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Economics

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I

ENERGY CONVERSION AND ECONOMICS FOR GEOTHERMAL POWER GENERATION AT

HEBER, CALIFORNIA, VALLES CALDERA, NEW MEXICO, AND RAFT RIVER, IDAHO - CASE STUDIES

EPRl ER-301 (Research Project 580)

Topical Report 2

November 1976

Prepared by c\g3y I

HO LT/PROCON (A Joint Venture of The Ben Holt Co. and Procon Incorporated)

201 South Lake Avenue Pasadena, California 91 101

\

Principal Investigators Ben Holt

Edward L. Ghormley

Prepared for

Electric Power Research Institute 3412 Hillview Avenue

Palo Alto, California 94304

Project Manager Vase1 W. Roberts

LEGAL NOTICE

This report was prepared by Holt/Procon (a Joint Venture of The Ben Holt Co. & Procon Incorporated) as an account of work sponsored by the Electric Power Research Institute, Inc. (EPRI). Neither EPRI, members of EPRI, Holt/Procon, nor any person acting on behalf of either: (a) makes any warranty or representation, express or implied, with respect to the accuracy, completeness, or usefulness of the information contained in this report, or that the use of any information, apparatus, method, or process disclosed in this report may not infringe privately owned rights; or (b) assumes any liabilities with respect to the use o f , or for damages resulting from the use of, any information, apparatus, method, or process disclosed in this report.

ABSTRACT

This report presents a portion of the resu l t s from a one-year study sponsored by the Electr ic Power Research Ins t i t u t e (EPRI ) t o assess the f eas ib i l i t y of constructing a 25-50 MWe geothermal power plant using low-salinity hydrothermal f luids as the energy source.

The overall objective of the project w a s t o assess the technical, geotechnical, environmental and economic feas ib i l i ty of producing e l ec t r i c i ty from hydrothermal resources l i ke those known t o ex i s t in the United'States. The objective of t h i s report w a s t o investigate the compatibility of the different power conversion options with r ea l geothermal reservoirs and t o analyze the economics of power generation.

Three s e t s of conversion technology are considered fo r the near term: flashed steam, binary, and hybrid (flashed steam/binary). Reservoir and geothermal f lu id characterist ics have a very strong influence on (1) the choice of conversion technology, ( 2 ) performance and l i f e of materials and components, (3) necessary environmental controls, and (4) the ultimate cost of generating power. A l l of these factors are interrelated, and the decision logic fo r optimum choice has not ye t been developed.

This report discusses nine cases which were chosen t o yield further insight in to the e f f ec t of reservoir temperature on the choice of conversion technology and power costs. These cases examine flashed steam, binary cycle and hybrid conversion for Raft River, Idaho; Heber, California; and Valles Caldera, New Mexico tha t have bottom- hole temperatures of approximately 150 C , 180 C and 260 C respectively. Conceptual layouts of the power conversion processes, cycle analyses and economic analyses are presented.

The principal conclusions are: (1) A hydrothermal demonstration plant is technically, environmentally, and economically feasible in the 1980 t i m e frame; (2) The recommended demonstration s i t e i s H e b e r , Imperial Valley, California; (3) Binary cycle power conversion technology is recommended; (41 The recommended demonstration plant capacity is approximately 50 MWe; and (5) There are no overriding environmental constraints.

The following reports from this study are being considered for publication by EPRI :

iii

"Comparison of Hydrothermal Reservoirs in the Western United States

"Reservoir Engineering and Aspects of Geothermal Site Selection at Heber, California and Valles Caldera, New Mexico''

"Energy Conversion and Economics for Geothermal Power Generation at Heber, California; Va l l e s Caldera, New Mexico; and Raft River , Idaho - Case Studies''

"Prel iminary Environmental Assessment of Geothermal Power Generation at Heber , California and Va l l e s Caldera, New Mexico"

"Geotechnical Environmental Aspects of Geothermal Power Generation at Heber , California"

I'Socioeconomic Environmental Aspects of Geothermal Power Generation at Heber , California"

iv

c3 TABLE O F CONTENTS

1.9

S UMMAR Y

Table 1 - Energy Conversion Study

INTRODUCTION

METHOD O F APPROACH

DESIGN CRITERIA

POWER CONVERSION OPTIONS SELECTION O F PLANT SIZE HEAT REJECTION OPTIONS FLASHED STEAM PROCESS THE BINARY PROCESS THE HYBRID PROCESS

Page

1

8

9

11

13 16 18 20 25 27

HEBER CONVERSION PLANTS 28

Drawing No. 7523-D-3204B, Flashed Steam Power P lan t 41 Drawing No. 7523-D-3205A, Binary Power Plant 42 Drawing No. 7523-D-3241A, Binary Power Plant 43 Drawing No. 7523-D-3208B, Hybrid Power Plant 44

VALLES CALDERA CONVERSION P U N T S 45

Drawing No. 7523-D-3203 B, Flashed Steam Power Plant 52 Drawing No. 7523-D-3259A, Binary Power Plant 53 Drawing No. 7523-D-3209C, Hybrid Power Plant 54

RAFT RIVER CONVERSION PLANTS 55

Drawing No. 7523-D-3207B, Flashed Steam Power Plant 60 Drawing No. 7523-D-3255A, Binary Power Plant 61 Drawing No. 7523 -D -3254B, Hybrid Power Plant 62

THERMODYNAMIC BINARY CYCLE ANALYSIS 63

Figure 1 - Simple Binary Cycle Figure 2 - Super-critical Binary Cycle Figure 3 - Subcrit ical Binary Cycle F igure 4 - Compound Binary Cycle

70 71 72 73

V

Table 3 - Case Study Summary, Heber Reservoir 76 Table 4 - Case Study Summary, Valles Caldera Reservoir 77

Table 2 - Computer Sample Printout

Table 5 - Case Study Summary, Raft River Reservoir

ECONOMIC FEASIBILITY

Figure 5 - Estimate Summary, Binary Figure 6 - Estimate Summary, F lash Figure 7 - Estimate Summary, Hybrid Figure 8 - Estimate Summary, Binary, Production &

Injection

Table 6 - Estimated Power Plant and Transmission

Table 7 - Estimated Initial Field Capital Costs Table 8 - Estimated Field Staff Cost Table 9 - Estimated Field Operating and Maintenance

Table 10 - Estimated Power Plant Labor Cost Table 11 - Estimated Plant Operating and Maintenance

Table 12 - Computer Printout - Geothermal Project

Table 13 - Estimated Geothermal Power Cost - Base

Table 14 - Sensitivity Analysis - Geothermal Power

Capital Costs

c o s t

c o s t

Economics

Case

Cost - Basis: Heber Binary

IDENTIFICATION OF TE C HNOL OG Y WEAKNESSES

SELECTION OF THE RESERVOIR

Table 15 - Criter ia for Reservoir Selection

RECOMMENDATION

APPENDIX

78

79

94 95 96 97

98

99 100 101

102 103

104

106

107

108

112

113

114

Figure 9 - Temperature - Enthalpy diagram for Propane -

Figure 10 - Temperature - Enthalpy diagram for Isobutane- Is obutane A- 1

Isopentane A-2

c vi

SUMMARY

SUMMARY O F RECOMMENDATIONS

On the strength of this study, the Heber geothermal field in California i s recommended a s the best site for a low-salinity hydrothermal demonstration plant. power conversion system should be based on the binary cycle, and the capacity of the plant should be in the 50 MWe range.

If a demonstration plant i s constructed, the

SUMMARY O F CONCLUSIONS

1 .

2.

3 .

4.

5.

6 .

It i s feasible to proceed with the design, construction and operation of a 50 MWe hydrothermal power plant with reasonable expectation of success , but not without some technical and economic r i sks . normally take , but i s acceptable as a "fir st-of-a-kind" r e sea rch and development undertaking.

The r isk i s greater than what a utility might

Of the geothermal reservoi rs studied in detail, demonstration plants appear to be technically and environmentally feasible a t Heber, California; Valles Caldera, New Mexico and Raft River , Idaho; and economically feasible at Heber and Valles Caldera.

Heber is the best all-around choice for the demonstration s i te , because the characterist ics of the geothermal fluid contained i n that reservoi r a r e more representative of other hydrothermal resources in the United States.

The binary cycle appears to be the best choice of conversion technology for the demonstration plant, particularly a t Heber , because it has broader application to moderate temperature r e se rvo i r s , 150°C to ZOO'C, and wi l l give utilities at least one option for the development of this resource type after the technology has been demonstrated on a commercial scale .

Optimization studies a r e not yet complete, but it appears that a working fluid mixture , a s opposed to a pure fluid, will be needed to optimize binary cycle operation, with the mix depending upon working tempera tures .

For economic reasons , the capacity of the power plant should be approximately 50 MWe.

1

7.

8.

9.

There appear to be no overriding environmental constraints; however, present data and analytical techniques a r e not adequate to fully evaluate seismicity, subsidence and hydrogeology . The impact in each case i s estimated to be small , and the est imates a r e thought to be conservative.

A commercial size demonstration plant with a r e sea rch and development orientation during the ear ly life of the plant, followed by commercial operation after debugging i s complete, i s needed to resolve the problems of technology adaptation and optimization, heat exchanger and turbine scale -up, mater ia ls , and scale control. It i s also needed to verify reservoi r performance modeling techniques and to study geotechnical environmental aspects of geothermal production . Dry cooling and wet-dry cooling would impose a severe cost penalty i f used .

SUMMARY OF RESULTS

In October 1975, the Electr ic Power Research Institute authorized Holt/Procon to make a feasibility study for a low-salinity hydrothermal demonstration plant. economic and environmental feasibility in the 1980 time f rame and, i f supported by the findings, to recommend a si te for the construction of a 25 MWe to 50 MWe geothermal power plant and a process upon which to base the design.

The objective of the study was to a s s e s s technical,

This study covers the technical and economic feasibility of the power conversion options. Valles Caldera in New Mexico and Heber in the Imperial Valley of California. the demonstration plant s i te , but a s representative of a low- temperature reservoi r .

Attention is focussed on two principal s i tes ,

Raft River , Idaho i s a lso included, not a s a candidate for

This study examines three state-of-the-art power conversion options a t three sites: the flashed s team, binary and hybrid. s team cycle employs two stages of flashing, the s team f rom each stage driving a double entry condensing turbine. closed-loop Rankine cycle using light hydrocarbons a s working fluids. The hybrid cycle i s a combination of the flashed s team and binary cycles .

The flashed

The binary cycle i s a

Three heat rejection options a r e examined: wet cooling, a i r cooling and combination wet-dry cooling. It i s concluded that the latter two a r e not viable alternatives in the near t e r m because the cost of a

G

c 2

power plant per kw increases a t least 50% over the cost of a plant employing wet cooling.

It i s concluded that a 50 MWe plant should be built, justified on the basis that the cost of power f rom a smaller plant would probably not be competitive. The cost of power f rom a 25 MWe plant i s expected to be 20% higher than the cost for a 50 MWe plant, resulting in an uneconomic installation.

The approach in determining technical and economic feasibility was to examine the three conversion options at the three sites (a total of nine cases ) a t a net power output level of 50 MWe, using wet cooling towers. Net power i s the generator output l e s s the parasit ic power required for pumps and cooling towers, but excluding the power required to pump and reinject the geothermal fluids.

Conceptual engineering design work was carr ied out -for each of the nine base cases a s a basis upon which to prepare realist ic es t imates of the capital cost for each case, for the power plant, the field installation and the t ransmission l ines.

In this study detailed capital cost es t imates were prepared for the field plant and t ransmission costs a t Heber. adjusted for the Valles Caldera and Raft River cases to reflect differences i n design and location. operating and maintenance cost es t imates for field, plant and t ransmission l ines.

These est imates were then

This work was followed by the preparation of

The next step in the study was to estimate fuel costs using a cost-of- service approach. estimated a s the sum of fixed charges applied against the initial capital investment plus estimated operating and maintenance expenses.

Power conversion and t ransmission costs were

The summarized resul ts of the foregoing work a r e presented in Table 1. This table se t s forth pertinent design and cost data relating to the r e se rvo i r , the power plant and t ransmission system. est imates per kw and est imates of fuel, conversion and t ransmission costs per kwh a r e presented.

Capital cost

The f i r s t observation is that hybrid plant and power costs do not appear to be competitive and therefore for the sake of simplicity a r e not further discussed in this summary.

Reservoir temperatures va ry f rom a low of 149 C (300 F) a t Raft River to 182 C (360 F) at Heber to a high of 260 C (500 F) a t Valles Caldera. Production well capacity var ies f rom 113,400 kg/hr (250,000 l b s / h r ) a t Valles Caldera to 294,800 kg/hr (650,000 l b s / h r ) at both other s i tes . Reinjection well capacity i s 589,600 kg/hr (1,300,000 l b s / h r ) a t a l l s i tes .

3

Brine flow at the s ta r t is in the range of 1. 2 M kg/hr to 1. 8 M kg/hr ( 2 . 6 to 4 .0 M lbs /h r ) a t Valles Caldera depending upon the process . The flows a t Heber vary f rom 3. 1 M kg/hr to 4 .5 M kg/hr ( 6 . 9 to 10 M lbs /hr ) , while at Raft River the flows vary f rom 5 M kg/hr to 7 . 4 M kg/hr (11. 0 to 16. 3 M lbs /h r ) .

The leas t number of producing and injection wells a r e required at Valles Caldera (13-17), followed by Heber (18-24) and by Raft River (25-37).

Brine consumption is lowest for the binary process a t a l l three r e se rvo i r s . Brine flow is lowest at Valles Caldera, 24 kg/kwh (52 lbs/kwh), increasing to 63. 2 kg/kwh (139 lbs/kwh) at Heber and to 100 kg/kwh (220 lbs/kwh) at Raft River. binary and s team f lash brine consumption increases as the r e se rvo i r temperature decreases .

The difference between

Pa ras i t i c power consumption for thk s team flash cases varies f rom 670 to 12% of net power output a s compared to a range of 27% to 3570 for the binary cycle.

Field development costs for the binary and flashed s team plants (including wells, pumps and surface installations) a r e lowest at Heber ($236 /kw and $287/kw) reflecting the relatively high fluid production p e r well and relatively low well cost. Corresponding costs at Valles Caldera a r e $336/kw and $406/kw and a t Raft River $590/kw and $845/kw. The binary field costs a r e consistently lower than the flashed s team costs.

Power plant costs for the binary and flashed s team plants show little difference at Heber and Valles Caldera, $570/kw and $536/kw a t Heber, compared to $530/kw and $562/kw at Valles Caldera. Caldera the remote location and high altitude resul t in higher costs than would be expected a t a m o r e accessible si te. River a r e significantly higher for both the binary and flashed steam plants, $646/kw and $718/kw, because of the increased s ize of the plant equipment.

At Valles

Plant costs a t Raft

The cost of power delivered to the load center is least for the binary process at all th ree s i tes ; i. e . , 35 mills /kwh at Heber, 34 mills /kwh at Valles Caldera, and 55 mil ls /kwh at Raft River. process power costs exceed these amounts by 3 mi l l s a t Heber, by 5 mills at Valles Caldera and by 15 mills a t Raft River. The higher costs of the flashed s team process a r e due to the higher brine consumption of the process .

The flashed steam

The assumptions made in estimating fuel and power costs a r e :

4

1.

2.

3.

4.

5.

6.

7.

8.

9.

Pro jec t life - 25 years .

DCF ra te of re turn to the producer, based on the cost of field development - 1570.

Depletion (22700) and write-off of intangible drilling costs taken into a ccount.

Royalty. - 12. 570 of fuel cost.

Ad va lorem taxes - 10. 070 of producer 's fuel cost and 2. 570 of utility's capital cost.

Utility re turn on investment - 1270.

Fifty-fifty utility debt/equity ratio.

Utility interest ra te - 970.

Investment tax credit of 1070.

The projected cost of power at Valles Caldera is probably understated because we assumed, lacking specific information to the contrary, that cooling water could be made available at a minimal cost , that the noncondensable content of the reservoi r fluid was nominal, and that the corrosion and scaling character is t ics of the brine' were similar to Heber.

The computer program developed to es t imate the power costs should give good relative values, but the absolute values a r e l e s s prec ise for a number of reasons, the more important being:

1.

2.

3 .

4.

The resu l t s reflect prel iminary but not final optimization.

The p rogram is based on 50 MWe output and does not reflect savings which should resul t f r o m the full development of the reservoi r . Fuel costs a r e based on order-of-magnitude est imates of capital and operating costs.

Fue l costs may vary over a wide spectrum depending upon the assumptions made with regard to treatment of depletion, tax life and write-off of intangible drilling costs. made herein clearly i l lustrate these points.

The sensitivity analyses

5

Near t e r m alternative new power available in the Southwest will probably be based on either coal-fired o r oil-fired power plants and will cost in the range of 30-35 mills/kwh. It appears that a 50 MWe binary cycle plant can be built a t Heber to supply power at a cost within this range.

Thermal efficiencies, i. e. , the ratio of net heat converted to electr icity to heat extracted f r o m the brine, do not vary f r o m case to case nearly as much as br ine consumption. Heber binary to 14. 86'30 for the Valles Caldera flash case. cases the hybrid and f lash processes a r e slightly more efficient than the binary process . at a lower temperature than the f lash process , thereby more than compensating for the loss in efficiency.

The range i s 9.867' for the In al l

However, the binary process re jects spent brine

Technical weaknesses a r e associated with the binary cycle and include the lack of experience in the design and operation of la rge hydrocarbon expanders, problems associated with down-hole pumping which have not been fully resolved, and lack of long-range brine scaling and corrosion data. None of these constraints appear to be of sufficient magnitude to warran t delay of design and construction of the power plant.

The Heber r e se rvo i r meets a l l the c r i te r ia for feasibility. good match for the representat ive low salinity r e se rvo i r as developed in Geonomics' work. for 30 y e a r s o r more. There a r e sufficient data upon which to base reliable es t imates of r e se rvo i r s ize and production character is t ics . The wells a r e productive and relatively inexpensive. been practiced successfully. of the br ine a r e known and neither scaling nor corrosion i s expected to be a ser ious problem. petitive with alternative sources available in the near t e rm. supplies of cooling water a r e available, at leas t for the near t e r m , and there appear to be no overriding environmental o r socioeconomic constraints.

It is a

It is la rge enough to support a 200 MWe operation

Reinjection has The scaling and corrosion charac te r i s t ics

The cost of power is expected to be com- Adequate

By contrast there is very little data available f o r Valles Caldera upon which to base a r e se rvo i r evaluation o r to make reliable es t imates of power cost. There may be environmental problems associated with transmitt ing power over public, private and Indian lands.

Cooling water may not be available except at high cost.

We therefore recommend that the Heber r e se rvo i r be selected as the si te f o r the demonstration plant.

6

The binary cycle plant produces power at a lower cost than the s team f lash cycle at Heber. Moreover, our studies show that the difference increases a s reservoi r temperature decreases . The successful demonstration of a binary cycle process at Heber will be widely applicable to the large medium tempera ture geothermal resource base.

Therefore , we also recommend that the conceptual design studies be based upon the binary cycle ra ther than the flashed s t eam cycle.

7

THE RESERVOIR

R e s e r v o i r T e m p e r a t u r e , "F Produc ing Well Capaci ty , K l b s l h r

No. of Wel ls , S t a r t of P roduc t i on In jec t ion Wel l Capaci ty , K l h s l h r

No. of Wel ls , S t a r t of P roduc t i on P roduc t i on and In jec t ion Wel l Cost . K $ Tota l F i e l d Capi ta l Cos t , M $ O & M Cos t , F i e ld , K $ / y r

THE POWER P L A N T

Wet Bulb T e m p e r a t u r e , "F B r i n e Consumpt ion , M I b s l h r , s t a r t

I b s lkwh B r i n e T e m p e r a t u r e , Out, 'F T h e r m a l E f f i c i ency , 70 G e n e r a t o r Output, kw Pumping Work , kw Cooling T o w e r Work , kw Net P o w e r , kw P l a n t Cost , M $ P l a n t O & M Cost . K $ /y r

TRANSMISSION COST, M $

OVERALL COSTS

F i e l d Development , $ /kw P o w e r P l a n t , $ /kw T r a n s m i s s i o n , $1 kw F u e l C o s t s , m i l l s / k w h P l an t F i x e d C h a r g e s , m i l l s l k w h P l a n t O&M, m i l l s /kwh T r a n s m i s s i o n Cos t , n , i l l s / kwh

TOTAL POWER COST, m i l l s /kwh

BINARY

360 650

12 1 ,300

6 300

11 .8 1 ,973

8 0 6. 942

139 154

11.75 64. 3

9 . 5 4 . 8

50. 0 28. 5 1 , 2 0 0

0. 500

236 570

10 16 .69 15.03 3 .22 0. 28

35 .22

TABLE 1

ENERGY CONVERSION STUDY SUMMARY

HEBER FLASH HYBRID

VALLES CALDERA BINARY FLASH HYBRID

Isopentane

R A F T RIVER FLASH HYBRID BINARY

300 650

19 1.300

9 600

29. 5 2.953

6 5 11 .00

220 145

9. 86 67. 5 15. 9

1. 6 50. 0 32. 3 1 , 331

3 .600

590 646

72 32.80 16.83 3 .57 1.97

55 .17

Note: M = mi l l i ons and K = thousands

INTRODUCTION

This report is one of the documents which has been prepared a s a pa r t of the feasibility study for a low salinity hydrothermal demonstration plant.

