERALLY LEVEL. WITH RELIEF LIMITED TO SMALL GULLIES AND RIDGES. THEVALLEY IS BORDERED BY THE JIM SHOE MOUNTAINS.

MOUNTAIN HOME IS LOCATEO IN THE WESTE~~ SHAKE RIVER BASI~ ON RELATIVELYFLAT LAND INTERSPERSED WITH A FEW GENTLY ROLLING HILLS. OTHER AREASOF INTEREST ARE GENERALLY IN LOWLANDS ON EITHER SIDE OF THE SNAKE RIVERWITH FLAT TOPOGRAPHY. IN VALLEYS BORDERED BY FLAT TOPPED PLATEAUSOR MOUNTAINS.

THE CHANDLER WELL IS ON FLAT DESERT LAND THAT IS IRRIGATED AND USEDFOR AGRICULTURE. THE REGION HAS SEVERAL DRY STEAM WASHES AND ARROYOSAND IS BORDERED BY THE PHOENIX MOUNTAINS.

LONGMIRE HOT SPRINGS IS LOCATED IN THE RUGGED TERRAIN OF THE CASCADEMOUNTAINS IN ANATIONAL PARK.

7-22

( (,NON-CONDENSIBLE GASES NON-CONDENSIBLE GASES

r-1-----+. NOISE• NON-CONDENSIBLE GASES• AESTHETICS (STEAM PLUME)

ALTERNATE HE-2A-l(WITHOUT REINJECTION)

• SUBSIDENCE• DEPLETION OF RESOURCE• SEISMICITY

1JI'-

RUNOFF1J---~~-"" OR

IRRIGATION--:~:-t"r--~~~~~--....... SALINITY

, ~ ,l.~

• TEMPERATURE• TOXICCHEMICALS;• EROSION

STEAMSEPARATOR(TYP)

~:l.r- H2S

~,~ I~~r'ENT• SOLI DWASTE

DISPOSALCONDENSOR • AESTHETICS(TYP) • EROSION

\ I

• SUBSIDENCE• DEPLETION OF RESOURCEe SEISMICITY

INJECTION PUMP

I .. '..J I ."-..

WASTEWATER

SUGARREFINING

ALTERNATE HE-2B-l~ (WITH REINJECTION)1,'

_--==-__--==__.........._'--"-._.. ,_.c.·-:=.=-_

• SOLID WASTE DISPOSAL• AESTHETICS• EROSION

\ /--;--.._-..1-_POND

.....I

NW

, .

Figure 7-6 Sugar Refining Waste Water Utilization Al ternate

in the systems where the process waste water is used for make up waterfor either reinjection or runoff and irrigation (see Figure 7-6), some ofthe process waste water must go to an evaporation pond. Upon evaporationof the fluid, the solid residue and waste must then be disposed of in anapproved disposal site. Increased erosion may result from excavation ofthe pond and from wind erosion of the solid wastes stored in the pond.

7.7 Aesthetics

Developing a geothermal resource area for application of the heat tothe sugar refining process will result in both temporary and permanentaesthetic impacts. Generally, less than one acre per drilling site will berequired for excavation.

Geothermal development can be compatible with existing land uses. Forexample, at Lardarello, Italy, much of the geothermal field is used for agri­culture while at the Geysers, much of the field is used for hunting and cattlegrazing. However, geothermal development can alter existing land uses. InNew Zealand, subsidence caused by geothermal production has resulted in aloss of hot springs and fumaroles and a change in the local tourist industry.In other areas, lt is possible that geothermal fluids discharged to riverscould deleteriously affect fisheries and irrigated crops if the fluids are hightemperature or low quality.

The amount of visual impact will vary depending on the type of geothermalsystem utilized. A system requiring the use of an underground pipeline totransport the fluid, such as the vertically drilled or the remote wellhead sys"temshown 1n Figures 7-4 and 7-5, will disrupt a much larger surface area than asystem that does not require a pipeline. The way in which the well flow effluentis handled can also have aesthetic impacts. As shown in Figures 7-1 and 7-6,a system that is not designed for reinjection will generate a steam plume fromthe silencer, as well as from testing procedures. These steam plumes are oftenvisible for miles, especially in areas where the terrain is flat and the plumeis not easily camouflaged by the natural topography.

7-24

u

If the process waste water is used as make up water for either thereinjection fluid or the runoff, an evaporation pond will be requiredfor the excess amount of waste water. The scars left by a pond that isnot rehabilitated can have a permanent visible impact. depending on therate of revegetation. Site rehabilitation will minimize aestheticimpacts. Full consideration must be given to aesthetic design, placementof man-made structures, use of compatible colors, landscaping and vegeta­tive restoration to minimize visual impacts.

In most of the six resource areas, development of the resource willrequire that men and equipment be placed onto relatively pristine lands.Impacts to the aesthetic quality are usually caused by visual obstruct­ions or intrusions associated with excavation, drilling operations,pipeline and facility construction and vegetation removal, etc. Also,alteration of existing land uses can be considered to have an aestheticimpact. The extent of the visual impact at each site will vary dependingon the topography, vegetative cover, the methods employed to minimizethe impact, the proximity to population centers, parks and forest, etc.It should be noted that the extent to which aesthetic impacts are per­ceived will vary from person to person and is very subjective.

Of the six resource areas identified, two areas, northern Califor­nia and \4ashington, will encounter problems in developing their geothermalresources because of aesthetic impacts. Clear Lake County in NorthernCalifornia is a recreational area of high aesthetic quality. Potentialimpacts are of major concern to the public. longmire Hot Springs inWashington is situated in a National Park where aesthetic impacts arealso of major concern •. In addition, since both areas are in areas ofrugged terrain,more land might have to be excavated to provide room forroads and drilling sites.

7-8 Geothermal Versus Fossil Fuel

One environmental issue of great concern is the impact of geothermaldevelopment relative to other sources of power. Table 7-6 shows the advant­ages and disadvantages of a geothermal system versus afossilful::l system.

7-25

.....I

N0'1

. TABLE 7-6 ADVANTAGES AND DISADVANTAGES OF A GEOTHERMAL VERSUS A FOSSIL FUEL SYSTEM

A 0 VANT AGE S DIS A DVANT AGE S

• AVAILABLE IN USABLE FORM AT PRODUCTII)N SITE • CANNOT TRANSP(!RT RESOURCE EXTENSIVELY

• NO PROCESSING OR TREATING (SUPPORT OPERATIONS) • LOCATED IN RE~roTE AREAS

• IMPACTS RESTRICTED PRIMARILY TO PRODUCTION SITE • DISPOSAL OF BRINES

GEOTHERMAL • FEWER WATER REQUIREMENTS • NOT FULLY DEFINED LEGALLY

• H2S IS PRIMARY POLLUTANT OF CONCERN

• MINERAL BY PRODUCTS (SULFUR RECOVERY)

• POTENTIAL FOR DESALINIZATION, IRRIGATION, ETC.

• MAY BE A RENEWABLE RESOURCE

• AFFECTS Sr~LLER NEWER AREA • REQUIRES PROCESSING OR TREATMENT

• MORE FLEXIBLY LOCATED • IMPACTS EXTEND TO MINING, PROCESSING, TRANS-

FOSSIL FUEL • TECHNOLOGY MORE DEVELOPED PORTATION, POWER PRODUCTION, WASTE DISPOSAL

• FUEL IS CAPABLE OF BEING TRANSPORTED • NON-RENEWABLE RESOURCE

• MINERAL BY PRODUCTS (SULFUR RECOVERY) • GREATER WATER REQUIREMENTS

• EMISSIONS (C02, SOx' NOx' PARTICULATES)

c

u

7. REFERENCES

7-1 Final Environmental Statement for the Geothermal Leasing Program,U.S. Department of the Interior, Volumes I - IV.

7-2 Anspaugh, LR. and Phelps, P.L, eds .. An Overview of the Imperial ValleyEnvironmental Proj~. Lawrence Livermore Laboratory, UCID - 17067,April 8, 1976.

