Evolution Overview

There is not a peer-reviewed literature on how much geothermal electric technology is likely to improve over time . However, there are published indicators that suggest hydrothermal-electric technology is immature and is frequentl y being improved along a number of fronts.

The estimated evolution of these systems assumes gradual improvements over time of many subsystems an d components ofthe 1997 technology. Table 4 describes how some of the estimates of the cost of future technology were derived. Costs in that table are in 1997 dollars. The values in Table 4 reflect only some of the expected changes i n technology, and then only for the high-temperature (flashed-steam) system, and not binary or other technologies.

Expected technology improvements and their sources, in brief, are:

• Average cost per well: Mid-term: Improved diamond compact bits, and control of mud circulation. Long-term: Costs drop markedly through radical improvements in drilling technology now being pursued for oil , gas, and geothermal wells. Cost savings for shallow wells will be smaller than for deep wells.

• Wildcat exploration success rate: The current value here implies that, on average, five deep wells need t o be drilled to discover a new geothermal power-capable field. In the near-term (e.g., 10 years), most improvements will come from improved interpretations of local geology, in cross-comparison to geologie s in other geothermal fields. In the long-term, sophisticated improvements in geophysical methods will make drilling targets (large water-filled fractures) relatively visible.

• Flow per production well: Combined impacts of better completions and improved reservoir engineering . Improved completions will reduce formation damage near the wellbore. Improved reservoir engineering will increase the degree to which the wellbore penetrates large-scale permeability.

• Field O&M cost: The 1990's effects of power sales contracts, i.e., lower payments for energy, establishe d under PURPA (the Public Utilities Regulatory Policies Act of 1978) are now driving geothermal operator s to identify co st-savings opportunities in plant O&M manpower. Also a result of improved chemistry an d materials, but smaller effects than for power-plant O&M.

Table 2. Performance and cost indicators for a geothermal high-temperature system ("flashed-steam" technology).

INDICATOR

Base Case 1997

2000

2005

2010

2020

2030

NAME

UNITS

+/- %

+/- %

+/- %

+/- %

+/- %

+/- %

Plant Size

MW

47.9

47.9

47.9

47.9

47.9

47.9

Performance

Levelized Capacity Factor

%

89

5

92

5

93

5

95

5

96

5

97

5

Annual Energy Production

GWh/year

390

403

407

416

420

425

Power Plant Net Effectiveness

Wh/kg fluid

26.4

27.5

28.8

29.0

29.0

29.0

Average Flow/Well

1000 kg/hr

304

322

342

368

402

435

Average Cost/Well

$1000

1,639

1,557

1,311

1,229

983

820

Capital Cost

Wildcat Exploration

$/kW

46

10

44

+11/-10

32

+13/-10

25

+14/-10

17

+17/-10

12

+20/-10

Site Confirmation, Well Costs

100

î

93

76

69

53

43

Site Confirmation, Soft Costs

18

17

16

16

15

13

Siting & Licenses

64

64

64

64

64

64

Land (@ $5000/ha)i

1

1

1

1

1

1

Producing Wells & Spares

255

15"

224

174

154

115

90

Dry Production Wells

64

5"

53

38

31

22

15

Injection Wells

110

5"

96

74

64

47

37

Field Piping

47

10

41

36

32

28

23

Production Pumps

0

0

0

0

0

0

Power Plant

629

10

629

629

629

629

629

Owner's Costs

109

10

109

109

109

109

109

Total Overnight Capital Cost

1,444

--

1,372

1,250

1,194

1,100

1,036

Operations and Maintenance Cost

Field, General O&M & Rework

$/kW-yr

32.40

10

29.00

+11/-10

25.50

+13/-10

23.60

+14/-10

21.70

+17/-10

20.90

+20/-10

Makeup Wells

12.20

11.60

10.40

8.10

6.10

4.00

Relocate Injection Wells

2.70

2.60

2.30

1.60

1.10

0.50

Power Plant O&M

49.10

43.90

36.60

33.00

29.30

29.30

Total Operating Costs

96.40

87.10

74.80

66.30

58.20

54.70

Notes for Tables 2 and 3:

Plant construction period is assumed to require 0.8-1.5 years. Column sums and totals may differ because of rounding.

* Values depend highly on reservoir temperature, geology, and hydrology.

t The generic uncertainty factors (+10/-10, +11/-10, etc.) are explained in Section 4.2. i Assumes desert land. Would be higher in agricultural areas.