P a r t A of the study consists of the assessment of the technical, economic and environmental feasibility of a 25 to 50 MWe plant in the Heber a r e a of the Imperial Valley and the Valles Caldera a r e a of New Mexico, using state-of - the-ar t technology.

Also included in P a r t A i s a paral le l technical and economic (not environmental) study of the Raft River, Idaho, reservoi r , which we have taken to be representative of a low temperature 149 C ( 3 0 0 F ) reservoir . By selecting Raft River a s a representative si te in addition to the other s i tes , we have accomplished another objective: i. e . , the development of the capital and operating costs associated with three different processes at th ree reservoi r temperatures . to be the hottest reservoir : 260 C (500 F), followed by Heber: 182 C (360 F) and then by Raft River: 149 C (300 F).

Valles Caldera is thought

The economic analysis resulting f r o m this work provides insight a s to the relative mer i t s of flashed s team and binary cycles with varying reservoi r temperatures and provides useful information relating power generation costs to reservoi r temperature.

P a r t A (of which this report is a pa r t ) involves the following tasks:

TASK 1 - TECHNICAL FEASIBILITY O F RESERVOIR DEVELOPMENT

This task is being prepared by Geonomics, Inc. and i s the subject of two separate reports submitted by Geonomics, Inc. , entitled "Reservoir Engineering Report - Phase 1" and "Reservoir Engineering Report - Phase II".

TASK 2 - TECHNICAL FEASIBILITY OF THE POWER. CONVERSION PROCESS

The response to this task is contained herein.

9

c TASK 3 - SYSTEM REQUIREMENTS

The response to this task is contained in a separate Holt/Procon repor t entitled "Plant Requirements Manual".

TASK 4 - ECONOMIC FEASIBILITY

The response to this task is contained in this report.

TASK 5 - ENVIRONMENTAL FEASIBILITY

The response to this task is contained in a separate report prepared by Procon (with input by Geonomics, Inc. , entitled "Preliminary Environmental As s e s srnent" .

TASK 6 - RESERVOIR SELECTION

All of the foregoing reports including this one present data which affect the selection of a reservoir . pertinent factors affecting reservoi r selection, together with a recommended reservoi r selection.

This report presents a n analysis of the

TASK 7 - IDENTIFICATION OF TECHNOLOGY WEAKNESSES

The response to this task is contained herein.

The foregoing tasks support the selection of a reservoi r and a process . Once these have been established, Part B - Conceptual Design, may be initiated.

LO

METHODOFAPPROACH

The method of approach in conducting the energy conversion study i s a s follows:

1. Available data were assembled for each site and, when not available, reasonable estimates were made. Such data included:

a.

b.

Reservoir temperature and chemical composition.

Noncondensable content and analysis of reservoi r fluid.

c.

d. Well productivity, depth, spacing and cost.

Corrosion and scaling character is t ics of the reservoi r fluid.

e. Meteorological data, p r imar i ly wet and dry bulb temperature of a i r .

f . P lant location and elevation.

g. Soil conditions.

h. Applicable building codes, including environmental controls.

i. Availability and cost of utilities.

j . Availability and cost of field labor, local building mater ia ls and service .facilities.

k. Character is t ics of power to be produced.

2. The next s tep was to establish three case studies (binary, flashed s team and hybrid) for each of the three s i tes , for a total of nine base cases. Each case was designed for 50 MWe net daily output, excluding field pumping costs (if any) but af ter allowing for paras i t ic power including working fluid pumps, cooling tower pumps and cooling tower fan.

3 . F o r each case, we prepared ' the following documents:

P r o c e s s flow diagram

Piping and instrument diagram

11

Plot plan

Major equipment specifications

Electr ical single-line drawings

This was done both for the field and the plant installations.

4. Vendors' quotations were sought fo r all major equipment. We evaluated the offerings and made equipment selections which were incorporated on the P & I diagrams. The cost quotations were used in estimating.

5. The foregoing documents were turned over to the est imators who prepared installed cost estimates. supplemented by our es t imates of operating costs, were used in the estimate of the cost of power delivered to a load center.

The capital cost es t imates ,

6. Next a computer p rogram was developed, the output of which was the cost of geothermal power delivered to a load center. p rog ram computed the selling pr ice of energy to the utility utilizing the cost-of- service approach in accordance with generally accepted pract ice in the oil industry. The cost of conversion was calculated employing the methods generally used by the investor-owned public utility. The cost of power was estimated for all nine cases , and a sensitivity analysis performed to evaluate the effect of changing key variables.

The

7. The final s tep in the study was to make an evaluation of the technical, economic and environmental fac tors and, based on the evaluation, to recommend a reservoi r s i te and a process .

12

POWER CONVERSION OPTIONS

The conversion of hydrothermal energy f r o m a liquid-dominated geothermal resource into electr ic power can be accomplished by the following methods:

The flashed s team process - in which a pa r t of the geothermal fluid is flashed into s team in one o r more stages. duce electr ic power by means of a turbine and generator.

The s team is used to pro-

The binary process - in which the thermal energy in the brine is t r ans fe r r ed into a pressur ized intermediate fluid, such a s isobutane, which is expanded through a turbine to produce power. then condensed and pumped up to i€s initial p re s su re so that it can be recycled through the system.

The fluid is

The hybrid process - in which a p a r t of the brine i s flashed into s team which is used to drive a s team turbine. The residual heat in the br ine is then t ransfer red to an intermediate fluid which i s used to drive a second turbine using the binary process .

Total flow processes - Several of these processes a r e under development. The common denominator in a l l cases is the concept of expanding the total well fluid through a mechanical device which will convert the thermal and kinetic energy of the well fluid to shaft work.

Several l a rge commercial power plants employing the flashed s team process are in operation, and severa l more a r e under construction in various locations throughout the world, although there a r e none in this country. However, the d ry s t eam plants a t The Geysers in California have been i n operation for years . flashed s team plants include installations in New Zealand, Mexico and Japan.

Notable examples of successful

The foregoing plants employ single entry s t eam turbines. plants under construction, o r beginning operation in Japan, the Philippines, Central Amer ica and Iceland, employ two stages of s team f lash and a double entry s team turbine.

Newer

1 3

c The major technical problems associated with the s team flash process have to do with corrosion and H2S disposal. successfully controlled by providing suitable mater ia ls of construction for the turbines, condensers and related equipment. H2S control has often been a problem because the ea r l i e r plants have used barometr ic condensers ra ther than surface condensers. In the fo rmer case much of the H2S is absorbed in the cooling water and released to the atmosphere in the cooling tower. be achieved by using surface condensers, in which case the H2S appears i n the discharge gases f r o m the vacuumpumps andmaybe removed com- pletely by established technology.

Corrosion has been

However, complete control of the H2S may

There seems to be no significant technical r i sk involved in designing a flashed steam plant, and we consider the flashed s team process to be a proven one.

There is nothing new in the concept of employing an organic fluid in a closed Rankine cycle. Over 1 ,000 so-called "naphtha launches" were built in the late 19th and ear ly 20th centuries using petroleum naphthas as a working fluid. The R.ussians a re reported to have a small 750 kw geothermal unit in operation employing F reon a s a working fluid. Japan a plant has been in operation since 1967, recovering waste heat f r o m a petrochemical plant and generating 3 . 8 MW of shaft work by expanding Freon in a radial inflow turbine. t e s t loop will soon be in operation in the Imperial Valley.

In

A nominal 10 MW isobutane

Hydrocarbon expansion turbines up to 10,000 hp have been in successful operation worldwide, and there appear to be no serious technical nor economic limitations on building expansion turbines up to 70 MWe using either a radial inflow design o r an axial flow design. The r e s t of the major equipment, consisting of heat exchangers, condensers, p r e s s u r e vesse ls and cooling towers, a r e of conventional design and may be purchased on a guaranteed performance basis f r o m established venders.

We consider the binary cycle process to be state-of-the-art , although there a r e cer ta in technical weaknesses which should be addressed (see section in this repor t entitled !'Technical Weaknesses").

The hybrid cycle i s simply a combination of s team f lash and binary, and therefore is a lso state-of-the-art.

The total flow options a r e in various stages of development, largely supported by ERDA. chances of success. candidates (Lawrence Livermor e Laboratory' s turbine, Sprankel' s

We express no opinion a s to their ultimate However, it is c lear that each of the popular

14

expander and others) require the pract ical solution to many difficult problems associated with scaling, corrosion and erosion of metal par t s . a r e likely to be ready for commercialization within the next two years .

Clearly, none of the total flow options a r e state-of-the-art o r

A modification of the binary p rocess . in which a direct-contact exchanger i s substituted for the tubular exchanger is under development by several firms including The Ben Holt Go. eliminating the problem of scale buildup on tubular exchangers and in reducing capital cost by substituting a relatively inexpensive direct- contact exchanger for the tubular exchanger. and economic feasibility will be demonstrated within the next two years .

This modification shows promise in

We expect that technical

Another modification of the binary process is incorporated in the design of the Niland Test Facility. Scaling of the heat exchangers is minimized by flashing the br ine at four successively lower p re s su res , scrubbing the particulates f r o m the flashed s team and heating the isobutane working fluid by condensing the f lash s team in tubular exchangers. The m e r i t s of this scheme are planned for demonstration by the end of 1976.

We have l imited our studies in this repor t to the state-of-the-art options.

SELECTION OF PLANT SIZE f-

It is c lear that geothermal power plants come in relatively small s izes a s compared with fossi l fuel o r nuclear plants. instance, a module is 110 MWe and a t Ce r ro Pr ie to the init ial installation is 75 MWe (two 37.5 MWe steam turbines). this is an economic one. collection and reinjection of the fluids increases as more wells (both production and reinjection) a r e required. energy losses become greater.

At The Geysers, for

The main reason for A s single plants get la rger , the cost of

Also the fluid t ransmission

Another reason is a technical/economic one. F o r example, no hydrocarbon expansion turbines have been built even in the 60-70 MWe range, although there appear to be no serious technical problems associated with scaling up existing designs. O r f o r that mat ter , i f capacity should really turn out to be a limiting factor, multiple units may be installed on a common shaft a t some economic penalty.

In either the 25 MWe o r 50 MWe sizes of a binary cycle plant, we a r e already dealing with multiple units of major equipment. F o r example, the preliminary equipment selection at Heber provides for eight hot water/working fluid exchanger bundles, eight condenser bundles, eight hydrocarbon pumps, three cooling water pumps and 10 to 12 cells in the cooling tower. A 25 MWe unit would have about one-half of the number of these units. Since individual exchangers, condensers, pumps and cooling tower cel ls a re already as la rge a s a r e readily available commercially, there is no advantage in t e r m s of demon- strating technical and operational feasibility by building a plant la rger than 25 MWe. Since we a r e a lso dealing with multiple wells, both production and injection, the same argument holds t rue for the field installation.

Moreover, f r o m a technical and operational standpoint, there is little justification for building, say, a 60 MWe expansion turbine instead of a 30 MWe turbine. Once successful demonstration of a 30 MWe turbine has been demonstrated, scaling f r o m this s ize up by a factor of two should be no problem.

Finally, a lot l e s s money would be required to build the smal le r plant (in the range of 60 to 70 percent of the cost of the l a rge r plant), a saving in the case of Heber of eight to ten million dollars.

It appears that the decision should r e s t on economic factors. al l , a major objective of the program is to demonstrate economic

First of

16

viability of power production f r o m low salinity medium temperature hot water reservoi rs . Moreover, i f the demonstration plant could not generate electricity economically, there would be little incentive to keep it operating beyond a reasonable tes t period without subsidizing the operation. By contrast , an economic operation would be self supporting, would provide real is t ic cost data and would encourage rapid development, not only of the reservoi r on which the plant is located but a lso other reservoi rs .

Based on data presented in our economic analysis, we have estimated the cost of power f rom a 25 MWe binary plant a t Heber as compared to a 50 MWe plant. is about 35.2 mills/kwh. 42 .3 mills/kwh, an increase of about 2070. making this calculation a r e a s follows:

Our base case est imate fo r the cost of power a t Heber The corresponding figure for 25 MWe is

The assumptions used in

1.

2.

3.

4.

5.

6 .

7.

8.

9.

10.

Power plant capital cost is 61% of a 50 MWe plant.

Power plant labor is constant.

Power plant maintenance i s proportional to capital.

Power plant, water, chemicals and miscellaneous costs a r e proportional to capital.

Transmission costs a r e constant.

One-half as many wells a r e drilled.

Surface installation is 6Oy0 of a 50 MWe estimate.

Field labor cost is constant.

Well maintenance is proportional to number of wells.

Field maintenance is proportional to capital.

F r o m the foregoing, it is apparent that there i s a strong economic incentive to build a 50 MWe unit. Moreover, the l a rge r unit will also m o r e nearly comply with the objective of providing the utility industry with reliable economic data. F o r these reasons, we selected a 50 MWe plant a s the prefer red size.

17

HEAT REJECTION OPTIONS

Heat rejection pe r kwh f r o m a geothermal power plant is higher than that f rom a fossil fuel o r nuclear power plant because the thermal efficiency i s lower. F o r example, the thermal efficiency of the Heber binary cycle plant is about 1370, a s compared with a typical fossi l fuel plant of 347'0, and heat rejection per kwh from the geothermal unit i s about 3.44 t imes that of the fossil fueled plant. apparent that the method and cost of heat rejection is relatively a m o r e important consideration in the design of geothermal power plants than in either fossi l fueled or nuclear plants. Moreover, because the heat source is itself a t a low temperature, the efficiency is very sensitive to the heat rejection temperature. In the range of temperature of interest , the net work produced is roughly proportional to the temperature difference between the heat source and the heat sink. There a r e three proven heat rejection options available: w e t cooling, a i r cooling and a combination.

Thus, it becomes

Typically, wet cooling towers can reduce the temperature of the recirculated cooling water to within 6 C (10 F) of the prevailing wet bulb temperature, which is typically a t l eas t 11 C ( 2 0 F) l e s s than the prevailing dry bulb temperature.

Dry cooling systems for heat rejection use finned heat exchanger tubes to t ransfer the heat f rom the process fluid to the atmosphere. The minimum temperature at which these systems can dissipate heat is typically 14 C (25 F) higher than the dry bulb temperature of the a i r .

The third combination system is known as the wet-dry cooling system. As in the air-cooled system, the process s t r eam is cooled by the passage of a i r through banks of extended surface exchanger tubes, As required, water is sprayed into the a i r flow, cooling the a i r flow by evaporation of the water to a temperature approaching the wet bulb temperature. cooling water is a t a premium and where dry-bulb temperatures a r e excessive. ment s.

This type of unit is expensive and is usually used when

Northern Africa and the Middle East provide such environ-

Let us first consider a binary plant a t Heber. cooled system for 40 C (105 F) dry-bulb which would allow a 54 C (130 F) condensing temperature, a s compared to a wet-bulb temperature of 27 C (80 F) and a condensing temperature of 43 C (110 F) fo r a wet tower. The installed cost of the wet tower, including pumps and condenser, is about $4, 000, 000, a s compared to the installed cost of a d ry tower of

We might design an a i r -

18

about $13, 000,000. parasi t ic power requirements increase about 5 MWe. given plant size, power output is reduced about 20% and costs increased about 20oJ0. Thus, if the plant costs $500/kw with wet cooling, it will cost a t least $750/kw with dry cooling.

The loss in cycle efficiency is about lo%, and the Thus, fo r a

The net effect is a 50% increase in the unit cost per kwh.

A similar analysis was made for a flashed s team system. a circulating water system is required to t ransfer heat f rom the condenser to the a i r cooler. The numbers come out about the same - - a reduction in cycle efficiency, an increase in parasi t ic power consumption and a sharp increase in installed cost pe r kw.

In this case,

We did not continue our analysis fur ther because it appears obvious that air cooling is not a viable alternative to wet cooling, and neither a r e combination coolers since they a r e even more costly than a i r coolers. Moreover, we suspect that a definitive study would show an even grea te r cost increase.

There i s one alternative which we did not examine because of t ime limitations. temperatures a r e low. say, 28 C (50 F) and then examine the daily and seasonal variations in power output which might result. output would be grea te r than design and during the summer months l e s s than design.

At Valles Caldera, for example, for much of the year a i r One might design for an a i r temperature of,

During the winter months, power

The overall resul t might not be too bad.

19

FLASHED STEAM PROCESS

GENERAL

Three factors strongly affect the process design of flashed s team geothermal plants. They a r e a s follows:

1. The temperature and composition of the geothermal brine.

2. The charac te r i s t ics of the available heat sink.

3 . The s ize and the charac te r i s t ics of the turbines available for use with geothermal steam.

The initial temperature of the r e se rvo i r fluid determines both the quantity of s team which can be flashed f r o m it and the temperature of the resulting steam. flashed. Our flash calculations are done with a computer program which takes this effect into account. Of the three geothermal fields under consideration in this report , the most concentrated brine exis ts a t Heber, about 15,000 par t s p e r million. f lash is reduced approximately 39'0 by the dissolved solids.

Dissolved solids a lso affect the amount of s team

In this case, the s team

It is ususally pract ical to f lash the reduced liquid a second time, using the secondary s team in lower stages of the turbine. i s possible to flash the br ine an infinite number of t imes extracting m o r e energy each t ime this is done. appear to be impractical .

Theoretically, it

However, more than two stages

A prel iminary analysis was made of a t r iple-f lash sys tem ve r sus dual f lash for Valles Caldera conditions, based on three-inch Hg back p res su re . machine (two separate casings) with a t least s ix admission valves. dual f lash required a two-flow machine (single casing) with only two admission valves. in favor of dual flash, plus additional savings on the turbine pedestal and the heat rejection equipment.

The slightly more efficient tr iple f lash required a four-flow The

Turbine-cost differential would be about $4,000,000

HEAT REJECTION

Plants with a low initial s team tempera ture a r e very sensitive to the condensing p r e s s u r e of the steam. tower s ize to provide a cold water temperature within ten degrees of

We have estimated the cooling

20

the design wet bulb tempera ture in each area. The overall efficiency of the plant is significantly improved if the temperature of the cooling water is low.

In a l l cases we have assumed that adequate makeup water will be available to permi t the operation of wet cooling towers. The flashed s team plant produces adequate quantities of condensate which can be used f o r cooling tower makeup water. this condensate i s a valuable commodity which would permi t a flashed s team plant to operate where other types of plants could not.

Where water supplies a r e short,

STEAM TURBINES

A survey was made of four domestic and two Japanese companies thought capable of providing turbines for this service. companies only one, General Elec t r ic Company, expressed in te res t i n producing geothermal steam turbines in the 25-50 MWe range. Of the two Japanese companies, Mitsubishi and Kawasaki, the long l ines of communications to their engineering departments made it impract ical t o c a r r y out a cooperative study. were conducted maingly with the General Elec t r ic Company.

Of the domestic

Accordingly, our turbine studies

Geothermal turbines operate under different conditions f r o m conventional power plant turbines. indicates that deposits f o r m on the turbine buckets, subjecting the machines to more vibration than those in conventional service. Accordingly, General Elec t r ic uses extra rigid buckets which a r e not available in a l l s izes , the two l a rges t being 42.7 cm (16. 8") and 50. 8 c m (20") long. These blade lengths determine the annular opening of the last stage, which in tu rn determines the maximum s team flow per case. A s sonic velocity cannot be exceeded in the last-stage buckets, the steam flow in pounds pe r hour is a function, not only of the annular a r ea , but a l so of the condensing pressure . Accordingly, turbines for the flashed s team process a r e available only in d iscre te s izes .

Experience with The Geysers geothermal plants

Another turbine generator charac te r i s t ic which en ters into the process design is overal l efficiency. generator output to the heat energy theoretically available. F o r initial s t eam conditions above 310 kPa (45 psia) , overal l efficiency is about 7070. Below 310 kPa (45 psia) , the efficiency falls off progressively t o about 6370 a t 110 kPa (16 psia).