7-3 Anspaugh, L.R. and Phelps, P.L., eds., Imperial Valley Environmentalf!QJect: Progress Report, Lawrence Livermore Laboratory, UCRL 50044-76-1.

7-4 Existing and Potential Geothermal Policies, County of Imperial, PlanningDepartment, December 1, 1976.

7-5 Geysers Power Plant Technical Information - Air Quality and HydrogenSulfide Abatement, Pacific Gas and Electric Co., Department of EngineeringResearch, April 6. 1976.

7-6 Tucker, F.L. and Anderson, M.D., eds., Geothermal Environmental Seminar,October 27-29, 1976, Lake County, California.

7-7 Reed, M.J., "Environmental Impact of Development in the Geysers GeothermalField, U.S.A.." Paper Presented to Second U.N. Symposium on the Developmentand Use of Geothermal Resources, May, 1975.

7-8 Environmental AnalxsisRecord .. Geothermal·LeasingonNational ResourceLands in Cassia County, Idaho, Bureau of Land Management, Burley DistrictOffice ,1974.

7..9 Chaney, E., The Sagebrush - Grass Ecosystem, Description of the ExistingEnvironment, Boise District, U.S. Bureau of Land Management, October 15, 1974.

7-10 Environmental Analysis Record - Geothermal Leasing and Development onPotential Areas Within the Boise District. Bureau of Land Management,Boise, District.

7-27

7-11 Environmental Analysis Record - Proposed Geothermal Leasing for Crane ~Creek KGRA and Adjacent Areas, Bureau of Land Management, Boise District.

7-12 Lundberg, Edward A., Geothermal Development Program and Its Water SupplyPotential for the Southwest.

7-13 Regional Eva1uation.of the Geothermal Resource Potential in CentralWashington State, Prepared for Washington Public Power Supply Systemby Woodward-Gizienski &Associates, January, 1975.

7-14 Geothermal Handbook, NP-21172, u.S. Fish and Wildlife Service, GeothermalProject, June, 1976.

7-15 Axtmann, R.C., IIEmission Control of Gas Effluents from Geothermal PowerPlants,lI Environmental Letters, 8(2}, Princeton University, New Jersey.pp. 135-146, 1975.

7-16 Beall, S.E., et.al., An Assessment of the Environmental Impact ofAlternative Energy Sources, ORNL-5024, Oak Ridge National Laboratory,September, 1974.

7-17 Anderson, S.O., "Environmental Impacts of Geothermal Resource Developmenton Agriculture: A Case Study of Land Use Conflict,lI Second U.N. Symposiumon the Development and Use of Geothermal Resources, May, 1975.

7-18 Illingworth, R.R., Factors Contributing to Annoyance by Geothermal SteamWell Venting Noise at the Geysers. Paper Presented to the GeothermalEnvironmental Seminar, October 27-29, 1976, Lake County, California.

7-28

8. CLOSELY RELATED PROCESSES

Process applications that are closely related to the beet sugar geo­thermal applications derived in this study will be identified for potentialtechnology transfer.

The evaporation process, using medium pressure steam, which is a keyelement in beet and cane sugar refining, is also used in the chemicalindustry in the manufacture of caustic soda and table salt and in thepulp and paper industry.

Pulp drying applications are likened to alfalfa drying and it is notedthat the same equipment could probably be utilized for seasonal balancedutiliz~t10nof the geothermal energy supply system with significant beneficialeconomic impact as discussed in Section 6.

Also, it is observed that other crop dehydration applications with lowtemperature requirements ( 250°F) such as onion, grain or seed drying couldbe economically cascaded from the geothermal outputs of the sugar applicationsas described in Section 6.

8-1

9. EFFECT/NEED FOR TECHNOLOGICAL/POLICY CHANGES

Assessments were conducted to evaluate the impact of technologicalor institutional factors or changes which might affect the potential forconversion to geothermal heat. Results are described below.

9.1 Geothermal Loan Guaranty Program

The Geothermal Loan Guaranty Program became effective on June 25,1976, following publication of regulations on May 26, 1976 (10 CFR 790).The purpose of the program is to accelerate commercial development ofgeothermal energy by the private sector by minimizing the financial riskto lenders. Congress appropriated $30 million to cover $200 million inloan guarantees for FY 1977. Maximum limits stipulated in the programare $25 mi11ibn for a single project and $50 million for a single bor­rower. Loans are guaranteed for up to 30 years; however, no new guaran­tees will be authorized past 1984. The borrower must comply with appro­priate federal, state and local administrative and environmentalregulations, which can delay the loan guaranty; however, such delays areexpected to be minor.

ERDA has stated that itwi11 give top priority to projects that willmost quickly result in the production of useful energy from geothermalresources, that will utilize new technological components and that willexploit the potential of new geothermal resource areas. Lower prioritywill be given to projects that propose exploration operations or theacquisition of land or leases.

In the past, it has been difficult to find adequate numbers of skilledpersonnel to work in the field. Most people work for successful ventures,such as The Geysers, and are reluctant to work elsewhere. In addition, ithas been difficult for new workers to enter the market. As a result,there has been a shortage of personnel for geothenna1 drilling. Financialinstitutions and private investors have been reluctant to commit funds forgeothermal development. They feel that investing in geothermal drilling

9-1

has a greater risk than investing in oil and gas drilling for tworeasons. First. investors must be assured of the reliability of thereservoir. Although oil. gas and geothermal resources are defined. thereliability of the geothermal resource is still relatively unknown.~

especially for hydrothermal fields. This lack of assurance makes geo­thermal drilling a higher risk venture than oil and gas drilling.Second. tax incentives for oil and gas drilling are greater than forgeothermal drilling. These tax incentives make investment in the oil andgas area more attractive to capitalists than investment in the geothermalarea. The competition for capital has discouraged geothermal development.The Geothermal Loan Guaranty Program may help ease this problem byencouraging development of geothermal energy while simultaneously reduc­ing the financial risks.

9.2 Tax Policy

Due to the diversity of the possible types of geothermal uses andapplications. the geothermal resource is difficult to fully describe. TheGeothermal Steam Act of 1970 (84 Stat. 1573. 30 U.S.C. 1001-1025) leftunresolved the question of whether or not geothermal steam and associatedgeothermal resources are to be regarded as part of the water resources ofa state; therefore. subject to applicable state water laws. which varyfrom state to state. In some states (i.e •• Hawaii) geothermal resourceshave not yet been fully defined legally.

The uncertainty of how to legally classify geothermal resources(water. mineral. heat. etc.) has resulted in taxation problems. Federaltax law does not have a provision for a depletion allowance specificallyfor geothermal energy. However. in a case held before the tax court in1969. Reich vs. Commissioner of IRS (52 T.C. 700. 1969). it was held thatthe natural steam at The Geysers qualified for a depletion allowance andthat the producers were entitled to write off as expenses the untangib1ecosts of drilling and developing The Geysers field. The reasoning inthe case was that the steam at The Geysers is not ordinary ground steam

9-2

fed by constant water seepage and inexhaustible. but steam that is lockedin closed spaces like natural gas. not replenished by seepage and deplet­able. Therefore. it was reasoned. that it should be subject to the sametax treatment as natural gas with respect to the depletion allowance andintangible drilling and development costs. It should be noted that thereasoning of this case may not be extended to depleting hot water and hotrock resources.

Since the Federal Tax structure does not contain a depletion allow­ance that applies to most geothermal resources. it appears that it mightdiscourage investment of venture capital in exploration. drilling andfield development. It should be noted that efforts are being made tochange this aspect of the existing structure and that progress is beingachieved.