This i s calculated as the ratio of the

PROCESS F L O W

The first s tep in the design was to per form a se r i e s of two-step direct f lash calculations for each of the br ines under consideration. These

21

were done at a number of p r imary and secondary s team p res su res chosen in relation to the init ial brine temperature , ma t r ix giving the amount of p r imary and the amount of secondary s team produced a t each combination of first and second-stage p res su res .

The resul t was a

The second step was to calculate the approximate s team flows to produce 55 MWe g ross f r o m each of the s team flash calculations derived above. s team ra t e s f o r each expansion f r o m a range of initial s team conditions to several condensing p res su res .

This was done by first calculating the theoretical

These were converted to "actual" s team ra tes by dividing them by estimated turbine efficiencies. It then possible to calculate for each initial and final condition, the p r imary and secondary s team flows f r o m 1000 pounds of brine and resultant e lectr ical gene ration.

Finally, by dividing 55 MWe by this l a s t figure, we obtain a factor both br ine and s team flows.

was

the

for

F o r each plant, this calculation was performed in tabular form f o r a l a rge ma t r ix of p r imary s team, secondary s team and condensing p r e s su re s.

TURBINE SELECTION

Using the prel iminary calculations a s a guide, GE turbine specialists selected for each case a number of operating conditions which appeared most favorable. which p r i ces were then developed.

F o r each of these they made turbine selections for

The p r i ces for these prel iminary selections were then evaluated in relation to reference br ine costs and probable condenser and cooling tower costs. The resu l t s , while not r igorous, enabled us to make a fa i r ly optimum selection in each case.

These selections were then recalculated by GE using more refined methods. Actual bucket selections were made and efficiencies calculated for stage-to-stage expansion. case a good turbine selection with fai r ly accurate es t imates of both s team flows and heat rejection.

F r o m this we obtained for each

CONDENSERS

Once turbine configuration and exhaust s team flows were established, it was possible to investigate condenser and cooling tower possibilities.

2 2

This was done with the cooperation of the Ingersoll-R.and Company which has furnished most of the s team condensers a t The Geysers plant.

Before prel iminary condenser designs could begin, however, some initial decisions had to be made, par t icular ly with respec t to mater ia l s . Because of the expected CO, and H2S content of the candidate br ines and in deference to experience at The Geysers, the following selections were made for a l l cases:

Shell

Non-welded inte rnals Type 316

Welded internals Type 316 L

Tube sheets

Tubes Type 316

Type 3 16 L clad

Type 316 clad on s team side only

The designers were given the option of tube diameters f r o m 14 mm (3/4”) to 25 .4 mm (1”) with a tube wall thickness of 0. 7 mm (22 BWG). F o r stainless tubes of these dimensions, water velocities of seven to nine feet p e r second are usually used in public utility power plants. We selected an average value of eight feet pe r second. Assuming that a n Amertap continuous mechanical cleaning system would be used with the cooling water, a condenser cleanliness factor of 0.85 was used for a l l cases.

A cold-water temperature compatible with the heat- sink character is t ics was established. respec t to the r i s e and allowed to use average public utility c r i te r ia for the cost of cooling tower installation and operation. The resul t in each case was reasonable condenser selection, ra ther than an optimized one.

The condenser designer was given latitude with

COOLING TOWERS

Wood cooling towers of public utility quality were specified for a l l sites. Cooling-water flow, cold-water temperature and range were determined by condenser selection.

VACUUM PUMPS

Because of the gas content anticipated for each of the candidate br ines , the removal of noncondensable gases f r o m the condensers i s a task in

2 3

orde r of magnitude l a rge r than in conventional public utility power plants. Fur ther , the poor init ial s team conditions make s team j e t e jectors uneconomical in these applications. Vacuum pumps were sized to accommodate the expected gas flow f r o m the brine plus the amount of a i r normally accumulated through leakage. Where cold water temperatures a r e sufficiently low, the use of pre-condensers was investigated.

2 4

THE BINARY PROCESS

GENERAL PROCESS DESCR.IPTION

The binary process for producing electr ic energy f r o m geothermal r e se rvo i r fluid involves the t ransfer of heat to a secondary, in-plant working fluid. produce power. shell and tube condensers.

The working fluid is expanded through a turbine to The expanded gas is then condensed in a battery of

The working fluid is continually recirculated f rom the turbine to the heat source. and tube exchangers a t an elevated pressure . fluid flows f r o m the production wells through the tubes. f e r r e d f r o m the reservoi r fluid to the working fluid. e i ther in the subcrit ical o r super-cr i t ical region. fluid is pumped f rom the plant to injection wells.

The fluid is pumped to the shell side of a bat tery of shell Hydrothermal reservoi r

Heat is t r ans - Operation may be

The spent reservoi r

CONVERSION STUDY BASIS

The bas is used in developing the binary process design for the three plant s i tes is defined below:

1.

2.

3.

4.

5.

6.

Each plant i s sized for a net output of 50 MWe. be sized with sufficient capacity to provide for in-plant e lectr ic power consumption.

The generator will

Hydrocarbon turbine- expander efficiency and generator efficiency a r e assumed to be 857'0 and 9870, respectively. working fluid circulation pump i s assumed to be 80%.

Efficiency of the

P r e s s u r e drop a c r o s s the operating f lu id / reservoi r fluid heat exchangers and hydrocarbon condensers is assumed to be 345 kPa (50 psi) and 21 kPa ( 3 psi) respectively.

Design values of the wet bulb and dry bulb temperatures a r e based on temperatures which occur 1% of the t ime during the summer months.

Operating fluid p r e s s u r e s a r e to be grea te r than atmospheric p re s su re to avoid air leakage into the process system.

The minimum temperature difference between operating fluid and r e se rvo i r fluid in the heat exchangers will be 8 C (15 F).

2 5

The p r imary purpose of the above conditions and assumptions was to establish a uniform base of comparison fo r all three plant si tes.

Selection of the operating fluid and operating conditions was de te r - mined for each s i te by a computer program, evaluating the thermodynamic propert ies of various systems. mize the reservoi r fluid flow requirements.

The emphasis was to mini-

SELECTION O F WORKING FLUID

Light aliphatic hydrocarbons (such a s propane, isobutane and isopentane) appear to be the bes t candidate working fluids for most geothermal applications. propert ies , a r e thermally stable, noncorrosive, and available in la rge quantities at reasonable pr ices (about 50 cents/gallon).

They have favorable thermodynamic

The Freons may also be used. thermodynamic propert ies , a r e expensive (about $5/gallon), and a r e thermally unstable. f lammable .

However, they offer no advantage in

Their only advantage is that they are non-

A number of other candidate fluids have been suggested, including all of the obvious gases such a s ammonia, sulfur dioxide, carbon dioxide and light aliphatic olefins. light aliphatic hydrocarbons.

None appear to offer advantages over the

Another virtue of the aliphatics is that their thermodynamic and physical propert ies a r e very well known, and their propert ies may be a c cur ate ly predicted.

Accordingly, we have limited our studies in this repor t to the use of light hydrocarbons and have tailored the fluid composition to the r e s e rvoi r .

2 6

THE HYBRID PROCESS

GENERAL

A hybrid power plant is a combination of two processes , the flashed s team process and the binary power cycle process. flashed to produce s team a t a relatively high pressure , which is used to drive a turbine-generator. the working fluid which drives a second turbine-generator.

Reservoir fluid is

The reservoi r fluid is then used to heat

THE FLASHED STEAM SECTION

The design of a hybrid plant s t a r t s with fixing the p re s su re a t which the s team i s flashed f rom the reservoi r fluid. desirable because the high p res su re will improve turbine efficiency and reduce the turbine size and cost. The p res su re that is chosen affects the relative s izes of the two par t s of the plant, a s well a s the quantity of reservoi r fluid required by the plant. different steam-flash p res su res were investigated to determine the most efficient generating condition for the plant.

High p res su re s team i s

F o r each plant, several

THE BINARY SECTION

The flashing of the s team f r o m the reservoi r fluid resul ts in cooling the fluid. the reservoi r fluid. Because the high temperature enthalpy in the brine was used to produce steam, the binary portion of the plant must have a lower thermodynamic efficiency than a binary plant which recovers all of the enthalpy f r o m the brine.

The binary portion of the plant must utilize the residual heat in

Each section of the plant i s calculated by making an enthalpy balance on the reservoi r fluid at the s team flash drum and sizing the individual portions of the plant based on the energy available for conversion into electr ic power.

It was assumed that minimum brine consumption, consistent with low hydrocarbon circulation represented the most economical operating condition for the plant. F o r each s team flash p res su re that was considered, the quantity of reservoi r fluid and the rate of hydrocarbon circulation were calculated. The relative s izes of the s team flash section and the binary section of the plant were established a t the condition where both flow ra tes were minimized.

27

HEBER CONVERSION PLANTS

Detailed data relative to the s i te , the geology, the reservoi r , the environment, plant facilities and field facilities a r e contained in companion volumes. of this section and succeeding sections a r e repeated in this volume.

Only the data necessary to fulfill the objectives

THE RESERVOIR

/-

The Heber geothermal reservoir i s located in the southern part of the Imperial Valley a t an elevation that i s close to sea level.

Summertime temperatures vary up to 49 C (120 F); one percent of the time during the s u m e r months, the wet bulb temperature reaches or exceeds 2 7 C (80 F). This wet bulb temperature was used for design.

The a rea i s level and devoted mainly to agriculture. bounded by i r r igat ion ditches which will supply makeup water to the plant.

The plant site i s

Roads and power lines a r e close to the s i te .

The reservoi r fluid has a total dissolved solids content of 15,000 ppm. The bottom hole temperature i s 182 C (360 F). i f there i s no heat recharge, the temperature of the reservoi r will decline about 20 C (35 F) over a 25-year period a t a sustained production ra te of 200 MWe. This temperature drop of the reservoi r fluid necessi ta tes a plant design in which the circulating systems in the plant can be expanded to maintain a constant power production r a t e .

Analysis indicates that

Thus f a r , minimal quantities of noncondensable gases have been observed in the reservoi r fluid. Analyses that were performed on the reservoir fluids did not ascer ta in i f noncondensable gases were present . For the purpose of this study we estimated that the noncondensable gases would consist of 680 kg/hr (1500 l b s / h r ) of carbon dioxide. Hydrogen sulfide was assumed to be present in the gas in the range of 100 to 1000 ppm.

The EPRI-sponsored heat exchanger tes ts showed that the salts present in the fluid fo rm scale a t a negligible ra te a t temperatures above 132 C (270 F) but below that temperature fouling occurs a t an increased ra te . F r o m their data we estimated the following tube-side fouling factors which were used in the design of brine/working fluid heat exchangers:

28

Temperature , C Temperature , F Fouling Fac tor

176 to 132 350 to 270 . O O O l 132 to 80 270 to 176 . O O l l 80 to 65 176 to 148 .0033

These fac tors a r e tentative in that the resul ts of a 22-day tes t have been extrapolated to predict a fouling factor suitable for one yea r ' s operation. months to confirm these figures.

Fur ther tes ts should be conducted over a period of several

The exchanger t e s t s were conducted using titanium, 90% cupro nickel and mild s tee l exchanger tubes. titanium tubes af ter 560 hours ' exposure; some corrosion occurred to the cupro nickel tubes af ter 200 hours ' testing; and slight pitting and surface decarbonization were observed on the carbon s teel tubes af ter 560 hours of testing. tubes had occurred pr ior to the t e s t program. that corrosion during their tes t work was negligible. Accordingly, we have specified the use of s tee l in all equipment exposed to brine o r flashed s team, except s team turbines and surface condensers a s noted in the previous section. Fur ther corrosion tes t s with the Heber brine should be conducted before a final decision is made on plant materials.

No corrosion was observed on the

It is possible that the slight corrosion of the s teel Chevron has indicated

FLASHED STEAM P U N T

A process flow sheet of the flashed s team plant is shown in drawing number 7523-D-3204.

The hot reservoi r fluid en ters the plant a t a flow ra te of 4.54 M kg/hr (10. 01 M lbs /hr ) . through the control valves into two f lash drums at an absolute p r e s s u r e of 374 kPa (54.3 psia).

Split into two parallel trains, the brine passes

The first stage f lash produces 392,000 kg/hr (864, 000 lbs /h r ) of p r imary s t eam which passes through a s team separator before reaching the turbine at a p re s su re of 370 kPa (53.7 psia) and a temperature of 141 C (286 F).

The liquid f r o m the f i rs t -s tage f lash drums flows to the second-stage f lash drums where its p re s su re is reduced to 151 kPa (21 .9 psia). resultant f lash produces 263,000 kg/hr (580, 000 lbs /h r ) of secondary s team which flashes through a s team separator to a lower stage of the turbine at a p r e s s u r e of 150 kPa (21. 7 psia) and a temperature of 112 C (233 F).

The

29

The secondary f lash drums float on the line, their p re s su re varying with turbine- stage p r e s s u r e and with demand.

The flashed liquid flows f r o m the second-stage f lash drums to the suction of the injection pumps which re turn the liquid to the reservoi r . Liquid level is maintained in the second-stage flash drums by a control valve on the pump discharge.

The turbine-.generator is operated as a base-load unit under load control. The operator ass igns a load to the generator, and the turbine must accept that load a t constant speed. detects changes in load and adjusts admission valves on both the p r imary and secondary s team l ines to satisfy the assignment. separate emergency t r i p mechanism on the turbine shaft will close emergency stop valves on both p r imary and secondary s team lines i f turbine speed exceeds 3 ,600 r p m by a given percentage.

The turbine governor

A

Exhaust s team f r o m the turbine pas ses directly into a surface condenser, where a back p res su re of 13.5 kPa (4 in. Hg) is obtained under design cooling-water conditions. the injection pumps. make the replenishment volume substantially equal to the volume of f r e s h br ine delivered to the plant. 103 C (217 F).

The condensate is pumped to the suction of The condensate is added to the reduced brine to

Average temperature of this flow is

Cooling water f r o m an induced draft cooling tower en ters the condenser at 35 C (95 F) and re turns to the tower at 49 C (120 F). The hot cooling water temperature gives a minimum condenser approach of 2.7 C (5 F).

During the turbine selection process , other combinations of p r imary and secondary s team p r e s s u r e s were tr ied, but were l e s s attractive economically. generated. require a four-flow turbine with two casings and a jump in turbine cost alone of about $3,000,000. duction (about 3.570) would not justify the increased capital expense. The p r imary and secondary s team conditions selected give the grea tes t power output possible f r o m General Elec t r ic ' s l a rges t double-flow, single-case turbine with a four-inch back pressure .

Higher p r e s s u r e s used m o r e brine p e r kilowatt of power Lower p r e s s u r e s increased exhaust s t eam flow enough to

The contemplated reduction in brine pro-

Noncondensable gases and a i r leakage a r e removed f rom the sys tem by six la rge vacuum pumps operating in parallel . The gases a r e discharged to a stack which is designed fo r dispersal of the hydrogen sulfide present.

30

A summary of pertinent design data is as follows:

Reservoir fluid Generator output 55.0 MWe

Pumping work 3.2 MWe

Cooling tower work 1.1 MWe

Net output 50.7 MWe

Reservoir fluid/net kwh

4.54 M kg/hr (10.01 M l b s / h r )

90 kg (200 lbs )

When r e se rvo i r temperatures deciine with depletion, initial e lectr ical output can be maintained by increasing hot water flow.

Theoretically, a plant designed for the depletion condition of 163 C (325 F) would require 37% more hot water than one designed for the init ial condition. (325 F) hot water would require a l tered s team conditions to maintain proportional flows through the turbine stages. 63% increased flow of hot water. a r e compared below:

However, operation of the base-case plant with 163 C

This would resu l t in a Initial and final operating conditions

Initial Final

Reservoir Fluid 4.54 M kg/hr (10. 01 M lbs /h r )

7.39 M kg/hr (16.3 M l b s / h r )

370.2 kPa (53. 7 psia)

P r i m a r y f lash p r e s s u r e 317.8 kPa (46. 1 psia)

P r i m a r y steam flow

Secondary f lash p r e s s u r e

Secondary s team flow

Spent water temperature

392 M kg/hr 386 M kg/hr (864 M l b s / h r ) (852 M lbs /h r )

149.6 kPa 165.5 kPa (21.7 psia) (24. 0 psia)

655 M kg/hr 666 M kg/hr (1444 M l b s / h r ) (1468 M l b s / h r )

103 c (217 F) 109 C (228 F)

31

BINARY PLANT G A process flow sheet of the binary plant is shown on drawing number 7523-D-3205. for the initial reservoi r conditions.

This flow sheet presents the heat and mater ia l balances

Liquid isobutane is preheated and vaporized by exchange with the brine to a p re s su re of 4137 kPa (600 psia) and a temperature of 149 C (300 F). The super- cr i t ical vapor dr ives an expansion turbine. vapor f r o m the turbine condenser flows to an accumulator and is pumped back through the brine exchanger completing the circuit.

The effluent

A summary of the pertinent design data i s a s follows:

Reservoir fluid

Isobutane

Generator output 64.28 MWe



50.00 MWe

63 kg (139 lbs )

3.149 M kg/hr (6.942 M l b s / h r )

3.702 M kg/hr (8.161 M lbs /h r )

Reservoir f luidlnet kwh

The magnitude of the above flow requirements makes the use of para l le l flow paths necessary o r desirable in various sections of the process . Consequently, plant design includes the following paral le l s tr eams :

Para l l e l Equipment Streams

Working fluid/ r e se rvo i r fluid exchangers

Working fluid condensers

2

8

Working fluid accumulators 4

Cooling water circulation pumps 3

Working fluid circulation pumps 8

The heat exchangers a r e fixed-tube design with single-pass flow on both shell and tube side. The r e se rvo i r fluid is on the tube side. All s tee l construction is specified and fouling fac tors a r e a s stated herein. The overal l t ransfer r a t e is about 250 Btu/(hr)(ft ')("F). This relatively high ra te combined with the economy inherent in fixed tube sheet design

32

resu l t s i n a significant reduction in the cost of heat t ransfer equipment fo r this service a s compared to our fo rmer estimates.

It is anticipated that the exchangers will be cleaned either mechanically o r chemically once pe r year during an annual turnaround. vision has been made for permanent installation for cleaning.

No pro-

Expander quotations were received f rom four vendors. Three were fo r axial flow designs, and one (Rotoflow) prepared a radial in-flow design. The Rotoflow offering was used in this study, but fur ther evaluations of expander offerings a r e necessary before a final selection is made.

The eight isobutane pumps a r e multi- stage ver t ical centrifugal pumps, 1,750 hp each. These pumps, as well a s cooling tower pumps and the cooling tower fans a r e electrically driven.

P r i m a r y p rocess control is based on the premise that plant output will va ry with demand. Consequently, a load control with manual s e t point is included for the generator, controlling the isobutane flow ra te to the turbine. Reservoir fluid flow ra t e is controlled by the temperature of the isobutane vapor. Adjustment of isobutane and reservoi r fluid flow ra t e s to each paral le l t r a in of hydrocarbon/reservoir fluid heat exchangers is manual. flow ra t e s to each condenser is a l so manual. emergency overspeed shutdown of the turbine.

Adjustment of isobutane vapor and cooling water Plant design provides for

Pre l iminary field studies indicate that the well fluid temperature a t Heber will decrease as the reservoi r is used. F o r the depleted condition, a mixture of 657'0 isobutane and 3570 propane appears opt: 'mum, requiring a minimum increase in r e se rvo i r fluid flow ra t e to produce 50 MWe of net power.

A process flow diagram, drawing number 7523-D-3241, provides ma te r i a l and heat balance details for the depleted case. of operating conditions for the base case (1007'0 isobutane) and the depleted case follows:

A comparison

Base Case Dede ted Case

Reservoir fluid flow ra t e

Working fluid flow ra t e

Cooling water flow ra te

3 .1 M kg/hr (6.942 M l b s / h r )

3.70 M kg/hr

43 ,000 m3/hr

(8.161 M lbs /h r )

(189,595 gpm)

4.5 M kg/hr (9.950 M lbs /h r )

5.0 M kg/hr

44,500 m3 / h r

(11.011 M l b s / h r )

( 195 , 942 gpm)

3 3

Base Case Depleted Case

586 kPa (85 psia) 896 kPa (130 psia) Working fluid accumulator operating p res su re

The increase in required flow rates for reservoir fluid and working fluid will necessitate future changes to the plant equipment. number of brine /working fluid exchangers, hydrocarbon condensers, working fluid circulation pumps, cooling water circulation p u p s , and cooling tower cells may increase. The turbine -expander is designed to operate under the conditions of the depleted case with a minimum change in par ts .