9.3 Technology Improvements

Technology improvements whi ch could improve the economic feasibil i tyof geothermal applications to sugar refining have been as follows:

a. Well stimulation completion and workover technology improve­ments to increase flow. thus reducing the most significantcost element of the energy supply system.

b. Heat exchanger scaling control improvements such as acidtreatment. continuous cleaning (modified AMERTAP) directcontact and fluidized bed improvements to improve approachefficiency and minimize capital and maintenance costs.

c. Non-condensible H2S gas control and abatement improvements •.This would permit using lower cost more efficient steamseparators as described in Section 3.

d. Lower temperature evaporation sequence technology improve­ments to permit maximum cost effective resource temperatureutilization.

9-3

9.4 Environmental and Administrative Regulationsand constraints .

Asubstantial portion of the development time-to-market for a geo­thermal resource is the time required to obtain approvals from govern­

·ment agencies. Approval delays have a direct bearing on the economicsof development and thus directly affects the potential of geothermalprospects.

The most significant differences in administrative requirements forgeothermal development are exhibited state by state, rather than prospectby prospect. The procedure and regulations adopted by local countygovernments are generally similar within any state. Most counties assumea minor role in the regulation of geothermal activity and the stateassumes the major responsibility, except in California, where local govern­ment exercises significant control.

Environmental and adminstrative requirements consist of variousregulations and permit procedures that vary by state and county and withfederal, state or private land ownership. The most complex series ofprocedures are found in development on federal lands and usually theinteraction of regulatory authority between federal, state and countylevels of government is required.

Table 9-1 shows the admi'nistrative and environmental requirementsfor development of geothermal resources on state or private land forCalifornia, Arizona, Idaho, Oregon, Washington and Utah. These stateswere selected based on the data developed in Section 2, which identifiedpotential sugar manufacturers within economic proximity to geothermalresources. Table 9-1 shows the procedures and applicable regulations orregulatory agencies for exploration and development and production.

As thiS table shows , regulatory requirements for development of geo­thermal resources are generally identical, with the exception of theleasing procedures. The California procedures and regulations are themost stringent in the nation. These tough requirements stem primarily

9-4 '

( (

ADMINISTRATIVE REQUIREMENTS FOR DEVELOPMENT OF GEOTHERMAL RESOURCES ON STATE OR PRIVATE LAND.

TABLE 9 1

EXPLORATION DEVELOPMENT AND PRODUCTIONS TAT E

NEW REGULATIONS TOPROCEDURE REGULATIONS PROCEDURE REGULATIONS(OR REGULATORY AGENcr~~\ (OR REGULATORY AGENCIES\ B E PROMULGATED

EIR REQUIRED BY COIJNTY ,0. REVIEW BY APPLICABLE COUNTY REGULATIONS EIR REQUIRED BY COUNTY, REVIEW BY APPLICABLE COUNTY REGULATIONS NONE IIt1EDIATESEVERAL AGENCIES: STATE OIL a GAS DEPT. SEVERAL AGENCIES: STATE a OIL GAS DEPT.• DIVISION OF OIL AND GAS • DIVISION OF OIL AND GAS• AIR RESOURCES BOARD REGIONAL WATER QUALITY BOARD • AIR RESOURCES BOARD REGIONAL WATER QUALITY BOARD

CALIFO.RKIA • STATE \lATER RESOURCES COOROL AIR POLLUTION CONTROL BOARD • STATE WATER RESOURCES CONTROL AIR POLLUTION CONTROL BOARDBOARD BOARD

PUBLIC UTILITIES COMMISSION• ENERGY RESOURCES CONSERVATION • ENERGY RESOURCES CONSERVATION

AND DEVELOPMENT COMI1ISSION AND DEVELOPMENT COMMISSIONDRILLING PERMIT" BY OIL & GAS DEPT. DRILLING PERMIT BY OIL & 'GAS DEPT.LAND USE PERMIT BY COUNT~ LAND USE PERMIT BY COUNTY

DRILLING PERMIT, OIL & GAS OIL & GAS COfItlISSION REGULATIONS. STATE LANDS DEPT. APPROVES SITING APPLICABLE COUNTY REGUlATIONS. NONE IMMEDIATECOMMISSION IS SOLE AUTHORITY. APPLICABLE COUNTY REGULATIONS OF PROJECTS (PMR PLANTS) ON STATE STATE POWER AUTHORITY.

LANDS. NO SITING AUTHORITY EXISTSARIZONA FOR PRIVATE LAND. OIL & GAS COMMISSION~

DRILLING PERMIT BY OIL &GAS COMMISSION.

DRILLING PERMIT. \lATER RESOURCES WATER RESOURCES DEPT. DRILLING DEVELOPMENT PERMIT. WATER RESOURCES WATER RESOURCES DEPT. REGULATIONS. EXPANSION OF COUNTY REQUIREMENTSDEPT. IS SOLE AUTHORITY. REGUlATIONS, PAmRNED ON OIL & DEPT. I SSUES APPROVAL AFTER REVIEW PUBLIC UTILITIES UNDERWAY.

I D A H 0 COUNTY MAY REQUIRE SPECIAL USE GAS PROCEDURES. BY HEALTH & WELFARE DEPT. PUBLICUTILITIES APPROVE SITING OF APPLICABLE COUNTY REGULATIONS.PERMIT IN DESIGNATED AREASPRODUCTION PLANTS.

APPUCATION FOR AN EXPLORATlori DEPT. OF. GEOLOGY AND MINERAL APPLICATION FOR A GEOTHERMAL RE- DEPT. OF GEOLOGY AND MINERAL NONE IMMEDIATESOURCES LEASE IS MADE TO DIVISIONPERMIT IS MADE TO THE DIVISION INDUSTRIES REGULATIONS OF OF STATE LANDS, ISSUED BY DEPT. OF INDUSTRIES REGUlATIONS OFOREGON OF STATE LANDS AND ISSUED BY THE GEOTHERMAL WELLS. GEOLOGY AND MINERAL RESOURCES IN GEOTHERMAL WELLS.

DEPT. OF GEOLOGY AND MINERALRESOURCES. DEPT. OF ENVIRONMENTAL QUALITY COMPLIANCE WITH DEPT. OF ENVIRON· DEPT. OF ENVIRONMENTAL QUALITYMENTAL QUALITY REGULATIONS. E1R

ENVIRONMENTAL REGULATIONS REQUIRED BEFORE APPROYAL OF LEASE. ENVIRONMENTAL REGULATIONS

DRILLING PERMIT FOR STATE AND DEPT. "OF NATURAL, RESOURCES DEVLOPMENT PERMIT, DEPT. OF NATURAL DEPT. OF NATURAL RESOURCES NEW REGUlAT~ONS BEING DEVELOPEDPRIVATE LANDS. DEPT• OF NATURAL DIVISION OF GEOLOGY AND EARTH RESOURCES, DIVISION OF GEOLOGY AND DrvrSION OF GEOLOGY AND EARTH BY DEPT. OF NATURAL RESOURCES.RESOURCES, DIVISION OF GEOLOGY AND RESOURCES REGUlATIONS. EARTH RESOURCES. RESOURCES REGULATIONS.

WAS H I N G TO" EARTIIRESOiJRCES;IS SOLE AUTHORITYDEPT. OF NATURAL RESOURCES WILL BE EIS REQUIRED FOR DEVELOPMENTI DEPT. OF NAruRAL RESOURCES WILL BE

EIS REQUIRED FOR PROPOSED LEASING LEAD AGENCY. APPROVAL BY DEPT. OF PRODUCTION {COULD CAUSE 1 YEAR LEAD AGENCY. APPROVAL BY DEPT. OFPROGRAM (COULD CAUSE 1 - 4 YEAR ECOLOGY. DELAY) BY DEPT. OF ECOLOGY ECOLOGY.DELAY) BY DEPT.:OF ECOLOGY.

DRILLING PERMIT. WATER RIGHTS DRILLING REGULATIONS PAmRNED DRILLING PERMIT, WATER RIGHTS DRILLING REGUALTlONS OF WATER NEW REGULATIONS, NOW IN PROCESSUTAH DIVISION IS SOLE AUTHORITY. AFTER OIL a GAS PROCEDURES. DIVISION IS SOLE AUTHORITY. RIGHTS DIVISION FOLLOWING RECENT GEOTHERMAL

COUNTY MAY. REQUIRE LAND USE PERMIT. APPLICABLE COUNTY REGULATIONS. COUNTY MAY REQUIRE LAND USE PERMITS APPLICABLE COUNTY REGULATIONS. LEGISLATION.

-EIR IS REQUIRED BY STATE i.ANDS COMMISSION, FOR STATE LAND;I!OlIEVER, EXCEPT FOR THE GEYSERS AREA, ALL LAND OF GEOTHERMAL INTEREST IN CALIFORNIA IS EITHER PRIVATE OR FEDERAL.

-

from the California Environmental Quality Act, which insures that alllocal governments control new development in a manner consistent withthe policy guidelines (environmental goals) of the Act. All proposedprojects, public or private, which are judged to offer potential signif­icant impact to the environment, may not be implemented without prepara­tion and evaluation of an Environmental Impact Report (EIR). The local(county) governments are the responsible agency in issuing the require­ment for an EIR, and participate jointly with numerous state and localagencies .in the approval of a proposed project. In other states, suchas Arizona, Utah, and Idaho, environmental impact reports are not requiredby either local or state authorities and approval of a proposed geothermalproject is accomplished by relatively simple processes.

Figure 9-1 illustrates the administrative requirements for develop­ment of geothermal resources on federal lands. Requirements fordevelopment of geothermal resources on federal lands are distinct in thatthe concept of full development is used from the outset. Issuing a fed­eral lease for geothermal development is contingent on the sUitabilityand approval of total development. This initial requirement is the mostsignificant impediment to developers of geothermal resources on federallands. Conversely, the greatest administrative deterrents facing devel­opers on state or private lands may often occur downstream of explorationactivities, when more stringent approval procedures are applied. Admin­istrative problems increase if a private/state land development spreadsinto adjacent federal land. Currently, geothermal activities on federallands are also subject to state and local requirements. However, as

Generally, the severity of constraints generated by regulations andpolicies depends on the following five factors:

• the number of reviewing agencies in the approval process(i.e., as many as 40 in California and 1 in Arizona)

• the delays associated with the approval processes. Manyprocedures do not stipulate a time target.

9-6

( (

IlU! prepares-:E;.:I::,S --I EAR or [IS fO,.I-__EA..R....._,

geothe.....lde".lopoent

accep.eaI ht .....st btd

8LM plaeft land.nder CClIIIPeti tt".btd·

Constructtonvttltzetion

Revtew of EAR or EIS

• USGS• 8ure•• of Reel_tton

• EPA• 8uret. of Sport ftsheriesand IItldlife

• Stlte .genetes• Local .genetes

r------,lEAR (8LM) or ElSII ,

~ (001) .l-'llty be req.tred l1 IL __ .... J

IlEAR or EIS'not req.tred1

t

DEYELOPMEIlT AND PROIIUCTION

Reporting Req.t~nts IDrill1ng Regul.tions J

Co.nty regul.tions.

tUSGS .pprovel ofPlan of Oper.tioMfor de".IOfllllent.l

. drtlling

Countyregulattons

1

EXPLORATION, , ,.

USGS drt 11tngreguletions IUSGSreporttng

IISGS"","t_ts

~Explor.tory

... drt11ing pe"",tt 1----1­issued by USGS

Operltorsublllttspl.n ofoperation

II,

non-KGIlAI Prospecting pe"",tt......- ls.rf.ce 'llPlor.tton)

+ INly be tssued. Infor-IOItton is av.n.ble to USGS.

joper.tor ftles.pplic.tion

forlease

LAND ACQUISITION

~--------1

I Oper.tors KGRAI ..ylltke:1--,nattons: for btddtngI ......---11....-_--,

II,IL_h!J'l!SJ.~cL~

nOt .cc"tea

I

Condittonal1.... issved.

'------1 stipulattons t----­outlined byUSGS

Revtew AgenciesUSGS8LMEPALocal .geneiesStlte .genctes

IRevtew AgenctesUSGS8LMEPASt.te ageneteslOC.l agencies

AppliclbleL-.- ",",tts of EIRs '---­.-- req.tred by

locil Ind stlte.genctes

Stltereg.lations

Stlte reg.l.ttons St.te 'Ild loc.lregulattons FIGURE 9-1

ADMINISTRATIVE REQUIREMENTSFOR DEVELOPMENT OF

GEOTHERMAL RESOURCES ONFEDERAL LAND

• the nature and disposition of the reviewing agencies.

e the disposition of private-interest groups, such as theSierra Club.

• the complexity and the technical consequences of requirementsto be implemented

The situation shows promise of improving, however, in that theCalifornia Energy Resources Conservation and Development Commission isset up to reduce redundancies and overlaps in regulatory jurisdiction,and have had a program in the development stage for seven months whichintends to define limits of jurisdiction, methods of cooperation andminimizing of red tape and delays in permitting decisions. Also, stepsare being taken at the federal and state level to allow the use of asingle document to suffice for an EIS and EIR, when a project overlapsfederal and state or private lands.

9-8

10. TECHNOLOGY TRANSFER

The objective of this task was to identify potential beet sugar factoryusers of geothermal energy and disseminate the· results of the study tostimulate early development of commercial applications.

The study identified sugar beet factories which are located neargeothermal anomalies and offer potential for retrofit or relocation aretabulated below in order of decreasing potential:

Factory

Location Area Firm

(1) Brawley Imperia1 Vall ey, CA Holly(2) Chandler Arizona Spreckels(3) Nyssa Southwest Idaho Amalgamated(4) Mi ni- Cass18 Southeast Idaho Amalgamated(5) Idaho Falls Southeast Idaho U & I(6) Nampa Southwest Idaho Amalgamated(7) Twin Falls Southeast Idaho Amal gamated

Based on these study findings, telephone conversations relating the studyresults have been held during the course of the study with the following firmrepresentatives:

• Holly Sugar - George W. Miles, Jr., Senior, Vice President - Planning• Spreckels - Temple C. Rowe, Chief Engineer• Amalgamated - Sylvester M. Heiner, Chief Engineer• U&I - Franklin Wareham, Manager of EngineeringAdditionally, several conversations have been held with Van R. Olsen, Director

of Public Affairs for the United States Beet Sugar Association.

Syd Willard of the California Energy Resources Conservation and DevelopmentCommission has been invited to, and attended all review meetings with ERDA.

Copies of the final report will be sent to each of the aforementionedinterested parties in lieu of conducting a workshop at the conclusion of thestudy.

'-I

10-1

11 .; FUTURE WORK PLAN

The sugar industry would be required to invest significant amounts/

of capital for a retrofit or new plant conversion from a fossil fuel toa fossil fuel/geothennal systen for refining sugar. Therefore, to meetthe objectives of this study, TRW has solicited from representatives ofthe sugar industry the type of infonnation they would require beforeseriously considering geothenmal conversion.

In Section 2, selected areas of geothenmal resources within economicrange to beet-growing areas and factories were identified. Sugar manuf­acturing representatives were selected from the. list of potential geothenmalusers described in Section 2. Representatives that were contacted includethe following:

• George Miles - Holly Sugar

• Temple Rowe - Spreckels Sugar

• Franklin Wareham- U&I, Inc.

• Sylvester Heiner - Amalgamated Sugar

• Van R. Olsen - U.S. Beet Sugar Association

The major areas of concern or steps to achieve geothenmal adaptationwhich were identified by the sugar representatives contdcted are~

• Indication of technical and economicfeasibility

• Assurance of reservoir capacity

• Assurance of operational feasibility.