The

The required design p res su re for accumulators, working fluid side of the working fluid condensers and the case of the turbine wi l l increase. The design p res su res for the equipment furnished in the base case have been up-rated to mee t this condition.

Piping as shown for the base case (major l ines) will handle the increased flow requirements. Additional piping, instrumentation and electr ical ma te r i a l (i. e . , switch gear) will be required for the new equipment.

Thus, the plant is somewhat oversized for the beginning conditions but may be economically expanded to accommodate the depleted reservoi r conditions.

HYBRID PLANT

Isobutane was chosen a s the working fluid in the binary section of the hybrid plant. the s team flash unit will generate 10 MWe. The two generating units in the hybrid plant will produce a total net power of 50 MWe.

The binary section is designed to generate 52 MWe, and

The process flow diagram, drawing number 7523-D-3208B, shows the following operating conditions:

Reservoir fluid flow

Generator output 62. 0 MWe


Cooling tower work - 1.3 MWe

3 .3 M kg/hr ( 7 . 2 5 M lbs /h r )

Net output 5 0 . 0 MWe

34

Reservoir f luid/net kwh 65 kg (145 lbs)

These conditions were chosen af ter having considered flashing temperatures between 160 C (320 F) and 171 C (340 F) in combination with isobutane expander inlet conditions ranging f r o m 400 to 600 psia a t temperatures between 127 C (260 F) and 149 C (300 F). operating conditions optimize the power generated p e r well fluid flow rate.

The selected

Water-seal vacuum pumps were selected to remove noncondensable gases f r o m the surface condensers because the seal-water condenses a la rge pa r t of the entrained water vapor. blow down will be used a s seal water. The noncondensable gases will be pumped into the f la re system. d ispersa l of the hydrogen sulfide present. The blowdown and seal water will be pumped into the effluent reservoi r fluid to avoid contaminating the environment.

Most of the cooling tower

The f la re stack is designed for

The basic process controls a r e the manual set point load controls a t the two turbine-generator units. other. but have different response lags , the overr ide will prevent both controls f r o m fighting each other.

One of the two controls will rese t the Since both units depend on the same source of reservoi r fluid

An isobutane vapor temperature control regulates the flow of reservoi r fluid through the isobutane exchangers. control regulates the flow of r e se rvo i r fluid to the plant. para l le l flow adjustments a r e manual. will change according to load p r e s s u r e changes.

A s team separator level All the

The isobutane circulation ra te

When the reservoir temperature declines below design conditions, operation of the conversion plant mus t be modified to maintain the power output of the plant. br ine rate increased to maintain a suitable flow of s team to the turbine.

In the binary portion of the plant, the working fluid would be changed f r o m pure isobutane to a mixture of isobutane and propane. Additional heat exchangers and condensers may be required to maintain the power output of this section of the plant.

The s team flash p res su re must be lowered and the

The br ine ra te to the plant must be increased to meet those added requirements. of the turbines to adjust to the new conditions. brine rate will increase 50 to 60% over the life of the plant.

The exact ra te of increase will depend on the capability We est imate that the

35

c RESERVOIR FACILITIES

The systems developed in this study for the production of geothermal hot water, and the disposal of the spent water, a r e based on premises se t forth by Chevron Oil Company, developers of the Heber field. p rocess bases established by Chevron include:

The

Production

1.

2.

3.

4.

Directional drilling of a l l production wells required for a 50 MWe power plant will be concentrated in an a r e a of about one acre .

Production wells will be pumped a t a ra te of about 295 m3/h r (1,300 gpm).

Two alternate sand separa tors will be provided, each sized for a one-minute residence of the total flow.

An automatic bypass of the power plant will be provided sending hot geothermal water directly to the injection system.

Injection

1.

2.

3.

4.

5.

Spent water injection is made through wells drilled at three islands uniformly spaced on one quadrant of the circumference of the reservoi r having a radius of about 3,048 m (10,000 feet) its center at the power plant. unit a t Heber, th ree additional 50 MWe plants will be built. Injection islands for each of these plants will be located s imilar ly in one of the other three quadrants of the circle around the power plants.

In the complete development of a geothermal

Injection r a t e pe r well is 590 m 3 / h r (2,600 gpm).

P r e s s u r e required at an injection well head can increase to 2. 861 kPa (415 psia).

Injection pumps deliver spent water to injection well islands at approximately 1,482 kPa (215 psia). island can be used to ra i se the p re s su re to 2,861 kPa (415 psia).

A booster pump at each

Automatic controls a r e provided at the injection wells to regulate the flow of liquid to each well.

36

Production Systems

The design of the production piping systems is i l lustrated in the flashed s t eam system shown in drawing number 7523-D-3223. sized to accommodate the l a r g e r flow attending operation when the geothermal water temperature declines to 163 C (325 F). provided with a down-hole pump rated at 295 m3/hr (1300 gpm) and 2,069 kPa (300 psi) head. pipe in the system, pertinent dimensions of pipe runs a r e given in the drawing.

The l ines a r e

Each well is

To facilitate the estimation of the cost of the

Down-hole pumps a r e ver t ical shaft-driven centrifugals a s offered by P e e r l e s s Pump Co. The bearings will be a special teflon type suitable for high temperature. The pump tubing will be flushed with f i l tered product for lubrication of line-shaft bearings.

Bowl setting will be about 400 feet.

To maintain a check on the operation, each well is provided with temperature , p r e s s u r e and flow recorders . Discharge p r e s s u r e is controlled by a p res su re control valve on a line which recycles hot water back to the well.

The total hot water produced is alternately passed through one of two sand separa tors , each sized to provide one minute residence and a velocity of about seven feet/second. geothermal water f r o m the wells is expected to drop out i n the separator . measuring the sand content of the water entering and leaving the sand separator . s t r eams of water entering and leaving the separator through tes t filters for a given time and measuring the sand trapped on the filters. Periodically, sand collected in a separa tor is flushed out through nozzles on the bottom of the separa tor to a sand disposal basin.

Any sand entrained in the

The efficiency of sand separation is monitored by

This is achieved by simultaneously passing equal flow slip

Should the power plant be unable to use the total hot water flow, a by- pas s with a n automatic p r e s s u r e control valve passes water directly to the injection systems. This avoids abrupt changes in the operation of the production wells and provides t ime for production adjustment o r order ly shutdown.

The production piping sys tem for the binary p rocess at Heber is shown on drawing number 7523-D-3225. Heber is the same as that for the flashed s t eam process shown in drawing 7523 -D-3223. flow and well requirements for the three processes at Heber.

The sys tem for the hybrid process a t

The following table summarizes the production

37

Flashed Steam

Binary

Hybrid

Inj e ction Systems

Field Conditions Required Flow Wells Required

End - Initial End Initial

4.5 M kg/hr 7.4 M kg/hr (10.0 M l b s / h r ) (16.3 M lbs /h r )

4.5 M kg/hr 3.1 M kg/hr (6.942 M lbs/hr)(9.9 M lbs /h r )

5.81 M kg/hr 3.288 M kg/hr (7. 249 M lbs/hr) (12. 8 M lbs /h r )

16 21

12 19

13 21

The geothermal water f r o m the power plant is pump-d back t r e se rvo i r through injection wells. The injection piping sys tem for the flashed s team process a t Heber, shown in drawing 7523-D-3224, illustrates the general features of such systems. Two injection pumps a r e provided for the total flow which, for the flashed s team process , va r i e s f r o m about 4.5 M kg/hr (10. 0 M l b s / h r ) initially to 7.4 M kg/hr (16. 3 M l b s / h r ) when the geothermal hot water temperature declines to 163 C (325 F). The injection pumps have a discharge p r e s s u r e of about 1,620 kPa (235 psia) and deliver the spent water to the far thest injection well island at about 1,482 kPa (215 psia). can be used to r a i se the p r e s s u r e to the maximum 2,861 kPa (415 ps ia ) at the well head f o r injection at 590 m 3 / h r (2,600 gpm). field conditions only seven wells a r e required a t full injection rate , o r all ten wells could be used at an average ra te of 422 m 3 / h r (1,860 gpm). To give flexibility, provision is made to bypass the booster pump and inject water at 1,482 kPa (215 ps ia ) p r e s s u r e provided by injection pumps.

the

At each island a booster pump

Under initial

As required by Imperial County, the injection l ines f r o m the power plant to theinjection wells a r e underground and a r e suitably coated and wrapped. valve, temperature and p r e s s u r e r eco rde r s and a flow controller r e corder.

At each well, the feed line is provided with a flow control

The injection piping sys tem fo r the binary process at Heber is shown in drawing 7523-D-3226. same a s that for the flashed s team process shown in drawing 7523-D- 3224. The following table summar izes the injection well requirements for the three processes a t Heber.

The sys tem fo r the hybrid process is the

3 8

Process

Flashed steam

Binary

Hybrid

Wells Required Initial Field Condition End Field Condition

10

9

10

GENERAL FACILITIES

The following facil i t ies a r e provided for each of the conversion plants:

B u ild ing s

The main control building is 15 by 23 m (50 by 75 feet) and contains the control room, swi t ch gear , laboratory and shop. The compressor building is 7. 5 by 7. 5 m (25 by 25 feet) and contains the air compressors and d rye r s . The cooling tower treatment building i s 4. 6 by 7. 5 m (15 by 25 feet) and contains the chemical mixing vessels and injection pumps.

F i r e Protection

The binary and hybrid plants use the cooling tower basin a s a f i r e - water reservoi r . An electr ic pump, a diesel pump and a jockey pump a r e provided along with automatic controls to s t a r t the main pumps in case the f i r e water pressure drops. Each plant is provided with a f i r e water loop around the plant with hydrants and f i re monitors as shown in drawings 7523 -D-3256 and 7523 -D-3257 (Plant Requirements Manual). flashed s team plant.

Only local f ire protection facil i t ies a r e provided for the

F la re System

The binary and hybrid plants a r e provided with a f lare system that contains a knock-out drum, water seal , and a 125-foot f lare stack as shown on drawing number 7523 -D-3222 (Plant Requirements Manual).

Instrumentation

In addition to the controls and instruments shown on the piping and instrumentation diagrams, each plant and each field facility is

39

provided with a data logging system which wi l l monitor and record all pertinent variables. date when multiple plants have been installed a t the reservoi r , a single computer can be installed to control all the plants.

The system wi l l be installed so that at a la ter

Blow -down Disposal

Al l plants a r e designed to dispose of contaminated process water such a s cooling tower blow down by discharging the fluid into the agricultural drains . No treatment facilities for the wastewater a r e planned.

40

v* V-3 ,v-4 PRIMARY FLASH VE55EI-S SECONDARY F U 5 H UE533-5

9

T- I €3 T U R ~ N E SURFACE CONDENSER

G-I GEN=TOR

STREAM PROPERTIES N6T OUFWT, K W ]P),=

CT- \

COOLING T O W E R

- P- l Vp-I

CONDEN~TE PUMP VACUUM PUMP 2'111 GPM U KW.

153 W C F M m LW

I THE BEN M T CO.

T- l - G-l nnl~r/u.c EXCUANGER EXPANDER GENERATOR H C SURGE DRUM COOLING TOWER

p-l H.C. CIQCUL&TIOU PUMP

6- I - GENERATOR

v- l - U.C. SUUY W U M

u P-l -

Y.C. CIRCULATION PUMP

STREAM PROPERTIES

I THE BEN HOLT CO. b-l - ,,,u

"a"< "S"8Srn D" c. 0.m BINARY POWER PANT

& , s u a o FOP E.ST,~%TE UP OWD I*.'. HEBER , CLIFORNIA -TED e45E M ~ E O x u n ",,TM~"

EP R \

REFERENCE DRAWING

W..,MGW T # , U

I

CT-I COOLING TOWER

CONOENIATE PUMP 345 GPM

kfi BLOWDOWN PUMP

630 GPM

VALLES CALDERA CONVERSION PLANTS

THE RESERVOIR

The Valles Caldera hydrothermal reservoi r i s located in the north- eas te rn corner of Sandoval County, New Mexico. The reservoi r i s located in mountainous te r ra in at an elevation of about 2,750 me te r s (9 ,000 feet) . At this elevation, atmospheric p re s su re is 72 .4 kPa (10. 5 psia).

Ai r temperatures a t the site range f rom 32 C (90 F) in summert ime to as low a s -40 C (-40 F) in the wintertime. One percent of the t ime during the summer months, the wet bulb temperature in the a r e a exceeds a temperature of 17 C (62 F). This temperature was used f o r de sign.

The a r e a is quite rough, with the geothermal wells located along the valleys created by Sulfur Creek and Redondo Creek. a r e a i s res t r ic ted, and roads to the si te a r e indicated to be dirt .

Access to the

The availability of water at the s i te i s res t r ic ted by regulations of water rights a s described in the Prel iminary Environmental Assessment . f r o m Santa Clara Creek located in the northwest corner of Sandoval County, a distance of approximately 18 miles. e lectr ic power in the a rea , and it would be necessary to bring the water line over a 3,000 m (10 ,000 f t ) mountain pass. installation has been estimated to be in the range of 7. 5 to 10 million dollars. possibly be used as cooling tower makeup, providing that subsidence would not be a problem and provided that permission to do so could be obtained f r o m the State of New Mexico. W e have assumed that water would be available at the plant s i te , and our estimates do not include the cost of obtaining a suitable source of water.

The assessment suggests that water might be obtainable

There a r e no roads nor

The cost of this

Condensate from the steam flash o r hybrid plants could

Information furnished by the Electr ic Power Research Institute regarding the Valles Caldera reservoi r fluid was interpreted a s follows:

Total dissolved solids 5 ,000 ppm

Silica (SiOz) 400 ppm

Bottom-hole temperature 260 C (500 F)

Noncondensable gases low

45

Wells a r e self-producing, providing well head fluid at the following conditions:

Temperature 182 C (360 F)

P r e s s u r e 1,034 kPa (150 psi)

Flow ra t e 113,400 kg/hr (250,000 lbs /h r )

These data.were used a s a design basis.

No information is available on the corrosive character is t ics of this fluid. to fluid f r o m the Heber reservoi r . suitable mater ia l for piping and vessels .

Therefore, it was assumed that its propert ies would be s imilar Carbon s teel is assumed to be a

The SiOz present in the fluid may cause scale to fo rm on the heat exchanger tubes of the binary and hybrid plants. formed to determine the temperature level a t which scale formation occurs. If scale formation is shown to occur, then the binary and hybrid plants could be designed to use flashed steam for heating. Because the fouling character is t ics of the reservoi r fluid were not known, the Heber fouling fac tors were used for the Valles Caldera binary and hybrid plants.

Tests should be pe r -

Some noncondensable gases occur in the flashed steam, but the concentration of gas in the r e se rvo i r fluid is not known. t ra t ion of noncondensable gases necessitates a major investment in vacuum pumps f o r the flashed s team and hybrid plants. that the quantity of noncondensable gases would be the same a s for Heber; i. e . , 680 kg/hr (1,500 lb s /h r ) . When accurate analyses of the noncondensable gases a r e available, this assumption must be reviewed and suitable equipment provided to remove the gases.

A high concen-

It was assumed

Similarly, the quantity of hydrogen sulfide present i n the noncondensable gases was assumed to be in the range f r o m 100 to 1 ,000 ppm. quantity of gas can be safely dispersed by using a vent stack of adequate height. If the quantities of hydrogen sulfide present in the reservoi r fluid preclude the use of a vent stack, then a sulfur removal unit such as a Stretford plant, should be added to the power plant.

This

The power conversion units and reservoi r piping a r e designed on the bas i s that some degradation of the reservoi r fluid will occur in the life of the plant. If the down-hole temperature of the reservoi r declines, m o r e fluid must be supplied to the plant to maintain a constant power output. Consequently, m o r e wells must be drilled and operated. The plant and reservoi r systems a r e designed for a 15 percent increase in e

46

flow which corresponds to a decrease in the down-hole temperature of 20 C (35 F).

FLASHED STEAM PLANT

Drawing number 7523-D-3203 i s a process flow diagram of the Valles Caldera flashed s team plant. The hot reservoi r fluid en ters the plant at a flow ra t e of 1. 8 M kg/hr (3. 96 M lbs /hr ) . pas s into two paral le l f i r s t - s tage f lash drums a t a p r e s s u r e of 1, 055 kPa (153 psia). The f i r s t - s tage drum produces 324,770 kg/hr (716,000 l b s / h r ) of p r imary s team which passes through a s team separator before reaching the turbine-generator a t a p r e s s u r e of 1, 055 kPa (153 psia and a temperature of 182 C (360 F).

The brine and s team

The liquid f r o m the f i rs t -s tage f lash drums flows to the second-stage f lash drums where its p re s su re is reduced to 232 kPa (33.7 psia). resultant f lash produces 169, 192 kg/hr (373,000 l b s / h r ) of secondary s team which flows through a s team separator to a lower stage of the turbine-generator through a separate s e t of admission valves. s team reaches the turbine a t a p re s su re of 228 kPa (33.0 psia) and a temperature of 125 C (257 F). line, their p r e s s u r e varying with turbine stage p r e s s u r e and with de ma nd.

The

The

The secondary flash drums float on the

The flashed liquid flows f r o m the second-stage f lash drums to the suction of the injection pumps which re turn the liquid to the reservoir . Liquid level i s maintained in the second-stage f lash drums by a control valve on the pump discharge.

The turbine generator is operated as a base-load unit under load control. The operator ass igns a load to the generator, and the turbine must accept that load at constant speed. The turbine governor detects changes in load and adjusts admission valves on both the p r imary and secondary s team lines to satisfy the assignment. A separate emergency t r i p mechanism on the turbine shaft will close emergency stop valves on both p r imary and secondary s team lines if turbine speed exceeds 3,600 r p m by a given percentage.

Exhaust s team f r o m the turbine passes directly into a surface condenser, where a back p res su re of 10. 1 kPa (3 in. Hg) is obtained under design cooling water conditions. suction of the injection pumps for disposal. The condensate is added to the reduced br ine to make the replenishment volume substantially equal to the volume of f r e sh brine delivered to the plant. pera ture of this flow is 103 C (218 F).

The s team condensate is pumped to the

Average tem-

4 7

Noncondensable gases f r o m the reservoi r fluid and air leakage a r e removed f r o m the condenser by two la rge vacuum pumps in parallel . The exhaust g a s i s discharged into a ver t ical stack which is designed to disperse the hydrogen sulfide contaminant.

A summary of pertinent design data for the flashed s team plant is as follows:

Reservoir fluid r a t e 1.8 M kg/hr (3.96 M l b s / h r )

55.0 MWe Generator output


Cooling tower work - 1.1 MWe

Net output 52 .0 MWe

Reservoir f luid/net kwh 34 kg (76 lbs )

BINARY P L A N T

The reservoi r fluid at Valles Caldera flows naturally f r o m the well, producing two phases a t the surface in the following proportions:

Steam 15. 3’7’0 (by weight)

Hot water 84. 770 (by weight)

Because of the two-phase flow, the heat exchanger section of this plant differs f r o m the Heber and Raft River binary plants. Separation of the s team and hot water is per formed in a horizontal separator providing a minimum of one-minute liquid residence time. the separator passes through a second-stage separator for removal of entrained condensate enroute to a hydrocarbon/ s t eam heat exchanger. Condensate leaving the exchanger is mixed with the hot water f r o m the separa tor , and this mixed s t r e a m i s used to preheat the hydrocarbon s t ream. condensate discharge s t r e a m and discharged into the f la re system.

The s t eam leaving

Noncondensable gases a r e continuously bled off f r o m the

The Valles Caldera process flow diagram, drawing number 7523-D-3259, providing mater ia l and heat balance details, is included in this section of the report . :gIsopentane is used f o r the operating fluid in the binary process plant. The isopentane is pumped f r o m the accumulator through the hydrocarbonlreservoir fluid exchanger and through the hydrocarbon s team exchanger.

:$Optimized proce s s

48

The heated isopentane in a subcrit ical condition is used to drive the expansion turbine. A generator output of approximately 56 MWe is required to provide for in-plant electric power consumption and produce a net output of 50 MWe.

Tes ts run on geothermal reservoi r fluids a t some locations have shown an increase in deposition of solids when the fluid is cooled. In the absence of specific tes t data on the reservoi r fluid a t Valles Caldera, the fouling factors observed with the Heber reservoi r fluid were used. The hydrocarbon/reservoir fluid heat exchangers a r e designed with four units in s e r i e s to facilitate cleaning.

A summary of the pertinent design data for the binary plant is a s follows:

Reservoir fluid

Isopentane


Pumping work 3 . 6 MWe

2 . 7 MWe Cooling tower work

Net output 50 .0 MWe

Reservoir fluid/net kwh

1. 19 M kg/hr (2. 62 M lbs /h r )

2. 10 M kg/hr (4.62 M lbs /h r )

-

24 kg (52 lbs )

HYBRID PLANT

Isobutane was chosen a s the working fluid in the b a s e c a s e binary power cycle of the hybrid plant. 2 4 MWe, and the s team unit will generate 32 MWe. The two generating units in the hybrid plant will produce a total net power of 50 MWe.

The binary portion of the plant will generate

The process flow diagram, drawing number 7523-D-3209C, shows the plant operating conditions.

The relative sizes of the s team and binary sections of the plant were chosen af ter having considered a s team temperature of 182 C (360 F) i n combination with isobutane expander inlet conditions ranging f rom 2,758 to 4,237 kPa (400 to 600 psia) at temperatures between 137 C (280 IF) and 160 C (320 F). a compromise between those providing maximum power generation pe r well fluid flow rate and those requiring a minimum isobutane circulation rate . The noncondensable gases will be dispersed in the f lare system.

The selected operating conditions represent

/ \

49

Wastewater will be pumped into the effluent reservoir fluid to avoid contaminating the environment.

A summary of the pertinent design data for the hybrid plant is a s follows:

Reservoir fluid ra te



1.4 MWe Cooling tower work

Net power 50.0 MWe

1.36 M kg/hr (3.0 M lbs /h r )

-

Reservoir fluid/net kwh 27. 2 kg (60 lbs)

RESERVOIR FACILITIES

The systems developed for production and injection of geothermal f lu id a t Valles Caldera, New Mexico, a r e based on conventional vertical drilling of the wells a t a spacing of 30 a c r e s p e r well. Based on square plots, the distance between wells is approximately 349 me te r s (1,145 feet) . The production wells in this field a r e self-flowing, and the fluid at the well head i s a mixture of s team and geothermal water.

The preceding description of the production scheme a t Heber, California applies for the most pa r t to Valles Caldera, except that special flow me te r s a r e required f o r the measurement of two-phase flow. Also, the removal of sand, i f any, i n the geothermal fluid is achieved in the f i rs t -s tage s team separator of the power plant.

The geothermal fluid flow and the number of wells required for the three processes evaluated at Valles Caldera for initial and final conditions a r e l isted in the following table.

Required Flow No. of Wells Initial End Initial - End P r o c e s s

1,796 M kg/hr 2,036 M kg/hr Flashed s team (3,989 M l b s / h r ) (4,489 M lbs /h r ) 16 18

Binary (3,217 M l b s / h r ) (3,574 M lbs /h r ) 13 15

12 14 (3,002 M lbs /h r ) ( 3 , 3 7 8 M lbs /h r ) Hybrid

1,489 M kg/hr

1,362 M kg/hr

1,621 M kg/hr

1,532 M kg/hr

G

50

The scheme for injection of spent geothermal fluid at Valles Caldera i s basically the same a s that a t Heber. However, the distance f rom the power plant to the neares t edge of the injection field i s 1,524 me te r s (5 ,000 feet) instead of 3 ,048 me te r s (10 ,000 feet used by Chevron a t Heber, and the wells a r e spaced a t 30 a c r e s p e r well. requirements a r e summarized in the following table:

Injection well

No. of Wells R.equired P r o c e s s Initial Field Condition Final Condition

Flashed s team 4 4

Binary 3 3

Hybrid 3 3

51

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RAFT R.IVER CONVERSION PLANTS

THE R.ESERVOIR

The Raft River hydrothermal reservoi r is located in south-central Idaho, approximately 40 miles southeast of Burley. The a r e a l ies along the Raft River Valley a t an elevation of about 1,400 me te r s (4,800 feet) . At this elevation the atmospheric p re s su re i s 82 kPa (12 psia).

Air temperatures at the si te range f rom 38 C (100 F) in summert ime to a s low as -34 C (-30 F) in the wintertime. The wet bulb tempe'rature in the a r e a reaches o r exceeds a maximum of 18 C (65 F) one percent of the t ime during the summer months. This temperature was used for de sign.

The a r e a is rugged with mountains reaching to about 3,000 me te r s (9,800 feet) elevation. comes close to the geothermal plant site.

U. S. Highway 30 is a three-lane highway which

Water for makeup to the cooling tower will be taken f r o m the Raft River o r f r o m surface wells.

Production wells and injection wells have been allocated 30 a c r e s of ground a r e a pe r well. a r e a s of the geothermal anomaly.

Injection wells will be located on the cooler

The R.aft River reservoi r fluid has the following general chacterist ics:

Total dissolved solids 2 ,000 ppm

Bottom-hole temperature 149 C (300 F)

The following noncondensable gases a r e present i n the fluid:

cc @ Standard Temperature & Gas P r e s s u r e , per Liter of Brine Mol. Percent

0.53 . 1

32. 0 . 1 . 7

5.8

55

1.4 . 1

81.8 .25

1.7 14. 8

. 1

100

The geothermal producing wells mus t be pumped to achieve high production rates . It has been assumed that the differential p re s su re required to produce the wells is 2,068 kPa (300 psia) and that the p r e s s u r e required to inject the brine will increase to 2,758 kPa (400 psia) a t the well head. We have used the same pumping r a t e of 295 m3/hr (1,300 gpm/well) as at Heber.

/---

The corrosion and fouling character is t ics of the Raft River reservoi r fluid a r e not known. Therefore, it was assumed that the fluid would have the same character is t ics as the Heber reservoi r fluid. We have specified the use of s teel in a l l equipment exposed to the reservoi r fluid o r flashed s team, except the s team turbines and surface condensers where stainless s tee l is used.

FLASHED STEAM PLANT

A process flow diagram of the flashed-steam plant i s shown in drawing number 7523-D-3207. flow rate of 7. 39 M kg/hr (16.3 M lbs/hr) . f irst-stage f lash drums at a p r e s s u r e of 290 kPa (42 psia). The first- stage f lash produces 241,000 kg/hr (532,000 l b s / h r ) of p r imary s team which passes through a s team separator before reaching the turbine- generator a t a p re s su re of 284 kPA (41. 2 psia) and a temperature of 132 C (270 F).

The hot r e se rvo i r fluid enters the plant a t a The brine flows into the

Liquid f r o m the f i r s t - s tage f lash drums flows to the second-stage flash d rums where its p r e s s u r e is reduced to 114 kPa (16.6 psia). resultant f lash produces 391,900 kg/hr (864,000 l b s / h r ) of secondary s t eam which flows through a s team separa tor to a lower stage of the turbine-generator through a separate set of admission valves. s t eam reaches the turbine at a p r e s s u r e of 112 kPa (16.3 psia) and a temperature of 103 C (218 F). the line, their p r e s s u r e varying with turbine stage p res su re and with demand.

The

The

The secondary f lash drums float on

Exhaust s team f r o m the turbine passes directly into a surface condenser, where a back p r e s s u r e of 6.77 kPa ( 2 in. Hg) is obtained under design cooling water conditions. suction line of the injection pumps for disposal. added to the reduced br ine to make the replenishment volume substantially equal to the volume of f r e s h br ine delivered to the plant. Average temperature of this flow is 98 C (208 F).

The s team condensate i s pumped to the The condensate is

The cooling water temperature was established a t 5.5 C (10 F) above the design wet bulb temperature . This i s the minimum pract ical cooling

5 6

tower approach and resul ts in an expensive tower. me t r i c study in which cold water temperature was ra i sed slightly 1. 7 C (3 F) increased the cost of the condenser more than it reduced the cost of the cooling tower. densing p res su re was raised slightly to 15 kPa (2.2 in. Hg) produced a lo s s of efficiency and an increase in br ine consumption. The prospec- tive cooling tower capital cost saving was more than offset by increased br ine costs and increased cooling tower fan horsepower.

However, a para-

Similarly, another study in which the con-

Turbine selection was difficult for the plant. bucket size mentioned ear l ie r , 55 MWe of output could be obtained only with a four-flow, two-case machine. with a two-flow turbine was about 38 MWe.

With the limitations on

The maximum output attainable

Noncondensable gas flow has been estimated a t 405 kg/hr (893 l b s / h r ) based on a brine analysis. denser with vacuum pumps. 13.8 kPa (2 in. Hg), two stages a r e required. f i r s t - s tage pumps and two medium-size second-stage pumps. is provided for the dispersal of the noncondensable gases.

These gases a r e removed f rom the con-

There a r e four la rge Because of the low condensing p r e s s u r e

A stack

A summary of pertinent design data for the plant is a s follows:

R.eservoir fluid ra te



Cooling tower work 2 .1 MWe

Net power 49.2 MWe

7.4 kg/hr (16.3 M l b s / h r )

R.eservoir f luid/net kwh 150 kg (331 lbs )

BINARY PLANT

Because of the low reservoi r temperature , a mixture of 50% isobutane and 50% propane was used for the operating fluid in the binary process plant at Raft River, Idaho. i s required to provide for in-plant e lec t r ic power consumption and produce a net output of 50 MWe.

A generator output of approximately 68 MWe

The Raft River process flow diagram, drawing number 7523-D-3255, shows mater ia l and heat balance details for the plant. character ized by the high circulation ra te of process fluids required to produce 50 MWe of power.

This plant is

Ten paral le l hydrocarbon circulation pumps

57

c a r e needed to meet the p rocess flow requirements. the plant is s imi la r to the Heber binary plant.

In other respects ,

A summary of pertinent design data for the plant is a s follows:

R.eservoir fluid ra te

Hydrocarbon fluid r a t e




50.0 MWe Net power


5.0 M kg/hr (11.0 M l b s / h r )

4.8 M kg/hr (10.6 M l b s / h r )

HYBRID PLANT

A mixture of 50 mol 70 propane and 5070 isobutane was chosen a s the working fluid in the binary power cycle of the hybrid plant because of the low temperature of the r e se rvo i r fluid. designed to generate 57 MWe, and the s team f lash unit will generate 9 MWe. p e r well fluid flow rate.

The binary section is

The selected design conditions optimize the power generated

The process flow diagram, drawing number 7523-D-3254B, shows the plant operating condition. t e r ized by high flow ra tes of the process fluids.

This plant, like the binary plant, is charac-

A summary of this pertinent design data for the plant is a s follows:

Reservoi r fluid ra te




50.0 MWe Net power


5 . 9 kg/hr (11.9 M lbs /h r )

RESERVOIR FACILITIES

At Raft River, the production and injection wells a r e dril led at a spacing of 30 a c r e s per well. The production wells a r e self-flowing,

5 8

but down-hole pumps a r e used to boost the flow to the design ra te of 1,300 gpm pe r well. generally the same as at Valles Caldera. At Raft River only initial field conditions a r e considered, since any decline in the reservoi r temperature would resul t in an excessive increase in plant and operating costs. table.

The production and injection piping schemes a r e

Flows and well requirements a r e summarized in the following

No. of Wells Required P r o c e s s R.equired Flow of Well Fluid Production Injection

Flashed s team 7.4 M kg/hr (16.3 M l b s / h r ) 27 13

Binary 5.0 M kg/hr (11.0 M l b s / h r ) 19 9

Hybrid 5.4 M kg/hr (11.9 M l b s / h r ) 20 10

59

V*Z PRIMARY FLASH VESSELS

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THERMODYNAMIC B1NAR.Y CYCLE ANALYSIS

In the development of the base binary cases for the three s i tes , p re - l iminary optimization studies were made, and on the basis of these findings the process design for the base case was established.

Subsequently, a screening study was made to determine which fluids and cycle character is t ics appeared to be optimal for each of the r e se rvo i r s being studied. The resu l t s of this study a r e presented in this section.

The cycle under consideration i s a simple Rankine cycle as shown in Figure 1. The working fluid is a light aliphatic hydrocarbon. The liquid working fluid is pumped to the operating pressure . It is then vaporized by heat exchange with the geothermal fluid. generated by passing the working fluid through an expansion turbine. The cycle is completed by condensation of the working fluid.

Power is

Several assumptions have been made in order to minimize the case studies and ensure that the cases a r e comparable. temperature difference (LMTD) for the condenser was 8 C (14.4 F) in a l l cases ; this corresponds to a 6 C (10 F) cooling water temperature r i s e and 6 C (10 F) approach for a pure hydrocarbon. The minimum hydrocarbon exchanger approach temperature was se t a t 8 C (15 F) for all cases. No working fluid condensing p res su res below local a tmos- pheric p r e s su re were allowed. taken to be the 170 summer values. The working fluid pump efficiency was 80700; the turbine efficiency was 8570; and the generator efficiency was 9870. (50 psi) , and in the condenser it was 14 kPa (2 psi). sized for a net production of 50 MWe af ter power had been provided f o r the working fluid pumps and the cooling tower.

The log mean

The meteorological var iables were

The working fluid p r e s s u r e drop in the vaporizer was 345 kPa The plant was

The performance of each power cycle was evaluated by a computer p rogram developed by Holt personnel. Benedict-Webb-Rubin equation of state to calculate a l l the thermodynamic propert ies of the system. The p rogram will handle either pure hydrocarbons o r two component mixtures in any proportion. addition to computing the turbo-generator performance and the auxiliary power consumption, the p rogram also provides temperature-enthalpy curves to facilitate the design of the heat exchange equipment. sample of the program output is shown in Table 2 .

The p rogram uses the modified

In

A

6 3

The geothermal fluid ra te is determined by a graphical technique utilizing the temperature-enthalpy plot of the R.ankine cycle. known well fluid temperature and approach in the heat exchanger, the geothermal fluid reject temperature can be determined. balance will then provide the flow ra t e s and thermodynamic state of all the s t r eams in the cycle. Examples of temperature-enthalpy plots for a super-cr i t ical and subcrit ical cycle a r e i l lustrated in Figures 2 and 3 .

With a

A heat

The various cycle permutations were optimized with respect to geothermal fluid consumption. temperature , p re s su re and fluid composition were var ied in search of the lowest well fluid rate. mixed fluid cycles, the condenser LMTD was held constant. Several general statements can be made about the optimum cycle for a given case.

F o r each reservoi r case, the cycle

In o rde r to properly compare pure and

1.

2.

3 .

4.

5.

6 .

7.

As the reservoi r temperature increases , a heavier molecular weight fluid i s preferable.

As the molecular weight of the working fluid increases , the optimal sys tem p r e s s u r e will decrease.

A mixed fluid will generally resu l t in a lower condensing p res su re since it does not have a constant condensing temperature. allows a closer approach to the cooling water enthalpy curve.

This

The optimum operating conditions will generally resu l t in a mini- m u m amount of superheat in the turbine exhaust.

An optimum cycle will generally not occur if the expansion path pas ses through the two-phase envelope of the working fluid Mollier diagram.

A subcrit ical cycle is indicated for a well fluid that is produced f r o m the field as a two-phase s t ream. A super-cr i t ical cycle is desirable otherwise.

F o r each possible bottom-hole temperature and surface condition of the well fluid, there is a par t icular hydrocarbon working fluid that will produce the optimum cycle. The propert ies of this fluid may o r may not coincide with the propert ies of one of the aliphatic hydrocarbons. If not, then a mixture of adjacent hydrocarbons is indicated.

It must be recognized that there is a limit to the accuracy and precis ion of the cycle calculations. This is caused by the uncertainties inherent

6 4

. . . . . . . . - . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . __ - .. -- - - __.

i n the design c r i te r ia and knowledge of local conditions. It is therefore not feasible f r o m a time and expense standpoint to t r y to c a r r y the optimization t o too fine a degree. cycles we shal l re fe r to a s prefer red wi l l be close to the t rue o p t h u m condition. The major var iables a re : operating temperature , operating p r e s s u r e and working fluid. As between different case studies, the temperature will not be var ied by l e s s than 3 C (5 F) in sea rch of an optimum; the p re s su re will not be var ied l e s s than70 kPa (10 psi) ; and the composition of a mixture will not be var ied l e s s than 10% of one component.

It can, however, be expected that the

The resul ts of the Heber studies a r e tabulated in Table 3 . Twenty different simple binary cycles were evaluated for the Heber design conditions. Since much of this information was usable f o r the other fields, fewer cases were required in the la te r studies. Initially, a base case was selected to serve a s a start ing point. cycle a t 4, 137 kPa (600 ps ia ) and 149 C (300 F) was selected, based on our previous experience a s being a reasonable case f r o m which to optimize. The base case produced 7.203 MWe per million pounds of well fluid. A summary is l isted below:

A pure isobutane

All cases were sized for a net e lectr ical output of 50 MWe.

Well fluid

Shaft work 87,966 BHP

output 64.28 MWe


3,148,000 kg/hr (6,940,000 l b s / h r )

Cooling tower work

N e t production

4 . 8 3 MWe

50.00 MWe

The cycle which was found to be optimum utilizes a mixture of isobutane and isopentane a s a working fluid. is obutane.

The mixture contains 5070

Well fluid


General output 60.89 MWe


3,017,000 kg/hr (6,651,000 l b s / h r )

Cooling tower work

Net pro duct i o n

65

2 .69 MWe

50.00 MWe

The power production f rom the cycles designed fo r this si te ranged f rom 7. 52 MWe/million pounds well fluid for the bes t cycle to 6.38 MWe/million pounds well fluid for the leas t efficient.

DEPLETED RESERVOIR

Prel iminary field studies indicate that the well fluid temperature will decrease over a period of t ime f rom 182 C (360 F) to 163 C (325 F). In order to provide fo r this eventuality, a s e r i e s of cases were run a t this lower temperature. hydrocarbon cycle a s the base case for the 182 C (360 F) reservoir ; only the amount of well fluid required to produce 50 MWe net was changed. (11. 3 M lbs /hr ) .

The base case for this situation utilized the same

The well fluid consumption increased by 63% to 5. 13 M kg/hr

Several other cycles were investigated in order to improve on this, and it was found that a mixture of 3570 propane and 65% isobutane with a turbine inlet condition of 4, 137 kPa (600 psia) and 129 C (265 F) provided a significant decrease in brine consumption. this case i s shown:

A summary of

Well fluid




4,513,000 kg/hr (9,950,000 l b s / h r )

Cooling tower work

Net production

VALLES CALDERA

5.18 MWe

50.00 MWe

F o r the Valles Caldera field, seven cases were examined a s shown on Table 4 . Since the well fluid in this case is hotter than a t Heber and the heat rejection temperature is colder, a heavier fluid is required. However, since the well fluid is naturally flowing and exists in two phases a t the surface, a subcrit ical Rankine cycle, a s shown in Figure 3 was found to be the optimum. The base case f o r this field was pure isobutane operated a t 4,137 kPa (600 psia) and 149 C (300 F). However, the condensing temperature was 33 C (92 F) o r 10 C (18 F) below that a t Heber. A summary of this case i s shown below:

Well fluid


1,459,000 kg/hr (3,217,000 l b s / h r )

6 6



Cooling tower work

Net production

4.59 MWe

50.00 MWe

Several cycles using mixtures of isobutane and isopentane were studied, but the optimum cycle was found to be a mixture of 90% isopentane and 1070 normal hexane. and 174 C (345 F). Since the field i s a t an elevation of 9 , 0 0 0 feet, this i s safely above atmospheric pressure .

This cycle was operated a t 2,482 kPa (360 psia) The condensing p res su re is 102 kPa (14 .8 psia).

A summary of this cycle is shown below:

W e l l fluid



Pumping work 3. 13 MWe


1,185,000 kg/hr (2,612,000 l b s / h r )

Net production 50.00 MWe

This cycle shows a 1970 improvement over the base case. noted that the working fluid in this case i s not much different f r o m pure isopentane. would not be ve ry inferior to this cycle. This i s , in fact, the case. P u r e isopentane shows a decreased performance of only 0. 1570. fore , pure isopentane could be selected a s the desired working fluid with no significant penalty

It should be

It might be expected that a cycle using isopentane alone

There-

RAFT RIVER

Nine cases were studied for the Raft River field as shown in Table 5. Since the geothermal fluid a t this s i te i s cooler than at Heber, a lighter working fluid and higher working p r e s s u r e a r e needed. there is a significant improvement in performance, the maximum working p res su re f o r 300 # ra ted pipe fittings should not be exceeded. The base case selected for this field i s isobutane. vaporize isobutane at these lower temperatures , a subcrit ical cycle a t 2,758 kPa (400 psia) and 121 C (250 F) is required. A summary of the base case is shown below:

However, unless

However, in o rde r to

W e l l fluid


6,609,000 kg/hr (14,570,000 l b s / h r )

6 7

General output

Pumping w o r k

Cooling tower work

Net production

61.78 MWe

6.38 MWe

5.40 MWe

50.00 MWe

/--

Several mixtures of propane and isobutane were found to be more efficient than the base case. isobutane operated a t 4,137 kPa (600 psia) and 121 C (250 F). summary of this cycle is shown below:

The best one was 5070 propane and 5070 A

Well fluid 5,006,800 kg/hr (1 1,040,000 l b s / h r )

Shaft work

General output

Pumping work

Cooling tower work

Ne t production

92,466 BHP

67.58 MWe

11.93 MWe

5.65 MWe

50.00 MWe

The power production of the various cycles studied ranged f r o m 3.412 to 4. 528 MWe/million pounds of well fluid.