11-1

11.1 Indication Of Technical And Economic Feasibility

Representatives fran the sugar industry have stated that for sugarmanufacturers to participate in a geothenna1 project, the technical andeconanic feasibility of using geothennal fluids to replace fossil fuelsas an energy source must first be detennined. Once the technical feasi­bility has been established, it must then be detenmined that the cost ofgeothennal energy be canpetitive with the industry's other alternatives.In the short tenn, geothema1 energy will have to be canpetitive withnatural gas and residual fuel oil in California and coal in Utah andIdaho, while in the long tenn, geothenna1 will have to be canpetitivewi th coal only.

Prior to considering the use of geothennal energy in their factories,sugar manufacturers must have credible predictions of feasibility for thefollowing econanic factors:

• the amount of capital out1~.

• overhead, operation and maintenance.

In canmunicating with the sugar manufacturers the approach and findingsof this study were discussed and generally appeared to be received ascredible indicators of technical and econanic feasibility.

11.2 Assurance of Reservoir Capacity

Because of its perishable nature, the sugar beet crop cannot be storedand must be processed immediately. The process requires a source of energythat is dependable for the length of the sugar campaign, 24 hours per day,7 days per week for 4-6 months. For sane California manufacturers, areliable energy source has becane a primary area of concern, since they havehad severe curtailments of natural gas in 1976 and 1977 and have beenforced to seek other fuel sources, such as residual fuel oil, to maintainoperation of sugar factories.

11-2

u

u

Before proceeding with a retrofit or new plant, the sugar manufact­urers contacted by TRW indicated that a well defined geothermal reservoirwould be required. Definition of the reservoir should include tests ordemonstrations which:

• indicate total energy of the reservoir.

• estimate recoverable energy.

• determine reservoir longevity at various production rates.

• estimate off-sugar season regeneration capability.

Specifically, reservoir testing should demonstrate minimum reliabilityof temperature, flow rate and pressure for the duration of a typical sugarcampaign (24 hours per day, 24 hours per day, 4-6 months per year). Inaddition, reservoir testing should demonstrate a reservoir lifetime require­ment of 30 years to match the life of an ammort1zed factory. For considera­tion of a new plant, the reservoir or geothermal well must be located withinor on the perimeter of the beet growing area to accomodate acceptable truckingdistances established by the sugar in~ustry. ERDA activities, such as thosebeing conducted at Raft River and soon to be conducted under the GeothermalLoan Guaranty Program \'lith r1cCullough. Oi 1 must consider the above demons­tration requirements to be applicable to future sugar industry utilization.

11.3 Assurance of Operational Feasibility

Asugar factory must have eqUipment that operates with minimumoperational maintenanceanddownti~e for 24 hours per day, 7 days per weekof a 4to 6 month sugar campaign. Therefore, in considering the adapta­tion ofa geothermal system-to sugar refining, the reliability of theequ1 pment1s of utmos t concern to the industry. Re11abi 11ty concepts wi 11not be accept~d by the industry based solely on engineering feasibili~

stUdies, such as this current study. Therefore, operational field testingof critical hardware is reqUired to demonstrate equipment reliability of

11-3

potential geothenma1 system approaches. To detenmine the impact onequipment cost and economic feasibility, operational field testingmust:

• demonstrate operability throughout the length of atypical sugar campaign with minimum performance degrad­ation due to the geothermal application (i.e., scaling,corrosion).

• establish equipment redundancy requirements to minimizeor eliminate downtime.

• demonstrate technical operability of utilizing low gradegeothenma1 heat for pulp drying and steam generation.

East Mesa is an ideal location for demonstration testing since(1) ERDA has existing facilities for non-e1ectri~ testing, (2) geothenma1fluids at East Mesa are typical for the region in which the Holly SugarBrawley plant is located, and (3) the Brawley plant is in nearbyfor sugar juice or beet pulp demonstration test requirements. Demons­tration testing of prime candidate concepts to satisfy the requirementsidentified above are described in the following sections.

11.3.1 Demonstration Test Experiments

The demonstration equipments and experiments described herein are basedon previously identified technology developments required to resolve engineer­ing and economic uncertainties. Economic feasibility evaluations have in­dicated the requirement for a cascaded boiler to beet pulp dryer retrofitapplication at the Brawley factory using 300°F geothermal brines. The pro­posed experiment is configured with cascaded sub-scale boiler and dryer demon­stration units as indicated schematically in the piping and instrument diagram(P&lD) of Figure 11-1.

11-4

u

........I

V'I

!20!L~12

..AN

DRYER

I·..·..

GEOTl-lE:RM.\L~ REFtlIH6

PftO~E:OT\.IEeMAL f:1:Jf:IZ'V\.lOU.y ~1l!AT"IOJ UU~.C~AlX ~Y:'TE:M ..

(i,821. 2~ -os

FIGURE 11-1

The experiments are designed to be conducted using one of the test \..)stations at the ERDA East Mesa Geothermal Component Test Facility. Theinstrumentation and control spools for brine supply and return and coolingwater supply and return as shown on-Figure 11-1 are as previously designedby TRW under ERDA Contract E (04-3}-1140 for use at this test facility.Additionally the experiment configuration includes a brine cooler to permitbypass control of experiment brine supply inlet temperatures at any temp­eraturefrom 275 to 350 t 5°F.

The demonstration units are to be skid mounted with prefabricatedflanged spools and connections for future testing or commercial use atUnion/Brawley, McCullough/Brawley or Chevron/Heber wells. Additionalequipment requirements, not shown, for remote testing would include a powersupply, instrument air compressor and cooling tower with pump.

The proposed general arrangement of equipment at atypical ERDA EastMesa test station is shown in the test facility plan of Figure 11-2. Boilerand dryer experiments are described in the following sections.

11.3.1.1 Boiler Experiment

The objectives of the boiler experiments are to:

a) Demonstrate the predicted boiler operation with the closetemperature approaches required by the application.

b} Determine length of operating time before performance degradation,due to scaling, requires cleaning. (This information is needed toestablish redundancy and maintenance requirements and operationalcost impacts.)

c} Evaluate chemical cleaning methods. (Minimize maintenance costs.)

d} Determine optimum application tube velocities and minimum impactbrine exit temperatures. (Substantiate the application applicabilityof the EPRI test findings discussed in Sectfon 3.)

The boiler configuration as shown in Figure 11-2 is predicated on theobservation that the sub-scale unit major impact is a function of tube lengthand diameter. Therefore, the test configuration is based on a bundle in- . \..Jc1uding tubes of a length and diameter previously selected for the Holly/Brawley

11-6

(

1(~: LI::J1-r

; .....~ :. ,l_... .J

__~ I

__rt~1.4I>d~"',-LJ I

In. Lri

--I.....

- -4UIIO 'ACtUl'1I:1 DI '.Dn......INTIO...TlOItlMOlltA'""'"

fIGURE 11-2

Ci:~~_"""

.~ I:ll'iMeI "T1!<!oT

eautl"Ml!NT ~DoI'T

-.....-

iIE5r~~~J~ PLA~

f.>(Jf.;.- /.E',iEFr -I jj":""~~". I tcW. ..,,,~ 4'!1oW,~, "4' '~.. , .r':"· ~l.a' ,.' ....... . ~r~rc...~~NQ.. 'iIli!S •

'.1 ~J< J< ~. {/}... "- ~~r-- •••: ...:=.j H Il f-'r--I~ t n ~ ~ ~

f--,!f-- f-;r--

~ ..,- - f-",. -'--- ---L....-..

ERDA. IE5T fACiliTY IUTi=" .. 7~,41 tyAIIotJ LOOI!lllG ::.aUTy

-----

factory retrofit application described in Section 3. As shown the bundleincludes carbon steel tubes of 1 inch diameter, and approximately 40 feetlong.

The boiler test loop as shown in Figure 11-1 includes a closed steamcondensing loop to minimize clean water make-up requirements in the deserttest location.

Equipments and arrangements shown are conceptual only as developed forpreliminary cost estimating and to assist in planning detailed designactivities and test facility implementation.

11.3.1.2 Dryer Experiment

The objectives of the beet pulp dryer experiments are to:

a) Demonstrate the predicted ~ryer capability to dry beet pulp to therequired moisture content using a low temperature heat source.

b) Determine the dryer drum speed, internal design and overall con­figuration required to obtain the required dwell time for low temp­erature drying. (Information required to establish dryer configurationand number required and thus investment cost impact.)

c) Evaluate and establish design requirements for maximizing costeffectiveness of the heat recovery system.

d) Determine length of operating time before coil performance degradation,due to sealing, requires cleaning. (This information is needed toestablish redundancy and maintenance requirements and operationalcost impacts.)

e) Determine optimum heating coil design tube configuration and chemicalcleaning methods (minimize maintenance costs).

The larger configuration as indicated in Figure 11-2 is based on a HeilHodel 5045-12 , three pass drum unit dehydrator modified with a geothermalbrine heating coil and heat recovery system as identified in Section 2 of thisstudy. The arrangement and equipment shown is conceptual only as developed

11-8

u

u

u

for preliminary cost estimating and to assist in planning detailed designactivities and test facility implementation. Extensive internal design (baffling),speed control and other modification detailed designs must be accomplished priorto fabrication for test.

The cascaded geothermal brine feedstock piping to the dryer is configuredwith a controlled by-pass loop to permit test flow variations during tests.Inlet test temperature variations from 275 to 350 + 5°F can be accomplished,with the boiler inoperative, in the manner described in Section 11.3.1.1

The modified test dryer proposed can be utilized for experiments orcommercially with drying other crops, such as alfalfa, after this test programis complete.

'1.3.1.3 Implementation Planning

As previously identified a prime test requirement is the demonstratedoperability of the geothermal application ~hroughout the length ofa typicalsugar campaign with minimum maintenance or downtime. In keeping with thisand the requirement for beet pulp from the Brawley factory for dryer teststhe test planning must be keyed to a sugar campaign at the Holly/Brawleyfactory. As indicated on Figure 11-3 the next sugar campaign will startin April 1978 and run through August 1978. The plan as shown in Figure 11-3indicates that with allowances for procuring long lead ftems coupled withtime required to design the equipments, the test program must be initiatedin June or~July of 1977 in order to be operable during the entire 1978campaign. The alternative is to slip. the test program one year.

Having established the time requirements for demonstrating "assurance ofa operational feasibility" we examined the potential time requirements tosatisfy another sugar manufacturer expressed concern that of "assurance ofreservoir capacity." As shown in Figure 11-4 we have projected credibleestimates of the time required for reservoir evaluations of the McCul10ck andUnion wells in the near vicinity of the Holly/Brawley factory. If the testdemonstration program proceeds as previously described it appears that HollySugar would have sufficient .information to make a decision to proceed, in thefa 11 of 1978, providing reservoi r and equipment tests demonstrated applicability

11-9

FIGURE 11-3

USE OF 0E0T!!!....Ai. H£AT FOR SUGAR REFINING

c'& OFF THE SHELF ITEMS: I'II'ES, VALVES, INITRUlIIENT1

c:

fY1m I fY1m

TAlKS CY1m CY1m

/11ft lIMY .IUN JUL AUG lEI" OCT NOV DeC JAN fO lIAR /11ft IlAY .IUN JUL AUG lEI"

CONTRACt ITUDY

TAlK 11- TUTDE'"TUTPMAIE'I- ADD ON t.!I!M!lL.. ..

PROCURBIEN'r PlCOI

MOUIRIMENTS DEF1NEIIRADE.....DRAt'TING

8'EClPlCAl1ONS

PIIOCtIMIIENY' PlCOI 6

PMMjzr!OCUI!CE!I ICj!O!!I'T!NCtIO

~rROCURElENT

lID

COMTRUC11ONCHEClCOU1'

TUTTEatMOlJUM.AN

'HAIEI

!!!!.TUTDRYI!RI

TUTBOILERTUTMPORT

HOU.Y/!!!AWLEYPLANT OPERATION

..ICING .ETaIUOAR ."NlNO

IJilO" FISCAL

-'-'I-'o

(FIGURE 11-4

Aa:£LERATfD DEVELOPMENT SCHEDULE

GEOTHERMAL APPLICATION TO lIUOAft REFINING

(

--I--

FY1m FY1978 FY1m FY,..

AenYmES CY1I'77 CY1m CYmt CY,..

• 1 2 S • 1 2 S .. 1 2 S • 1 2 S •~. CUftRENT S1UDY I:3! THT PLANNING

II COIffRACT AODON "II,

,

Ii PHAIE 1 DlI!IION

ISl PltAll! 2 PROCURE

as PHAIESTEST

DlYELm'IlIIENT WELLIC2) •-Ii CMC CULLOOHt

I~I

DRAW DNfRECOVERY TUft

Ii DlYEUlNBfTWELLIC4) .., I. CUNIOfI)

DRAW DNlRECOVERY TESTSJ 1/

WELLDUtGN ....~ lITE ""EPAMnON....I a a a a . .

DRlLLWELLIIS I'ROO - .INJEC) • • . . • •

!!DESIGN

iiI'ROCUREMENT

CXINIT'RUCT1ON

.. ! ~RATIOII

tl SLICING BEETS

Ii lIUOAft REFINING

and the sugar market conditions warranted a factory retrofit at Brawley. Adecision to proceed at that time could result in geothermal supplemented energyutilization in the Brawley sugar campaign of 1980. It is noted however thatthe predicted implementation scheduled activities of testing and factoryretrofit are series in nature and this coupled with the seasonal sugarprocessing activity would result in a slip of one year to 1981, if the testprogram is not initiated this summer.

11.4 Recommendations

There is a need for demonstration technology experiments to resolveengineering and economic uncertainties identified in the process conversionanalyses and the expressed concern of industry. The recommended experimentconfiguration is illustrated in Figure 11-2 to conduct experiments aimed atthe following objectives.

(a) Demonstrate the ability of the cascade system to operatereliably on actual geothermal fluids.

(b) Demonstrate operability throughout the length of a typicalsugar campaign with minimum maintenance or perfonnancedegradation due to the geothermal application.

(c) Determine base performance characteristics and establishdesign criteria for varying equipment sizes and flow para­meters .

The specific tasks to accomplish these objectives are as follows:

(a) Design, fabricate and install the cascade test equipments ofFigure 1 at the ERDA East Mesa Geothermal Component TestFacility before the next Brawley sugar campaign; i.e., April,1978.

(b) Perform demonstration experiments during the period Aprilthrough September, 1978, using beet pulp from the Brawleyfacto ry to accomp 11sh the fo 11 owi ng :

(1) Determi ne 1ength of operati ng time of boi 1er and dryerheat exchangers before performance degradation due togeothema1 fluid scaling.

11-12

u

u

(2) Evaluate chemical scale cleaning methods on boilerand dryer heat exchangers.

(3) Determine optimum boiler and dryer tube velocitiesand minimum scale impact brine exit temperatures.

(4) Determine parametric performance characteristics ofthe boiler and dryer for geothermal brine inlet temp­eratures varied from 275 to 350°F.

(5) Demonstrate the predicted boiler operation with theclose temperature approaches required by the appli­cation.

(6) Determine the dryer drum speed, internal drum bafflemodifications and overall configuration required toobtain the required dwell (residence) time for lowtemperature drying.

(7) Evaluate performance and establish design require~

ments for maximizing cost effectiveness of the pulpdryer heat recovery sys tern.

(8) Demonstrate the predicted dryer capability to drybeet pulp to the required moisture content using alow temperature geothermal heat source.

(c) Relocate the skid mounted cascade testequipments of Figure 1 toa potential producing geothermal wellhead (e.g. Union or McCullochWells) near the Brawley factory and repeat the aforementionedtests of (b) above for a period of 2 to 3 months.