COMPOUND CYCLES

In general , the performance of a simple binary cycle can be improved by adding m o r e equipment to make a more complex cycle. I'compound cycles" improve performance by more efficiently utilizing the geothermal fluid. m o r e commonly considered a re :

These

There a r e many possible cycles, but three of the

1. Turbine exhaust heat recovery

2. Dual 15n-line' ' cycle

3 . Dual fluid cycle

The first cycle is only pract ical when there is a significant amount of superheat in the turbine outlet vapors. This is not the case for any of the optimum cycles so far proposed for this project. p rocesses the geothermal fluid through two successive cycles utilizing different fluids and operating conditions. at a low temperature. Although this cycle extracts the maximum heat available in the brine, the conversion efficiency of this heat to

The second cycle

The br ine can then be rejected

6 8

electricity is low. a t a high temperature to maintain the t t in- l inet ' character is t ic of the process . i n the p r imary cycle, and the overall efficiency of the cycle is generally l e s s than that of the simple cycle.

This is because the pr imary cycle must reject heat

The high reject temperature causes a low Carnot efficiency

The third possible cycle avoids this problem. Figure 4. the given geothermal fluid. f r o m the p r imary cycle, below the pinch point, and used to heat a secondary cycle. The effective geothermal fluid heating curve then conforms more closely with the shape of the hydrocarbon heating curve. If desired, the same principle can be applied to the secondary cycle resulting in a three-cycle process. When evaluating the desirability of a compound cycle, a significant increase in performance over the simple cycle should be observed in order to justify the additional expense of equipment f o r the secondary cycle.

It i s i l lustrated in The pr imary cycle is selected to be the optimum cycle for

A side s t r e a m of geothermal fluid is taken

Two compound cycles were studied using the best simple cycle a s a basis (see Table 3 ). The resul ts a r e shown below:

Simple Cycle 3.041 MWe/M kg (7. 518 MWe/M lbs) of well fluid

Dual Cycle 3.341 MWe/M kg (7.381 MWe/M lbs) of well fluid

Treble Cycle 3. 392 MWe/M kg (7.478 MWe/M lbs) of well fluid

Since for a reasonably well optimized case the compound cycles failed to exhibit any significant improvement over a simple cycle, fur ther study into compound cycles was abandoned.

63

CON OENSEU COQLIUG

CIZ'CULATING PUMP

F IGURE I

SUPERCRITICAL BINARY CYCLE TEMPERATURE-ENTHALPY DIAGRAM

I I I 1 I I I I I

2 0 40 60 80 100 12 0 140 160 180 HEAT CONTENT BTU/# WORKING FLUID

/ WE-LLHEAD / CON^ ITION COUDEUSIN(I STEAM

/ CON DENSING /

FIGURE 3

FLUID VAPORIZER

COOLlhiG

WATER

CIRCULATING

TURBO-GENERATOR

kl=m I SECONDARY CYCLE

\ / . COOL1 NG --._-.

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FIGURE- 4 THE BEN HOLT CO.

""' COMPOUUD BINARY CYCLe (DUAL)

<us.-"

C P R I

CYCLE POIHTS

COND. TEFlP.= 1 0 4 . 4 COND. PRESS.= 57.8

CONDENSEE DUTY= 14i.'E.48ETU/=

VAP. IftLET TEMP.= 103.5 PUMP D I S C H . P = 550.0

EXP. TEMP.= 310. 0 OP. PRESS.= 500 .0

EXP OUTLET- T = 137.0 P = 59.s H = 146.648

V= 1.472355

TC = 786.410 PC = 5 3 1 . 4 7 0 MOL. UT. = 65.14

COMPl X = 0.500 COFlP2 x = 0.500

C-W TEMP.= 9 0 . 0 C-W DT 26.5

CCND. AF'FEOACti = 14.4 COND. DP 2 . 0

VAP. HPPEOHCH = 1 5 . 0 VAP. DP = 50.0

EXP. EFF.= 0.650 P u w EFF.= 0 . 8 0 0

H.P. ENTR= 1.1563 L.P. ENTF:= 1.1599

CYCLE EFF. = 0 . 1 1 7 5

GROSS WORE = 24.529

6EN. OUTPUT = 2 4 . 0 3 3

PUPlPING WORK = 3.237

C.W. PIJMP = 0.700

C.W. FAN = 0.363 ------- HE1 WORK = 19.739

7'4

TABLE 2

TABLE 2 (Continued) HEfil1 tlG CVF'VE

T 1 = lOS.5 )I 1 = 3.237 v 1 = 0.028Z0.1

1 2 = 120.0 t i E = 9.%4 v 2 = 0 . 0 8 y 2

v 3 = 0.0,>.?292 1 3 = 140:o H 3 = 21.894

T 4 = 160.6 H 4 = 34.189 v 4 = 0.03nnz.?

T 5 = 180.0 tl 5 = 46.903 V 5 = 0. 031 Ciijc.

1 6 = 200.0 H 6 = 60.114 \' 6 E o.fJ::>rJg;.

1 7 = 220.0 H 7 = 73.450 V 7 = 0.0?3414

1 8 = 2 4 0 . 0 H 8 = b3.631 v 8 = 0.025136

T 9 = 2 6 0 . 0 t i 3 = 104.618 $/ 9 = 0.037544

T i 0 = 23u.0 H I 0 = 123. n:::;, ,410 = o.[l41:::Zo

1 1 1 = 290.0 H11 = 134.152 v 1 1 E [ I . (lJf583

T i 2 = 316.0 H l Z = 188.0:X V12 = 0.11:+1245

T13 = 317.0 H13 = 190.155 V 1 3 = 0. 104'335

114 = 315.0 H14 191.476 V14 0.108160

f l 5 = 319.0 H15 = 143.62'3 L'15 = 6.111059

1 1 6 = 320.0 H16 = 195.170 V16 = 0. 113751

1 1 7 = 321.0 H 1 i = 146.574 4 1 7 = 0.116130

718 = 322.0 4 1 9 = 197.929 v10: = 0 . 1 1 8 4 3

v 1 9 = 0.12(?;24 f19 = 323.0 H13 = 199. 193

fZO = 324.0 H20 = 200.421 V20 = O. l i2 .556

721 = 325.0 921 = 201.553 '$21 = 0.124551

T22 = 326.6 H2:,> = 2 0 2 . i S l v2,> t tj.l&:;G

T23 = 3 2 6 . 7 u,>3 ;1:14.6:5 ;?Is Ij.12152:

f 2 4 326.; u.24 = 204 .641 . i t 4 = o. 1315.33

125 = 323.9 H 3 = 201.610 v 2 5 = 0.1.?6741

T26 = 321.1 H2.j = 193.234 V Z 6 = 0.1212-97

127 = 319.4 H27 .I 144.488 b-27 = @.114+.84

128 315.6 H28 = 189.Ei05 \'E9 = O . l O i , > ? 9

129 = 312.8 H 2 9 = 182.850 v24 = 0.093i13

f 3 0 = 310.0 H30 = 171.177 V 3 0 = 0.074725

. . ~ O ~ 0 * * * ~ ~ ~ . 0 0 * 0 . . . 0 ~ 0 0 0 0 0 ~ * ~

* I -

CONDE~I~INI; CURVE

H 1 = 0.000 v 1 - 0.028421

H 2 = 34.410 V / F -0.243

T 1 = 104.4

T 2 - 108.8

3 = 113.2 H 3 = 60.409 V/F = 0 . 4 ~ 4 a

T 4 117.6 H 4 = 52.449 V/F - 0 . S i 6 7

t 5 = 122.0 H 5 - 102.766 V / F -0.7153

f 6 = 126.4 H 6 - 122.476 V/F -0.8534

T 7 - 130.9 H 7 - 144.133 V 7 - 1.4504615

7 5

Operating Working Fluid P r e s s u r e

Composition psia

Base Case - Isobutane Isobutane 80% iC4-20% iC5 80% iC4-20% iC5 80% iC4-20% iC5 80% iC4-20% iC5 20% C3-80% iC4 20% C3 -80% iC4 50% C3-50% iC4 50% C3-50% iC4 80% iC4-20% iC5 50% iC4-50% iC5 50% iC4-50% iC5 50% iC4-50% iC5 50% iC4-50% iC5 50% iC4-50% iC5 50% iC4-50% iC5 30% iC4-70k iC5 65% iC4-35% iC5 80% iC4-20% iC5

Dual Compound Cycle Treble Compound Cycle

DEPLETED

Base Case - Isobutane 2070 C3-80'70 iC4 2070 C3 -80% iC4 20% C3 -80% iC4 80% iC4-20% iC5

80% iC3-20% iC4 20% C3 -80% iC4 50% C3-50% iC4 50% C3 -50% iC4 35% C3-65% iC4 35% C3-65% iC4 35% C3 -6570 iC4

TABLE 3

THERMODYNAMIC ANALYSIS OF BINARY GEOTHERMAL POWER CYCLES

CASE STUDY SUMMARY

HEBER RESERVOIR

Operating Condensing Temperature Tempera tu re

" F " F

Geothermal Fluid Inlet Outlet

M Ibs Ihr Temperature Temperature

W o r k ~ n g Generator Fluid Output

M lbs /hr MWe --

P u m p ~ n g Cooling Tower Work Work MWe MWe

TABLE 4

THERMODYNAMIC ANALYSIS O F BINARY GEOTHERMAL POWER CYCLES

CASE STUDY SUMMARY

VALLES CALDERA RESERVOIR

Opera t ing Operating Condensing Geo the rma l Flu id Working G e n e r a t o r Pumping Cooling Tower Working Flu id P r e s s u r e Tempera tu r e T e m p e r a t u r e In le t Out le t F lu id Output Work Work

Composi t ion p s i a " F " F M lb s / h r T e m p e r a t u r e T e m p e r a t u r e M lb s / h r MWe MWe MWe

B a s e C a s e - Isobutane 600 80% iC4-10% iC5 600 50% iC4-50% iC5 600 20% iC4-80% iC5 500 80% iC5-20% C6 350 70% iC5-30% C6 320 90% iC5-10% C6 360 Isopentane 400

TABLE 5

THERMODYNAMIC ANALYSIS O F BINARY GEOTHERMAL POWER CYCLES

CASE STUDY SUMMARY

RAFT RIVER RESERVOIR

Operating Operating Condensing Geothermal Fluid Working Gene ra to r Pumping Cooling Tower Working Fluid P r e s s u r e Tempera tu re Tempera tu re Inlet Outlet Fluid O u t ~ u t Work Work Composition ps ia "F "F . M lbs /hr Temperature Tempera tu re M lbs /hr MWe MWe MWe

Base Case - Isobutane Propane 50% C3-50% iC4 50% C3 -50% iC4 50% C3-50% iC4 50% C3-50% iC4 35% C3-65% iC4 60% C3-40% iC4 60% C3 -40% iC4

ECONOMIC FEASIBILITY

In order to a s s e s s economic feasibility for the three si tes, the following s teps a r e necessary:

P r e p a r e est imates for both plant and field installations for each process at each site, a total of 18 estimates.

P r e p a r e operating and maintenance (O&M) cost es t imates for both plant and field installation for each process at each site.

Based on the foregoing est imates , calculate the selling pr ice of energy by the producer to the utility for each process a t each site.

Finally, estimate conversion and t ransmission costs for each process at each site.

P r e p a r e sensitivity analyses in o r d e r to examine the effect of various fuel pricing s t ra tegies on energy and power costs.

CAPITAL COSTS

Capital cost es t imates for the three Heber conversion options and for one Heber field installation a r e presented in F igures 5 , 6 , 7 and 8. would be let for design, procurement and construction and therefore represent the installed cost ready for operation.

These est imates a r e made on the basis that a single contract

Major equipment costs (i. e. , p r e s s u r e vessels, heat exchangers, pumps, cooling tower, turbine and generator) were based on vendor quotations. Construction i tems (i. e. , concrete, piping, s t ructural , instruments, painting, electrical , insulation, paving, roads, fencing and buildings) were based on mater ia l takeoffs and cur ren t unit p r ices of such mater ia ls . Indirect field costs and home office services a r e based upon experience in building facilities of s imi la r s ize and com- plexity.

The est imates include a contingency of six percent and an escalation of ten percent. increases in labor, mater ia ls and other costs which may occur between the first quarter of 1976 and the completion of the plant in ear ly 1980.

The la t te r f igure is expected to be sufficient to cover

79

The power plant costs for each process a t Heber a r e a s follows:

Million Dollars

Flashed s team 26. 8

Binary 28. 5

Hybrid 36. 6

These costs exclude the cost of land and any costs incurred by the owner associated with design and construction.

The cost of the surface installation for the binary plant at Heber is estimated to be $7,800,000. the injection pumps, production piping, injection piping and related installations. excluded. somewhat higher than would actually be incurred at the s tar t .

This cost includes the down-hole pumps,

The cost of completed production and injection wells is The cost is based on end-of-run conditions and is therefore

Table 6 installations a t each site. cost es t imates by prorat ing the cost differences in each category of work and each piece of equipment. These differences were fur ther adjusted to reflect local conditions. The est imates of t ransmission costs assume that a t Heber, the power is t ransmit ted to a load center at El Centro; at Valles Caldera, the power i s t ransmit ted to Los Alamos (about 20 miles) ; and a t Raft River the power is t ransmit ted to Burley (40 miles) . Table 7 .

presents capital costs for the power plants and t ransmission The plant costs were estimated f r o m Heber

Es t imates of surface installations a r e shown in

We expected that power plant capital costs a t Valles Caldera would be lower than at Heber because the r e se rvo i r is hotter. a r e somewhat higher in a l l cases , attributable to the high cost of construction in the a rea . installed costs would be 15 to 20 percent lower than the reported costs.

However, they

If these same plants were built at Heber,

Table 7 develop the three r e se rvo i r s for each of the three processes at each site. wells, dry holes and surface installations.

p resents an est imate of the initial capital requirements to

The est imates include the cost of producing wells, injection

The cost of the Heber wells of $300,000 each is pret ty close to our understanding of actual well costs in the relatively easy drilling character is t ics of the Imperial Valley. wells of $700,000 each i s much higher because of f a r more difficult

The cost of the Valles Caldera c 8 0

drilling conditions (young volcanic formations, deep wells, remote locations). guesses , since we have no actual data. of $600,000 i s close to actual published drilling costs for the area.

In this case the well costs a r e nothing more than educated The cost of Raft River wells

In each case, we have assumed that about 20% of the development wells will be dry holes. easi ly be low for a young volcanic formation like Valles Caldera.

Again, this f igure is an educated guess and could

Total well costs vary f r o m a low of $5. 9 million for the Heber binary process to a high of $24. 2 million for the Raft River flash plant.

The surface installation costs (including down-hole pumps for Heber and Raft River ) vary f r o m a low of $5. 9 million at Heber to a high of $18 million a t Raft River.

FIELD OPERATING AND MAINTENANCE COSTS

Table 9 p resents es t imates of field operating and maintenance costs fo r the nine cases. Table 8. field office burden and G&A is estimated to be $253,000. considered this cost to be a constant for all cases.

The est imate of the field staff portion is shown in The annual cost of the field staff including sa la r ies , benefits,

We have

Producing well maintenance costs a r e estimated f r o m suggestions made by Chevron f o r Heber a s follows:

1. Each producing well is acidized once p e r year a t a cost of $10,000.

2. Major remedial well work is done once every four yea r s for each well at a cost of $80,000.

3. Two of the original wells will be abandoned by the end of the project at a cost of $50,000 p e r well.

The annual cost for the Heber binary case is $368,000. other cases were prora ted by the number of wells.

Costs for all

Injection well maintenance costs were estimated on the following basis :

1. Each injection well i s stimulated once p e r year at a cost of $25,000.

81

2. Major remedial well work is done once every two yea r s for each well at a cost of $80,000.

3 . One injection well will be abandoned by the end of the project at a cost of $50,000.

Costs for all other cases were prorated by the number of wells.

Annual surface-installation maintenance (labor and mater ia l s ) is calculated at four percent of the initial capital cost f o r Heber and Raft River, where the wells a r e p u l p e d , and two percent a t Valles Caldera where they a r e not.

Down-hole surveys a r e figured at $1,000 p e r year per well.

The cost of pumping electricity was figured a t 2. 0 cents/kwh. the pumped wells this cost represents about one-third of the total operating and maintenance expense.

F o r

Total field operating and maintenance expense va r i e s f r o m $1,263,000 p e r yea r fo r the Valles Caldera binary plant to a high of $4,181,000 fo r the Raft River f lash plant.

The monthly operating and maintenance costs (excluding power) p e r well a r e in the range of $6,000, nearly twice a s high as would be expected fo r a typical oil well.

POWER PLANT OPERATING AND MAINTENANCE COST

Table 1 1 presents es t imates of power plant operating and maintenance costs for the nine cases. Table 10 is an est imate of the cost of power plant labor, including sa la r ies , benefits, field office burden and G&A expense. Labor cost is a constant fo r all cases.

Annual maintenance costs a r e figured as two percent of the initial plant cost. acre-foot. $20,000 per month at Heber, based on Imperial Irrigation Distr ic t ' s expenses at their El Centro plant. chemicals is estimated to be $253,000 for the Heber binary plant. Costs for a l l other cases a r e prorated by cooling tower duty. Total operating and maintenance costs a r e about 3 mills/kwh for a l l plants.

Cooling water makeup fo r Heber is purchased at $3 . 50 pe r Cooling water t reatment chemicals a r e estimated to cost

The total cost of cooling water and

82

COST O F GEOTHERMAL POWER

In estimating the cost of geothermal power delivered to a utility load, we assume that a privately owned producer will sel l thermal energy to an investor-owned public utility who will own and operate the power plant and t ransmission lines. Thus, there a r e three elements of cost to be considered.

1. Producer ' s selling pr ice of thermal energy to the utility

2. The utility's cost of generating electricity

3. The utility's t ransmission cost to a load center

There is a minimum selling pr ice below which a producer would not receive an adequate re turn on his investment and/or an adequate incentive to continue an exploration program and therefore would not enter into a contract to sel l thermal energy.

There is a lso a maximum pr ice which a utility can afford to pay for the thermal energy.

The Problem

The problem to be addressed in this study is two-fold in scope. first aspect is to estimate the cost of geothermal power for three processes at the three sites. The est imates must be made on a consistent basis so that comparisons a r e valid. i s to explore various fuel-pricing s t ra tegies and to evaluate the effect of these s t ra tegies on the cost of geothermal power. The approach to each of these problems is set forth in succeeding sections.

The

The second aspect

Production Risk Fac to r s

The business of exploring for and developing a geothermal hot-water r e se rvo i r is s imilar in all major respec ts to exploration and development of an oil field. In both cases exploration involves the gathering of geologic and geophysical data to select promising sites for leasing and subsequent exploratory drilling, followed by an analysis of the r e se rvo i r potential. involves drilling of wells and construction of above-ground facilities to collect the reservoi r f luids for sale to the customer.

In both cases development and production

The major differences a r e a s follows:

8 3

1.

2.

3 .

4.

5.

The geological and geophysical methods used successfully in oil and gas exploration a r e not necessar i ly useful o r may require some adaptation to be useful in a geothermal environment.

Drilling technology is about the same, except for the effect of temperature and the problems associated with drilling through rock rather than sedimentary formation.

Oil and gas may be t ransported to marke t and both a r e sold in national and international marke ts through well established marketing channels, whereas geothermal energy must be sold to a utility who will build the power plant in the producing field. Thus, the producer can get no income f r o m a geothermal reservoi r until the power plant is built and operating.

The utility must have confidence that the reservoi r will furnish thermal energy for an extended period of time (normally 30 years) .

Title to the geothermal water is not well established, unlike oil and gas r e se rvo i r s where there is seldom the problem of owner- s hip.