11-13

APPENDIX A

GEOTHERMAL BOILER DESIGN STUDY

Southwestern Engineering was contracted for Engineering Service toperform an analysis for a full size steam boiler using geothermal fluid.for the energy source. Southwestern Engineering, a leading manufacturerof heat exchangers, was chosen for their expertise in this field and thetechnical knowledge they could add to the program. Basic criteria estab­lished for the geothermal fluid and steam product together with theresultant dati are included in this appendix.

~1

AttachmentTRW. 1981-JW-7.012March 7. 1917

HEAT EXCHANGER DESIGNENGINEERING SERVICES

Southwest Engineering shall provide engineering services and computertime as required to develop parametric cost and evaluation data for the·following geothermal boiler services:

u

Case I Case 11

300°F 350°F80 PSIA 175 PSIA15 PSI 15 PSIVary VaryTBD TBD

Geothermal (Tube Side)Inlet TemperatureInlet PressurePressure DropOutlet TemperatureFlow Rate (GPM)

Steam (Shell Side)Inlet Condensate TempInlet Condensate PressSteam Outlet TempSteam Outlet PressFlow

250°F25 PSIG +268°F25 PSIG75,000 LB/HR

250°F25 PSIG +268°F25 PSIG75,000 LB/HR

Design optimizations will consider duty effects of the following tube­side fouling factors:

a. Designb. Cleanc. Dirty

= 0.002c 0

= 0.004

Design optimizations will show preference to:

a. Minimizing geothermal fluid flowb. Configurations suitable for periodic tube side

mechanical scale cleaning.

The deliverable data shall consist of graphs, tabulations and sketchesas required to characterize the heat exchangers satisfying the aforementionedrequirements. The parametric performance data shall be quantified in termsof square feet of heat transfer surface or costs.

A-2

SOUII.we...mltlgl....rI...Subsidiary ofTyler Corporation

Geothermal BoUer Design StudyTRW P.O. A75334LBCESEC File 29895 - JOB 5829-04

AttachmentTRW 1981~JW-77.012March 7, 19 7

March 15, 1977

This study was based on the performance conditions specified in TRW letter 1981-JW~7.012dated March 7, 1977.

Sizes and heat transfer surfaces were determined for a number of different brine outlettemperatures and corresponding flow rates for each case, using a fouling factor of 0.002.These designs were accomplished by making a number of computer runs with an arbitrarytube length limitation of 40 feet in order to obtain reasonable length to diameter proportions.Some of the specific results came out with 40 foot tubes and others with 36 foot tubes becauseof velocity limitations as combined with the optimum number of tube passes. The numberof tube passes varied from 1 to 3 depending on brine flow rate. Figure III shows the generolconfiguration and range of sizes of the equipment.

Brine pressure drop ranged from 3 psi to 9 psi, with velocities ranging from 4.3 to 7.4 feetper second. Tube diameter was set at 1 inch 0.0.; however, in any final optimized design,this could be different depending on specific design conditions.

Costs shown are based on the assumption that all material is carbon steel. These costs of course,are approximate but should be within 10 to 15 percent of current actual values.

After determining a number of different size units for each case,. the performance was re­computed for zero and 0.004 fouling factors using the same brine flow rates and sizes aswas determined in the design runs.

Surfaces and costs are plotted In Figures I-A and II-A. Duties are plotted In Figures I..BandII-B for the alternate fouling conditions. Figures I and II are Inter-related, since the same

. flow rates and corresponding surfaces are Involved.

If there are any further questions or if additional data Is desired, please contact Mr. Abe Yardenor Mr. Nate Galnsboro.

Engineering Staff Consultant

NRG/mn

U attachments

A-3

'n-If: INFORMATION DISCLOSED HEREIN INCLUDES I"ROP'RIIE:TARV RIGKTS O~ SOU'nfMSTERNENGINEERING COMPANY. NEITHER THIS DOCUMENT NOR THE INFORMATION DISCLOSED HEREINSHALL 81t REJ>ROC)UCED OR TRANSFERRED TO OTHER C)OCUMENTS OR USED OR DISCLOSED TOOTHERS FOR MANUP'AC'TURING PURPOSES. OR FOR ANY OTHER PURPOSES. EXCEPT AS SPECIFI­CALLY AUTHORIZED IN WRITING BY SOUTHWESTERN ENGINItERING COMPANY.

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APPENDIX B

PULP DRYER THERMODYNAMIC ANALYSIS

A separate analysis was performed to assess the impact on beet-pulp

drying of using heat from a geothermal source. The analysis considered

thermodynamic effects only; no attempt was made to determine the effect

on the quality of the resulting product. The analyses are included in

thi s appendi x.

In order to predict the performance of a low-temperature dryer, it

is necessary to obtain some properties of the pulp in the dryer which arenot avai 1able in the 1i terature. These properties are the heat transfer

between the dryi.ng stream and the pulp (Btu/hr-lb pulp F) and the evapo­

ration rate from the pulp (lb H20/hr-psi-lb pUlp).

Approximate values of these two coefficients were obtained by analyz­

ing present high-temperature dryers and using the -resulting values toanalyze a low-temperature dryer. The effects of temperature on the heat

transfer were predictable and included; however, any effect on the evapo­ration coefficient was not.-

As expected, the results show that a low-temperature dryer, whilecapable of delivering a product with the required moisture content, is much

less effective than a high-temperature dryer. Specifically, for the same

volumetric flow. of the drying stream, the rate of flow of pulp is reduc~c;i

by a ratio of five to six, and the required residence or dwell time of the

pulp in the dryer is increased by a factor of three to five.

These results coincide with dryer manufacturer'sesti.mates of a total

of 16 dryers to replace the existing three fossil-fueled units. In addi­

tion, other modifications could be necessary to retain the pulp in the

dryer for the time r:equiredfor the moisture content to be reduced to the

proper level.

B-1

...-;

77.6~21.5-7.1J

14 !\;:)~1 1977?!\GE 1 iJF 25

013JECTIVE of THE ANAL YSIS

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OIME~SIO~ 1(60C,2)# V(4)# ~!(600), SLtbOC), CB(oO()#STAP.(600)__.._ _.NAr1[ L.IST 1 I tIi Pl,;T 1 K1, K2, K3, ZETA, N . . _ .. . ••._._.

DATA t/18.,2B.,32.,44.1# \12.6111~,36.62~53,7.61862,1.Ob7961

•• Kl a BTU/HP/f/FT, K2 - BTU/HR/F/LBSCl, K3 - LB~OlE H2C/LBSGL/HR/PSI~_tiZ.I:LCr.t 1.1 ICAlS: PC - PS 1, H." r .. . _ ..__ __ .._. ..

DATA Kl,~2,K3/l1q.,ll.,'.4/# PC,TC,lR/32t6.182,70~.3qe,45q.6a&,

• VAPOR P~lSS~R( CUEFfICIENTS t - 0__... ....OAlA. t:,B, C, 0/3.2437 ti 14,3. I: 601444(-3,2.0065 8..0 e.E.~.9,.1_..21.5.4.1.Qll~E.~..3J. ._._•• lElA • (LBMLlt H2C/L~SuL) •• ~

•• FM • L3rl20/LEPULF AT INLfT, R· RESIOlNCE UF SOLID eHOURS)•• Xl_~.LJ.tt<:.T.H.OF. E\lAPOPATO~' (FEET) _._

DATA ZfT~#~/l.5E-7,31, fM,R#Xl/O.e,L.5,50.1·DATA ST1,ST2/1H #lH*1

~_J::I_~'-.t.A.r.E~.T.. hE AT .. C. Uk VE-F IT (B TlJ' LB) ..... __... .__HF,eX)· ~4e5.~6C + 3.~714SEt/tX-2636.0)

• KEENAN A~D KEYES VAPOR PkESSlRE ep~I)