Thus, the r i sk fac tors a r e different between exploration and development of oil and gas on the one hand and geothermal r e se rvo i r s on the other hand, but the same cost-of-service approach used in the oil industry may be used for estimating the cost of fuel.

W e have developed a computer p rogram which calculates the cost of geothermal power delivered to a load center. The first element of this cost is the calculation of the selling pr ice of energy (i. e . , the fuel cost) to the utility.

Estimation of Fuel Cost

In estimating the selling p r i ce of fuel to a utility, we have used the cost-of- service approach. In this approach, we estimate the capital investment and operating costs associated with the development of the field. We then est imate a selling pr ice for the thermal energy which will give the producer a re turn on investment commensurate with the r isks .

The following procedure is built into the program to determine the cost of fuel for a par t icular case:

1. Reservoir Requirements

The amount of e lectr ical power desired and the energy con- vers ion process utilized will determine the amount of geothermal

8 4

fluid required a t a given site. character is t ics will indicate the necessary number of production and injection wells, the field layout and the required collection and distribution piping. With this information, the various costs involved with bringing the field into production can then be estimated.

A knowledge of the r e se rvo i r

2. Capital Inve s tment

The capital investment for a geothermal project is the money required by the project for which a re turn on investment is expected. that none of these funds a r e obtained by borrowing. ponents of the capital investment a r e a s follows:

F o r the purposes of this investigation, it is assumed ' The com-

a. Exdora t ion and Land Acauisition Costs

This represents the money spent in geological and geophysical r e sea rch , exploratory drilling, bonus payments and other costs involved with establishing the presence of an exploitable geothermal reservoi r . Since the r e se rvo i r will typically be sufficiently la rge to supply more than one power plant, only a proportional amount of this charge is assigned to the project under consideration. to the field development phase.

These costs a r e incurred pr ior

b. Well Drilling Costs

The costs of a drilling program to provide the required production and injection wells a r e continuously disbursed during the program. power plant.

The program culminates in the s tar tup of the

c. Working Capital

Working capital is required as of the s tar tup of the power plant. The working, capital is sufficient to pay one month's expenses, and is returned at the termination of the project.

d. Capital Additions

An additional annual drilling cost is required to provide additional wells in the field to offset the effects of a declining reservoi r . a capital requirement equal to the initial drilling costs but disbursed evenly over the life of the project.

Typical decline ra tes and project l ives indicate

The capital investments l isted above a r e expected to re turn a profit commensurate with the r isks involved in a geothermal venture. cash-flow method is used to determine the annual revenue requirements.

To account fo r the time value of money, the discounted-

3. Expenses

Several types of expenses a r e incurred during the operation of a producing geothermal field. These fall into two classes: cash expenses and book expenses. The book expenses a r e not deducted f r o m the revenues but a r e used in determining the taxable income for federal and state income taxes.

a. Cash Expenses

(1) Royalty Payment

Royalty payments a re typically 12. 57'0 of the gross revenues.

(2) Operating Expenses

Annual operating expenses include labor, maintenance, supplies, utilities, etc.

b. Book Expenses

Depreciation

Depreciation for tax purposes is calculated by the s u m - of-the-years-digits method for a tax life of 15 years . Depreciation for bookkeeping purposes is calculated by the sum-of-the-years-digits method over the life of the project.

(2) Intangible Drilling Expenses

These expenses a r e deducted in the year incurred. Since most of the drilling activities occur before any taxable income is produced by the project, it is assumed that the producer can take advantage of this deduction elsewhere to the credi t of the project. current ly in use in the oil industry, there is some question a s to whether it will a l so be available to the geothermal industry.

Although this deduction is

8 6

( 3 ) Depletion Allowance

This deductible expense, similar to depreciation, we assume to be 22% of gross revenue. been ruled applicable to geothermal in general.

However, it has not

4. Taxes

Federa l , state and local taxes will be paid by the project. federal and state income taxes a r e paid according to the net taxable income. deducted f r o m the federal income tax. tangible, depreciable asse ts of the project. The state and local r ea l property taxes a r e generally charged according to the value of the r ea l property. revenues produced by that property.

The

A federal investment tax credit of ten percent is The credi t is based on the

This is judged to be a function of the

Thus, these taxes a r e usually a percentage of the g ross revenues. They a r e t reated a s an ad valorem tax of ten percent in this study.

5. Annual Cash Flow

The cash flow is the sales revenues minus taxes and expenses not including depreciation. addition, this is a lso subtracted f r o m the cash flow. flow is then discounted at the desired ra te of re turn to a present worth at the beginning of power plant operations. The annual sales revenue is adjusted i teratively until the sum of the discounted cash flows equals the capital investment at the s t a r t of power plant operations. The sales revenue then becomes the cost of energy to the power plant.

Since there is a lso an annual capital The cash

Any of the pa rame te r s in the program can be easily a l tered to allow - - \-- ' sensitivity studies.

Estimation of Power Conversion and Transmission Costs

The balance of the program calculates the power conversion and t ransmission costs to a load center, using a method of economic analysis used by public utilities. cost is the sum of the energy cost, the utility's fixed charges, the operating and maintenance cost and the electr ical t ransmiss ion cost. The fixed charges a r e each expressed as a percentage of the invested capital. They are:

By this method, the delivered power

a 7

1.

2.

3 .

4.

5.

6.

Return on Investment

Current capital requirements a r e in the range of 11 to 13 percent.

Income Tax

The method used takes the expected annual taxes over the life of the power plant including provisions for investment tax credit and in te res t deductions and converts them to a uniform annual "levelized" expense. a 50-50 debt/equity ratio.

An in te res t r a t e of nine percent is used with

DeDreciation

The depreciation expense is often calculated by the straight-line method, but for economic analysis the sinking-fund method is generally used. case uses the sinking-fund method (at the ra te of return).

The p rogram can use either method, but the base

Ad Valorem Tax

This accounts for the various property and ad valorem taxes. typical value is 2. 5% of capital cost.

A

Administrative and General Expense

This is typically one percent of capital cost.

Insurance

This is typically one-tenth percent of capital cost.

The operating and maintenance costs will vary depending on type and location of plant. charges and operating costs. The fixed charges a r e calculated in the same manner as the power plant fixed charges.

The t ransmission costs a r e divided into fixed

The p rogram gives the annual delivered power cost and a l so uses the load factor (typically 85%) and the plant size to determine the unit power cost (mills/kwh). flows for the geothermal field.

Also included i s a printout of the yearly cash Table 12 is a sample printout.

Base- Ca se Results

Our f i r s t t ask is to compare delivered power costs for the nine base cases . These comparisons should be done on a consistent basis in

88

order to obtain good relative values but may not represent best absolute values. These cases a r e based on the following assumptions:

Project life 25

Exploration cost, K $ 800

Lease bonus payment none

Producer ' s DCF rate of return, 70 15

Utility ra te of return, 7 0 12

Depletion, 70 2 2

Write -off of intangible drilling expense, 70 70

Write -off of dry-holes expense, 70 100

The producer 's capital costs and operating and maintenance (O&M) costs, together with the utility's capital costs and O&M costs, were taken for each case from Tables 6 , 7, 9 and 11. taken as the typical values reported in the preceding section. The results a r e tabulated in Table 13.

Other input data were

The Heber binary case shows the lowest fuel cost of the three Heber cases (16. 69 mills/kwh) and the lowest power cost (35. 22 mills/kwh). The flashed s team cost at Heber is about 2 . 9 mills higher than the Heber binary, while the hybrid is about 5 .3 mills higher than the Heber binary.

At V a l l e s Caldera, the binary cost is again the lowest (33. 69 mills) by a la rger margin (5. 85 mills) over the flashed steam. The hybrid cost is the highest of the three (42.99 mills) but by a smal le r margin than at Heber.

At Raft River, the binary cost is lowest (55. 17 mi l l s ) by a substantial margin (about 15 mills) over the other two.

Fuel costs a r e low at Heber (16.69 mills) for the binary case, reflecting the relatively high well productivity and the relatively low cost of drilling. Binary fuel costs a t V a l l e s Caldera a r e slightly lower than at Heber, even though well costs a r e much higher ($700, 000 versus $300, 000), and well productivity is much lower; i. e . , 113, 000 kg/hr (250, 000 l b s / h r ) versus 295, 000 kg/hr (650, 000 lb s /h r ) .

/

8 9

These increases a r e offset to a large extent by the decreased brine requirements of 1 . 19 M kg/hr versus 3 . 1 M kg/hr ( 2 . 6 2 M lbs /h r ve r sus 6 . 9 M lbs /hr ) .

f-

Raft River costs a r e high in all counts, reflecting the low temperature of the reservoi r as compared to the others.

Utility fixed charges plus O&M expenses vary from a little over 18 mills (Heber binary) to a l i t t le over 20 mills (Raft River binary). variation is not nearly as great as the variation in fuel cost for the best cases, 16.0 mills to 3 2 . 8 mills.

This

Fuel cost expressed as cents/M Btu extracted is in the range of 60 cents/M Btu a t Heber, increasing to about 80 cents/M Btu a t Valles Caldera, o r over $ 1 . OO/M Btu a t Raft River.

We eliminated hybrid systems f rom fur ther consideration since hybrid costs were higher than the others . although the hybrid fuel cost was low at the three si tes, the power plant w a s the mos t expensive. One reason for the high cost power plant is that we have provided separate turbine -generator installations for both the s team-flash and binary sections of the plant, If it were possible to put both turbines and a single generator on one shaft, the capital cost would be reduced considerably. This prospect requires fur ther study.

It should be noted in passing that,

Raft River costs a r e important a s an indication of costs whichmay be expected in developing low - temperature reservoi rs . such r e se rvo i r s mus t be highly productive to be economic power sources .

It is c lear that

Heber versus Valles Caldera

Our best case at Valles Caldera is about 1 .5 mills lower than the best case at Heber. speculative than at Heber. F o r one thing, we have no reliable data on field development costs, and these costs could either be higher or lower than estimated by a substantial margin. optimistic assumptions relative to the cost of providing cooling water, the scaling and corrosion tendencies of the brine and the noncondensable content of the brine. Any one o r a combination could lead to substantial increases in power plant cost. have probably understated Valles Caldera power costs and that the cost of power at that r e se rvo i r is likely to be grea te r than projected. F o r this and other reasons we have focussed our attention on the Heber r e se r voir.

Our cost projections at Valles Caldera a r e m o r e

We have likely made

Our judgment is that we

9 0

Sensitivity Analysis

We have previously stated that the power costs presented in Table 13 a r e expected to give good relative values between r e se rvo i r s and between processes , but a r e not necessar i ly valid in absolute sense. Accordingly, we have made a study of the effect of changes in key var iables entering into the economic model. We have limited these comparisons to the Heber binary plant. in Table 14.

These resu l t s a r e tabulated

Case 2 a s sumes that we have overestimated field capital and operating costs by 20%. 16. 7 mil ls to 13. 5 mi l l s and the power cost f r o m 35. 2 mills to 32. 0 mi l l s .

The effect is to reduce the fuel cost f r o m

Case 3 assumes that we have underestimated field capital and operating costs by 20010, in which case fuel cost and power cost increase by 3 . 2 mills.

In case 4, we assume that no wells will be dril led during the life of the project, thereby reducing fuel cost by 0. 8 mill

In cases 5 and 6, we have var ied the producer ' s r a t e of re turn down to 10% and up 200/0. and the higher ra te of re turn increases fuel cost by 3.5 mi l l s .

The lower ra te of re turn reduces fue l cost 3 m i l l s ,

In case 7, the effect of eliminating both depletion and intangible wri te- off is to increase fuel cost by 4. 1 mi l l s .

In case 8, the effect of eliminating depletion i s to increase the fuel cost by 1 mill.

In case 9, the effect of eliminating the intangible write-off i s to increase fuel cost by 2.2 mi l l s .

In cases 10 and 11, the effect of reducing project life to 20 yea r s o r increasing to 30 years is relatively small: plus 0 .4mi l l . instance and minus 0 .2 mill in the second instance.

In cases 12 and 13 we examine the effect of reducing the power plant r a t e of re turn to 10% and increasing it to 14%. In the first instance, the effect is to decrease the power cost by 2. 5 mills, and in the second instance to increase power cost by 2.6 mills.

91

F r o m the foregoing, it is apparent that the prediction of power costs may vary widely depending on the par t icular se t of assumptions entering into the calculation.

The analyses do not take into account that only prel iminary optimization of the plant design has been made. important point, since we did not have producing costs available when the prel iminary optimization studies were made, present judgment is that the optimum design will be in the direction of higher power plant costs and lower brine consumption. We think that the cost reductions associated with optimization of the binary cycle will be grea te r than by optimization of the flash cycle.

This is a particularly

Our

No recognition is given to the economies which may resul t f r o m a full development of the reservoi r . expenses in par t icular will be spread over a wider base.

Overhead and maintenance

No allowance i s made for increased plant capital and operating costs which may be incurred at the end of the project due to temperature decline. savings resulting f r o m ful l field development.

This factor will be offset somewhat by the

We cannot hope to know a s much about a producer ' s o r a utility's business pract ices and costs a s these firms do themselves. Their methods of economic analyses may provide significantly different numbers .

Selection of the P r o c e s s

In o rde r to justify the construction of a 50 MWe plant, the cost of the power generated should be competitive with the cost of alternative sources of power available to the utility.

The near t e r m (by 1980) viable alternative energy sources available to a utility in the southwest a r e coal-based o r oil-based. It is our impress ion that coal-based power is somewhat l e s s expensive than oil-based power and that a fa i r ly typical cost would be about 30 mills /kwh, while oil-based (burning low-sulfur fuel oil) would be somewhat higher, about 35 mi l l s /kwh.

The projected power costs a t Heber fo r the binary cycle a r e within this range. The flashed s team costs at Heber a r e 2. 8 mi l l s higher a t the start of operation. As the reservoi r declines, the flashed s team process must use increasingly l a rge r quantities of reservoi r fluid,

9 2

while the binary process can a l te r i t s operating conditions to minimize the increase. The effect of decreasing temperature can be seen in the comparison of the processes a t Raft River where the cost of power by the flashed s team process is 15 mil ls or 22% higher than the binary process . recommend that the binary process should be installed a t the Heber site.

On the basis of this difference in the cost of power, we

Fuel Pricing S t r a t e m

A contract for the sale of fuel by a producer to a utility is like a mar r i age where divorce is impossible. option of changing to a new sel ler o r a new buyer. different business objectives and philosophies. to government actions of one kind o r another. a major effect on their respective costs. the producer ' s costs a r e affected in a major way by government regulations with respect to depletion, write-off of intangible drilling costs , federal and s ta te income tax ra tes , property tax ra tes and income tax credits. Utility costs a r e affected by all of the foregoing (except those relating to depletion and intangible drilling costs) , and their income i s controlled by the public utility commission. affected in different ways by many other agencies responsible for enforcing environmental, safety and health standards.

Neither par ty has the pract ical Each par ty has

Each par ty is subject These regulations have

As we have already observed,

Both a r e

In our view the approach to a contract begins with a good-faith negotiation a s to the start ing fuel selling pr ice between the par t ies , based upon a unit weight of fluid, with stipulations regarding the minimum p r e s s u r e and temperature of the fluid. mechanism provides an incentive for the utility to generate power a s efficiently as possible.

This pricing

A second feature would be to include a demand and a n energy charge. This feature would protect the producers in the event of a decision by the utility to reduce power output. i n reverse to protect the utility if the producer were unable to provide an adequate supply of fuel.

The demand charge should work

Beyond this basic s t ructure of a contract there a r e many other mat te rs which must be settled. One of the knottiest is to devise a mechanism f o r coping with inflation (or deflation, f o r that mat ter) . This might be done by relating the fuel cost to one o r more of the recognized cost indicators. However, it seems s impler to agree on a n annual renegotiation of pr ice , i f required. ref lect any changes in tax s t ructure , government regulations, inflation and other mat ters .

This negotiation would

9 3

FIGURE 5

E S T I M A T E S U M M A R Y S H E E T

CUSTOMER

DATE 4/Z2/76 TOTAL

LOCATION Heber, Cel i fo: ACCOUNT

ia Materials

REV. NO. 0 Labor Subcontract

I100 I200 1300 I400 IS00 I600 I700 I800 I900 2800

Columns (incl. trays) Pressure Vessels Heat Exchangers F urnace/Heaters Pumps Boilers Cooling Towers Turbine & Generator Tanks Other Labor

213,000 2,700,000

213,000 2,700,000

i,132,000 1,132,000

1,800,000

155,000 200,000 200,000

7,900,000

200,000 1,640,000

360,000 400,000

TOTAL MAJOR EQUIPMENT

3100 Concrete 3200 Pipe, Valves, Fittings 3300 Structural Steel 3400 Instruments 3500 Painting 3600 Electrical 3700 Insulation 3800 Paving, Roads, Fences & 3900 Buildings

200,000 210,000

1,000,000 200,000 40,000

9,900 7 000

410,000 2,700,000 600, ooo

50,000 460,000

1,875,000 255 030 200,000 200,000

60,000

60,000 50, ooo 650,000 255 , 000 80,000

200,000

1,225,000

.sc. 20,000 100,000

3,845,000

11,745,000

471,000

6,753,000

16,650 006

2,824,030

175 50 000

1,750,000

2,20a,000

TOTAL CONSTRUCTION ITEMS

DIRECT F IELD COSTS

Indirect Field Costs (ae. 2)

TOTAL FIELD COSTS 12,216,000 3 , 300,000

8203 Home Office Services

SUB-TOTAL

9500 Sales Tax on Material

9200 Fee & Contingency

E s c a l a t i o n

TOTAL SELLING PRICE

707,000

2,600,003

2,600,000

828,500,000

9 4

FIGURE 6

E S T I M A T E S U M M A R Y S H E . E T

CUSTOMER

LOCATION Heber, Calif( ACCOUNT

I100 Columns (incl. trays) I200 Pressure Vessels 1300 Heat Exchangers 1400 Furnace/Heaters 1500 Pumps 1600 Boilers 1700 Cooling Towers 1800 Turbine & Generator I900 Tanks 2800 Other - Vacuum Equip

and etc.

Labor


3100 Concrete 3200 Pipe, Valves, Fittings 3300 Structural Steel 3400 Instruments 3500 Painting 3600 E:ectrical 3700 Insulation 3800 Paving, Roads, Fences & 3900 Buildings

TOTAL CONSTRUCTION ITEMS

DIRECT F I E L D COSTS

Indirect Field Costs (pg. 2)

TOTAL FIELD COSTS


i a Materials

283,000 1,280,000

451,000

6 , 880,000

406 , 000

9 J 30° J Oo0

200,000 750 , 000 200,000 300 , ooo

sc. 10,000

2,410,000

11,710,000

468,000

12,178,000

subcontract

1,600,000 200,000

1,aoo,ooo

10,000

100,000 50 , 000 425,000 200,000 100 , 000 200,000

1,085,000

2 , aa5 , 000

144,000

3 Jo29 J Oo0

XEV.NO. 0 Labor

400,000

400 , 300 350,000 400,000 100,000 30 , 000

90,000

970 , 000

1, j70,ooo 1,749,000

3 , 119 , 000

SUB-TOTAL


9200 Fee & Contingency Escalation

TOTAL SELLING PRICE

DATE 4/22/76 TOTAL

283,000 1,280,000

451,000

1,600,000 7,080,000

406,000

400,000

11,500,000

550,000 1,160,000 300, ooo b30,ooo 50, coo

1,375,000 200,000 200,000 200,000

4,465,000

15,965,000

2,361,000

18,326,000

2 , 971,000 21,297,000

703,000

2,400,000 2,400,000

$26,800,000

Page I of 1

9 5

F I G U R E 7

LOCAT~ON Heber, Cal i forn ia ACCOUNT

I100 Columns (incl. trays)

1300 Heat Exchangers

1400 Furnace/Heaters

IS00 Pumps 1600 Boilers

1800 Turbines & Generators 1900 Tanks 2800 Other - Vacuum Equip.

1200 Pressure Vessels

1700 Cooling Towers

and etc .