_. t:V_()O..~P_' ..~lC.• ~_"J.J X-.lC) '" (A+~ '" UC-Xl.+C.* (J.C=.XJ.~.! ..3J.LU._._j-_UC-X )*_0) I (X+ZP+ »•• Fl • TEMPERATlJRE DEFE~OE~CE LF LOSS HEAT TRANSfER COEFFICINT

__• *_f.Z __~.. _V.I 5CO.$1' Y.. AND CO~j)UC T1 V1TY. VAR 1ANC E.._.__ .. ...•• F3 • PuLP TfrPEPATUPF PROFILE AT fXIT*. G • REY~OLD~S NUMB~P VA~lAN(E

.f.l q ) ~_.l • 0 . . ... .....FltX). (li 4 .OOO~5*eX+ZR»

F3ix)- (1. - IETA*(S/.)+*~)

__..__..G.(X)- .. (. (~.M (1.> +SVM)/ SVMT ) **0. eOXN - O.lCVlel) - \1(1)

-iQ.C_·_or SP L~Y•.•OI5PLAY+ *DISPLAY" •

_________01 S.p l AY* •KEAO e ~, It\Pl;T)IF(N.LT.O) GO TO 999FUEL • le·2.~4

----f···· '132 ~().', FUf LL(l)· s.f~/el.-FM)/Mel)c

'f'NN

-----".~-

--_._-----_.-

._---------_._-" _._----

.- . . -- ~ _.~_ .._,-_.__.._-_._--_._-----' _-_ -

(

..PI - PARTIAL H20 PRESURE Of GAS STQEA~

S"MT - LB TOTAL GASlL6MOLE fUEL AT INLET

_•.,_~ft.S.._·._.1..B SOLID/lBMOlE FUEL I CFl/HR)MAS- S *~ lXlV(1)- Vl(l)

••Jl-~_...L.altc.LE.S.ll6MClE FUEL • CtNTENT S Of THE. VAPOR_.S.IREA~t __ ... .\IT • "Cl)+\tC2)+VC3)+V(4)TO-TC1,2)-70.

___ .__._T tl,.1)· 1193 ••• H2C -TOlll lehOL~ H20/lBM~l~ FUEL ENT~RING EVAPO~ATCR

H2 C- L'( 1 )+" C1 )• T0 lA1._~.R ~SSl< RE.. I ~ .....l!i .7. PSI.

PT • 14.7•• SV,.. - lB DPY GAS/lBMOlE FuEL,__ .__Sv.f1.._~._ 0. __ .. __...

00 1 1-2,41 SVM·S"~+VCI)*MCI)

___·_.SVt.1.t._~_J'ItlJ*.V C1) _t..SV~.CPS • .40CPW - M(l)*1.0

____.HVQUT~O•.•., .. _' _•.00 4 J·1I4CAll lNT~CJ,TC1,1),H,CP)

..!!_·_._tlVO.UJ_·JlV.ltUT+.VJJ) +H ... _.. __ "'_" ..._... .__._.. ._.OOUT • HVOUT+ (S*CPS + lCl)*CPk)tTCl,Z)

• FINITE SEGM~hl OF OXNlFEE1), PRINT EVE~Y EVEN FOCT CKPP SEG~~NTS).. D.X •. !I J).XN:::'.. _.:.. __ .. ".' _ _ _.•• _._.. __.•••_ _

KPR - INTeI./DX·+ .00tl)SL (,1) -a •

. .o..o_.Z.Q.. Ill.!' bOO '.' ...IF(Sl(!).GT.Xl) GO TO 25SL(!+l)-SLCI)+OX

_____..._.._.P.2._- .. I:"V CT( 1,2» _...•• P2 • VAPCP ~RESSUPE OVER PULf,

Pl • "CU*PTIVT•• D~J(.~.J,.~.~_GlE.P20 I~Q Il esoLlCil f- S1 __- .EVA PClRArJYE.. _~}_SE ._ .._.

OEV ~ K3*F3Cl(1))•• lE~· A~tUNT EVAPORATED OR ClNDENSED__._ LEV. -- . MAS*r.EVIj.:C x* CPz-p 1)

L(I+1) -L(I)-LEV• kATER CONTENTCF THE PULP STR£AM IS NCT PERMITTED BELOW .3 LBMOLE

IFCLC!+1).LT.O.3) GO TO 2~

-.-"'\-':LWA·T{if"LrA~ tNGTHE . PULP ~Ni ERS HlI:'''VAPOFf"STREAMVllI+l) • H20-LlI+l)

(

'"•NW

12

15

c c------------------------------,,_._~,..,-'----------

c (

Tl - NEw VAfOR T~MP~F~TURf

999

_.... ---_._._.._.. _- .....••••E~O SEQLf~CE.

16 TCI+l,t) - Tl___QIN._I1.\· QLU1. ..__.

QOUT·HVG~T + CS*CPS + l(1+1).CPW)*TC!+1,Z)•• C8 - O. ~O~ Mj Ht.AT lGSSt:S CI<I-0.)~_IH.LSU1'.L..a.f..All ClO,. WHEN K.NE.( eI wILL OE: tOlJAl 10 ALL.HEAl LOS.t---.---..-­

QB(l)·CI~-COUT+CE~l-tE~Z

STARCI) • STI__.AJIf:.Ul.l.+.1.,.2) • LT. 'f( 1,2» STt F CI ). STf - ST2

20 CONTINUE2 5 PRINT lOO,Sl C1),08 ( 1), l( n ,. TC 1, Z ),,,1 ( 1), T(.I; 1) , S1 F

____.01 SPl AV.• HVOUT •• , HVllU1, lC 12 (3C(d -*, TC3tiO, 2) ,.-.1....-- .. .__... ....STF-S11OrSPLAY.PRl~T~ I-YES, OaNO*

____.~ACCEP_l ..IP.~J!T ._IFCIP~NT.EQ.O) GO TO 500WRITEC6,lNPUT)

____.00 ..30.. K-1, 1KCK • «K-lJ/KPP) *KPRI~(.N~(KCK.Eo.K-l.0.STAk(~).EO.ST2.C.K.~Q~I) (0 TO 30

__ . WR I.TE J6, 1C(t ) .. Sl ( K), ~ BCK) , l ( K ) , 1 ( "', Z ) , \I .1 (K ) , 1 ( K,1 ) , SlARCI<..L. ._. ...__30 COhl!NU~ .100 FORMAn f7. 2, E12. 4, 2 (flO .4, FO.2) ,A3)

._ ..•_. GO 10. :. 00SlOPl:NO'

."•NU1

_~E.N;...LT.DH ...__.... .....__..... _.. _... _...._. ..- .._--_._-

_.__._ _----------------------

SUBROLTINE ENTHCI,TF,H,CP)*CAlCUlATES ENTHALPY ~ND CP FOR GASEGUS H20,N2,02, A C02, RESPECTIVeLY.

--!.!.DH 0 I·e P F.O ILN.E.W J ON..~RA PHS me r.. QO.T EI ND.l.N G-..... _DIMENSID~ A(4',B(4',CC4'DATA ~/-1.198941E7, -2.b4t50bE7, 1.15722, 1.309921

___....c.ilA 8/-93.2..7.9.• 3., . .'~1307.14. 'u_ .522. 715,_34Z.._~.4bLDATA C/-128.2875, -202.28(5, 457.0~~, 40~.53el

*____T.!--...:·~('-TF..-_'t.5 9. b8 8 L[10 0 •.... .•. _GO TO ( J , 1,3,3) !

1 H • ~(!, + A(l)/CT+CCI»**OHO I • ~ALU..±..c..lLL1+C >J.l00... - - CH-B l/.l.T.+CJJIOO..._.

C~ • L.Ol*(B(I)-H'/(T+C(!)'RETURt-l

3 H • BllJ_t_C..Lll..~..l.~+.Al.LL. __. ._... _.*OHOT • A*c*r**CA-l)/lOO • A*(c*r++A)/T/IOO • A*(H-B)/T/IOO

CP • O.Ol*(H-B(I»+AC!)/T____RETURb

END

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