Labor


3100 Concrete

3200 Pipe. Valves, Fit t ings 3300 Structural Steel

3400 Instruments 3500 Painting 3600 Electrical

3800 Paving, Roads, Fences 8c 3700 Insulation

3900 Buildings

TOTAL CONSTRUCT~ON ITEMS

D I R E C T F I E L D COSTS

Indirect F ie ld Costs (pg. 2)

TOTAL FIELD COSTS



Materials Subcontract

272,000 2,i15,000

1,135 , 000

1,600,000 5,OOO,OOO

498,000 50,000

9,020,000 1,650,000 200,000

2,160,000 59, 000 562,000 425,000 171,000

50,000 1,317,000 701,000

h ’ i S C . 300, ooo 3332 000

324,000

4,664,000 1,938,000

13,684,000 3,58a,000

14,231,000 3 ¶767¶ 000

547,000 179,000

REV.NO. 0 Labor

271,000

271,000 440,000

2,206,000 354,000 41,000

3,041,000

9SOO Sales Tax on Material


Escalation

T O T A L SELLING PRICE

-==q TOTAL

272,000 2,115,000

1 , 135 000

1,600,000 5,000,000

548,000

271,000

10,941,000 640 , 000

4,425 , 000 916,000 637,000 50 , 000

2,018,000 333,000 300,000 324,000

9,643,000 I 20,584,000 1

820,000

3,300,000

39 300,000

$36,600,000

9 6

FIGURE 8


I O 8 NO. 7523 CUSTOMER EPR1 'LANT

REV.NO. n DATE 4/22/76 Productior. FL I n j e c t i o n

LOCATION Heber, C a l i f o ACCOUNT

ia Materials Labor TOTAL Subcontract

I100 I200 1300 1400

I500 1600 I700 I800 I900 2800

Columns (incl. trays) Pressure Vessels Heat Exchangers Furnace/Heaters

Pumps Boilers Cooling Towers Compressors Tanks Other

Labor

70,000

1,411,000

70,000

1,411,000

1,000 1,000

53,000 53,000

1,482,000

13,000 884,000

1,535,000

51,000 1,581,000

53,000

18,000 677,000

T O T A L MAJOR EQUIPMENT

3 100 Concrete 3200 Pipe, Valves, Fit t ings

3300 Structural Steel 3400 Instruments 3500 Painting 3600 Electr ical 3700 Insulation 3800 Paving, Roads, Fences& F 3900 Buildings

20,000

149,000

440,000 10,000 217,000

281,000 455 , 000 25,000

630,000 10,000 217,000

190,000

sc:.

TOTAL CONSTRUCTION ITEMS 'i20,ooo 836,000 1,368,000

2,850,000

114,000

2,964,000

2,924,000

4,459,000

882,000

5,341, 000

888,000

836,000 D I R E C T F I E L D C O S T S

indirect F ie ld Costs (pg. 2)

TOTAL F IELD COSTS

41,000

877,000


SUB-TOTAL 6,229,000

171,000

700, ooo 700,000

$7,800,000



Escalation

TOTAL SELLING PRICE

Page I of 1

9 7

c TABLE 6

ESTIMATED POWER PLANT AND TRANSMISSION CAPITAL COSTS

(ALL FIGURES IN $ K)

HEBER

BINARY

FLASHED STEAM

HYBRID

VALLES CALDERA

BINARY

FLASHED STEAM

HYBRID

RAFT RIVER

BINARY

FLASHED STEAM

HYBRID

PLANT

28,500

26,800

36,600

26,500

28,100

37,600

32,300

35,900

39,800

9 8

TRANSMISSION

500

500

500

1,900

1,900

1,900

3,600

3,600

3,600

I T E M -

PRODUCING WELLS

No. of We l l s x C o s t / W e l l

C o s t

INJECTION WELLS

No. of We l l s x C o s t / W e l l

C o s t

DRY HOLES

No. of Wel ls x C o s t I W e l l

C o s t

W E L L COST

TABLE 7

ESTIMATED INITIAL F I E L D CAPITAL COSTS

( A L L COSTS IN $ K)

HEBER VALLES CALDERA R A F T RIVER BINARY FLASH HYBRID BINARY FLASH HYBRID BINARY FLASH HYBRID

T O T A L F I E L D COST 11,800 14,350 12.200 =

1. Inc ludes dowh-hole pumps a t Heber and Raf t River

TABLE 8 c

POSITION

FIELD OPERATORS

ESTIMATED FIELD STAFF COST

(ALL FIELDS)

R.OUS TA BO U T

ELE C TR.IC-N INSTRUMENT SPECIALIST MECHANIC

FOREMAN

OFFICE MANAGER

MECHANICAL ENGINEER

PRODUCTION ENGINEER

NO. O F RATE RATE HIRES $/MONTH $/MONTH

4 1,000 4,000

1 1,000 1,000

2 1,200 2,400

1 1,500 1,500

1 1,000 1,000

0.5 1,800 900

0.5 1,800 900

10.0 11,700

OVERHEAD::: 9,360

TOTAL MONTHLY COST 21,060

ANNUAL COST $253,000

::Overhead includes fringe benefits, field burden and G&A expense.

100

T A B L E 9

I T E M -

ESTIMATED F I E L D O P E R A T I N G AND MAINTENANCE COSTS

( A L L F IGURES IN $ &'YEAR)

H E B E R VALLES CALDERA R A F T RIVER BINARY FLASH HYBRID FLASH HYBRID BINARY FLASH HYBRID BINARY

F I E L D LABOR (INCLUDING OVERHEAD & G&A)

2 5 3 253 253 253 253 253 253 253 253

PRODUCING W E L L MAINTENANCE 368 4 9 1 398 337 428 368 521 767 675

INJECTION W E L L MAINTENANCE 3 93 524 393

SURFACE INSTALLATION MAINTENANCE 2 3 6 256 240

DOWN HOLE SURVEYS 18 2 4 19

MISCELLANEOUS S U P P L I E S 4 0 53 45

PURCHASED POWER 665 885 702 - - -

TOTALS 1,973 2.486 2 ,050 - - - - -

TABLE 10

POSITION

ESTIMATED POWER PLANT LABOR COST

OPERATORS

LABORER

ELECTRICIAN INSTRUMENT SPECIALIST MECHANIC

OFFICE MANAGER

SUPERINTENDENT

NO. O F RATE RATE HIRES $/MONTH $/MONTH

9 1,000 9,000

1 75 0 750

2

1

1

14

1,200

1,000

2,000

2,400

1,000

2,000

15,150

OVERHEAD >:: 12,120

TOTAL MONTHLY COST 27,270

ANNUAL COST: $327,000

*Overhead includes fringe benefits, field burden and G&A expense.

102

TABLE 12

INPUT URTR

TOTAL

$9S,214. $ 5 9 000.

POLJER RfiTE = 35.223 MILLI/KlrJH

104

T A B L E 1 2 (Continued)

P AYO UT E. . 1 YEAPI:

105

TABLE 13

ESTIMATED GEOTHERMAL POWER COST - BASE CASES

B rine Fuel Cost Power Cost (milslkwh) Rate d p e r 6 p e r Fixed Operating &

Case

Heber

K # /h r K # Brine M Btu Fue l Charges Maintenance Transmiss ion Total

Binary

Flashed Steam

Hybrid

P 0 cn Valles Caldera

Binary

Flashed Steam

Hybrid

Raft River

Binary

Flashed Steam

Hybrid

TABLE 14

Conditions

SENSITIVITY ANALYSIS - GEOTHERMAL POWER COST

BASIS: HEBER BINARY

Power Cost - mils lkwh Fixed Operating &

Fue l Charges Maintenance Transmiss ion Total

Base Case (includes depletion 16. 7 15. 0 3.2 and intangibles write -off)

Lower Field Capital and 13. 5 15. 0 3.2 Overhead & Maintenance - 207'0

Higher Field Capital and 19. 9 15. 0 3.2 Overhead & Maintenance - 207'0

Field Decline - 070 15. 9 15. 0 3.2

Field Rate of Return - 1070 13. 7 15. 0 3.2

Field Rate of Return - 2070 20.2 15. 0 3.2 0.3 38. 7

No Depletion & Intangibles 20.8 15. 0 3.2

Depletion Only 17. 6 15. 0 3.2

Intangibles Only 19. 9 15. 0 3.2

Projec t Life - 20 Years 17. 1 15. 2 3.2 0.3 35. 8

Projec t Life - 30 Years 16.5 15. 0 3.2 0.3 35.0

Power Plant Rate of Return - 1070 16. 7 12. 6 3.2

Power Plant Rate of Return - 147'0 16. 7 17. 6 3.2

IDENTIFICATION OF TECHNOLOGY WEAKNESSES

There appear to be no ser ious technology weaknesses associated with the design of steam-flash cycles. operation for a number of yea r s i n New Zealand, Japan and Mexico. Established steam turbine manufacturers offer two- stage, double-entry s team turbines on a guaranteed performance basis. Corrosion and erosion have been a problem but not a ser ious hindrance.

Such plants have been in successful

No binary cycle plants have been built in this country. The Russians a r e reported to have a small plant in geothermal service, and the Japanese have a 3 .8 MWe plant recovering energy f r o m waste heat and employing F reon a s a working fluid. soon be in operation in the Imperial Valley. nominal 10 MWe isobutane t e s t loop but no expansion turbine. the exception of the expansion turbine, the major equipment is available

lines.

The Niland t e s t facility will This plant contains a

With

. f r o m established manufacturers as a pa r t of their standard product

HYDROCARBON TURBINES

Both axial and radial turbines have been proposed for this project. Both types of turbines have been used in industry for many yea r s and a r e considered to be safe and reliable. However, neither type of turbine has been designed for hydrocarbon service in the range of capacities needed.

The Axial Turbine

General Elec t r ic and Elliott proposed to supply axial turbines. turbines have been built by both companies in the 50 MWe range for s team service, but this type of turbine has not been used in hydrocarbon service.

Axial

Conversion f r o m one fluid to another in turbine service has been practiced for many yea r s , and consequently this modification should not affect the predicted performance. turbine represents an innovation that will require engineering development work.

However, the design of such a

108

The Radial Turbine

The Rotoflow Corporation has proposed to supply a 65 MWe turbine installation made up of three radial turbine elements. would consist of a single-flow turbine in one casing and a dual-flow turbine in a second casing, all mounted on a single shaft.

The assembly

Rotoflow is experienced in the design of radial turbines in hydrocarbon service. capable of delivering 7 MWe of e lectr ic power. would consist of three turbine wheels each rated a t 2 2 MWe. Thus, the scale-up of the turbine element is about 3/1. This degree of scale-up does not appear to represent a major change in turbine design. How- ever , it does represent an extension of the present state of the a r t and will require fur ther engineering development.

The la rges t unit they have built is a single-flow turbine The proposed unit

An independent design effort by qualified consultants, comparing the two types of turbines and evaluating final proposals, appears to be justified.

Speed Control

All the turbines proposed by vendors a r e designed to operate a t 3600 rpm and will not need a speed-reducing gear. The turbines will be brought up to speed before the generator is connected to the electr ical t ransmiss ion system. After it is connected, it will continue to rotate at 3600 rpm, the synchronous speed of the electr ical system.

The p r imary turbine controls include the following:

1. A load control which regulates the flow of hydrocarbon to the turbine.

2. An overspeed t r ip and valve(s) to stop the flow of motive fluid to the turbine in the event the turbine speed exceeds a specified value.

Both General Elec t r ic and Elliott have extensive experience in the control of turbines which a r e used to drive generators , and R.otoflow has said that their controls a r e suitable. All the vendors c la im that their control system will provide stable turbine operation for normal conditions, with load- shedding capability and overspeed protection.

Because of the relatively low m a s s of the hydrocarbon turbine a s compared to a typical s team turbine, some special problems of adapting

109

the s team turbine control sys tem to a hydrocarbon turbine may be encountered. While this problem is not in our judgment a ser ious constraint, a study by qualified consultants may be justified.

DOWN-HOLE PUMPS

The pumps so f a r used to produce geothermal fluid f r o m intermediate temperature wells a r e modified deep-well pumps which consist of an electr ic motor dr ive located at the well head, a long shaft stabilized by bearings located along its length, and a multi-stage centrifugal pump located at the base of the shaft. This type of pump has been used successfully in Iceland in supplying hot water to the City of Reykjavik. f i l tered water f r o m the surface down the bearing tubing, thereby pro- tecting the bearings f r o m contact with the well fluid. mater ia l s a r e available fo r fabrication of the bowls, impel lers and pump bearings. Heber using the same type of pump and solved more o r less successfully.

Shaft-bearing wear has been minimized by pumping

Suitable

Various difficulties were experienced by Chevron a t

We regard this type of pump as the only state-of-the-art pump available but recognize that successful low maintenance operation may not be realized fo r some time.

Other pumps have been proposed which would eliminate the shaft lubrication problem. follows:

The different technical approaches a r e a s

1. A down-hole turbine pump and exchanger. F r e s h water is vaporized by exchange with the well fluid, and the s team produced is expanded in the turbine to pump the brine to the surface.

2. A down-hole pump operated by a down-hole e lec t r ic motor.

3 . A down-hole pump and hydraulic motor driven by water pumped f r o m the surface.

These three concepts have not yet been field tested, and considerable development work may be required before they can be used in a com- m e r cia1 ins tallation.

Improvements in the state-of-the-art a r e needed as well as new developments. weakne s s.

F o r these reasons down-hole pumping is a technical

110

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

SCALE DEPOSITION

The deposition of scale on heat exchanger tubes occurs when geothermal fluids a r e cooled to their saturation point. A se r i e s of tes t s were performed at the Heber reservoi r in 1976 to measure the effect of scale deposition on heat exchanger performance. The resul ts of these tes t s indicated that scale deposition does occur on the tubes. The amount of scale formed during the t e s t s was small , but it was sufficient to show that the rate of formation increased as the temperature of the brine was reduced. the longest one was 22 days, and the data f r o m this relatively short- range tes t was extrapolated to predict performance over a year. Fu r the r extended duration heat exchanger tes t s appear justified to establish the r a t e of deposition of scale as a function of temperature and time.

The tes t s var ied in length, but

CORROSION

Each of the geothermal fluids differ f r o m one another in salinity, pH and concentration of anions and cations. Even different wells in the same re se rvo i r can produce fluids with different chemical properties. The corrosive character is t ics of each reservoi r should be established before the final materials selection fo r the plant takes place. should be conducted for a sufficient length of t ime to identify if oxi- dation, s t r e s s corrosion, o r pitting could be expected in the plant. Different mater ia l s should be tes ted to establish what degree of corrosion protection would be needed. Corrosion work could most expeditiously be ca r r i ed on concurrently with scale deposition tests.

Tests

HYDROGEN SULFIDE DISPOSAL

Most geothermal fluids contain carbon dioxide along with small quantities of hydrogen sulfide. va ry f r o m t r ace amounts to significant percentages which exceed allowable limits for atmospheric disposal. produce vapor, these gases will be released and must be removed f r o m the system.

The amount of hydrogen sulfide can

If the fluid is flashed to

Most processes that a r e designed to absorb hydrogen sulfide will a l so absorb the carbon dioxide. which will do the job, but this process is complex, and the equipment i s costly. Additional development work is needed in this field to develop a simple method of disposing of the hydrogen sulfide in a manner that is compatible with environmental controls.

An exception is the Stretford process

111

SELECTION O F THE RESERVOIR

The selection of Heber o r Valles Caldera f o r the si te of the demon- s t ra t ion plant is based on the rating of appropriate c r i te r ia as se t forth in Table 15, which summar izes the findings developed during the course of this study. bility of reservoi r development and the socioeconomic impact of geothermal development in the Imperial Valley. Procon has made a prel iminary environmental assessment of Heber and Valles Caldera (with seismic, subsidence and geological input by Geonomics). Holt in this repor t has developed the technical feasibility of the conversion options and, with assis tance f r o m Procon in capital cost estimating, has made an economic analysis of the conversion options of each site.

Geonomics has reported on the technical feasi-

Table 15 se t s forth ten c r i te r ia for reservoi r selection and then ra tes each cr i te r ia (somewhat subjectively) on a scale of 10 to 0. r e se rvo i r rates ve ry well on all c r i te r ia fo r a n overall rating of 92. Valles Caldera 's overal l rating is 63.

The Heber

One major problem at Valles Caldera is that there is l i t t le hard data available on which to base a r e se rvo i r evaluation o r to make technical and economic evaluations (rating of 2). Cooling water availability is a ser ious constraint at Valles Caldera and ra tes a 2. Valles Caldera does not match the representative r e se rvo i r as well a s Heber and r a t e s 4 in this category. Well productivity is low and well cost is high at Valles Caldera, so this factor c a r r i e s a low rating of 4. Otherwise the ratings a t Valles Caldera a r e only a little lower than at Heber.

The ratings of the c r i te r ia show that at each point of comparison, the Heber s i te was either equal to o r superior to the Valles Caldera site. This difference is in p a r t due to lack of information about some factors at Valles Caldera, but in other cases the information that is available c lear ly indicates that Heber is the bet ter site.

The projected power costs a t Heber for the binary process and for the flashed s team process a r e close to the estimated power costs for coal and oil. engineering design and equipment optimization is completed. There- fore , on the bas i s that geothermal power can compete with other sources of power, there is ample justification f o r a power conversion plant a t Heber ra ther than at Va l l e s Caldera.

We expect that these costs can be reduced when a complete

112

CRITERIA

R e s e r v o i r should suppor t 200 MWe f o r 30 years .

Re l l ab l e da t a should be a v a ~ l a b l e to define size and c h a r a c t e r i s t i c s of r e s e r v o i r .

R e s e r v o i r c h a r a c t e r i s t i c s , s h o u l d be c lose to r ep resen ta t ive r e s e r v o i r .

Wel ls should be p roduc t ive , and success fu l re inject ion should have been p rac t i ced .

B r i n e should b e noncor ros ive and nonscallng, o r wel l demons t r a t ed methods of combat t ing both should be avai lable

T h e r e should be a demand fo r e l e c t r i c power within a r ea sonab le dis tance.

The c o s t of power should be compet i t ive with a l t e rna t e s o u r c e s of new power

T h e r e should be a n a s s u r e d supply of coollng w a t e r avai lable .

T h e r e should be no overriding environmental cons t r a in t s .

T h e r e should be no ove r r id ing soc ioeconon~ ic cons t r a in t s .

TABLE 15

CRITERIA F O R RESERVOIR SELECTION

HEBER COMMENTS RATING

R e s e r v o i r m o r e than adequate .

Good data a r e a v a ~ l a b l e .

Hebe r i s good match. It i s low sal in i ty (15,000 ppm) and m e d i u m t e m p e r a t u r e - 182 C (360 F).

Hebe r i s OK on both counts .

Good data avai lable on both counts . B r i n e i s re la t ively benlgn

50 MWe can supply loca l needs . F u l l f i e ld development r e q u l r e s new t r a n s m i s s i o n l ine to San Diego.

A p p e a r s t o be competitive.

OK on s h o r t t e r m . P r o b l e m s , probably su rmoun tab le , on long t e r m .

Min ima l p r o b l e m s a s s o c i a t e d w ~ t h a l r qual i ty , w a t e r qual i ty , subs idence and s e i s m i c e f f ec t s .

Min ima l i m p a c t a f t e r const ruct ion. Will i n c r e a s e employmen t and Improve tax base .

VALLES CALDERA COMMENTS

R e s e r v o i r probably m o r e than adequate .

Very l i t t le da t a avai lable .

Val les Ca lde ra I S f a l r match. It 1s low sa l lmty ( 5 , 000 p p m ) bu t f a i r ly high t e m p e r a t u r e - 260 C (500 F).

Well product ivi ty probably low; r e in j ec t ion h a s been c a r r i e d out but no data avai lable .

No h a r d da t a avai lable . If c o r r o s i o n and s c a l e a r e p r o b l e m s , me thods a r e ava i l ab l e to comba t t hem.

New M e x ~ c o Publ ic S e r v i c e can take output, but need i s l e s s than a t Hebe r .

Not quite s o compet i t ive .

P robab ly not ava i l ab l e excep t a t high cost .

Min ima l p r o b l e m s excep t f o r power c o r r i d o r s .

Min lma l impac t a f t e r const ruct ion will i n c r e a s e employmen t and Improve tax base .

RATING

10

2

4

4

9

8

TOTALS

RE COMMENDATION

On the strength of this study, the Heber geothermal field in California i s recommended as the best site for a low-salinity hydrothermal demonstration plant. If a demonstration plant is' constructed, the power conversion system should be based on the binary cycle, and the capacity of the plant should be in the 50 MWe range.

c 114

APPENDIX

TEMPERATURE ENTHALPY DIAGRAM

TWO PHASE ENVELOPES OF T Y P I C A L BINARY CYCLE F L U I D S

PROPANE - ISOBUTANE

TEMPERATURE ENTHALPY D I A G R A M

TWO PHASE ENVELOPES O F T Y P I C A L B I N A R Y C Y C L E F L U I D S

ISOBUTANE - ISOPENTANE

- - - . - . . . . . . . - \ /80% I S O B U T A N E - 2 0 % I S O P E N T A N E / 41.

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