# Uncertainty is for cost per unit well.

Table 3. Performance and cost indicators for a geothermal moderate-temperature system ("binary" technology).

INDICATOR

Base Case 1996

2000

2005

2010

2020

2030

NAME

UNITS

+/- %

+/- %

+/- %

+/- %

+/- %

+/- %

Plant Size

MW

50.0

-

50.0|

50.0|

50.0

50.0|

50.0|

Performance

Levelized Capacity Factor

%

89

5

92

5

93

5

95

5

96

5

97

5

Annual Energy Production

GWh/Year

390

403

407

416

420

425

Power Plant Net Effectiveness

Wh/kg fluid

11.6

11.8

12.2

12.8

13.3

13.9

Average Flow/Well

1000 kg/hr

317

*

337

356

383

419

454

Average Cost/Well

$1000

492

*

467

443

418

393

344

Capital Cost

Wildcat Exploration

$/kW

21

10

20

+11/-10

16

+13/-10

13

+14/-10

10

+17/-10

4

+20/-10

Site Confirmation, Well Costs

29

î

27

24

22

20

17

Site Confirmation, Soft Costs

17

17

16

15

14

12

Siting & Licenses

64

64

64

64

64

64

Land (@ $5000/ha)i

1

1

1

1

1

1

Producing Wells & Spares

148

15"

131

115

98

82

65

Dry Production Wells

26

15#

21

18

14

11

8

Injection Wells

69

15"

61

53

45

37

29

Field Piping

35

31

27

23

19

15

Production Pumps

46

43

40

36

32

29

Power Plant

1,545

1,468

1,391

1,313

1,236

1,159

Owner's Costs

109

109

109

109

109

109

Total Overnight Capital Cost

2,112

1,994

1,875

1,754

1,637

1,512

Operations and Maintenance Cost

Field, General O&M & Rework

$/kW-yr

28.80

10

25.60

+11/-10

22.30

+13/-10

20.50

+14/-10

18.80

+17/-10

18.40

+20/-10

Makeup Wells

7.10

6.70

6.00

4.70

3.60

2.30

Relocate Injection Wells

1.70

1.60

1.40

0.80

0.30

0.10

Power Plant O&M

49.80

44.60

37.20

33.40

29.70

29.70

Total Operating Costs

87.40

78.50

66.80

59.50

52.40

50.50

Notes: See notes at the bottom of Table 2.

Technology Factor or Indicator

Units

1997 value

Performance or Cost Multiplier (relative to 1997 value)

2005

2010

2020

2030

a. Average cost per well

$K

1,639

.80

.75

.60

.50

b. Wildcat dry hole ratio

ratio

0.80

.95

.90

.80

.70

c. Flow per production well

1000 kg/hr

304

1.12

1.20

1.30

1.40

d. Field O&M cost

$/kW/yr

24

.75

.68

.62

.62

e. Power plant capital cost

$/kW

629

1.00

1.00

1.00

1.00

f.Plant net effectiveness

Wh/kg

26.4

1.09

1.10

1.10

1.10

g. Plant O&M cost

$/kW/yr

49

.75

.67

.60

0.50

h. Reservoir pressure decline:

%/yr

6

.85

.66

.40

.33

• Power plant capital cost: Expected to remain flat after mid-1990's large decreases in costs due to world-wid e competition among suppliers.

• Plant net effectiveness: Improved due to better matching to reservoir conditions.

• Plant O&M cost: Similar to impacts in field O&M costs, above. Also expect continuingly higher degrees o f automation in operation of power plants.

• Rate of reservoir pressure decline: The 6% decline per year set for Base Case (1997) technologies is higher than expected for fields developed at a reasonable pace. While this level of decline would require adding enoug h makeup wells to double the number of production wells by about year 20, its impacts on levelized costs and on the present value of reduced production in the final years are very small.

For hydrothermal electric systems as a whole, the estimated time to final commercial maturity is estimated to be 30 to 40 years. The time to maturity for major subcomponents is estimated as follows:

• Reservoir exploration and analysis technologies : 30 to 40 years. Substantial improvements in geophysica l sensors and data inversion processing can be expected to occur over a long interval [18]. Also, advances in computer modeling of geochemical systems and rock-water interactions will provide substantial new information about underground conditions and long-term production processes [19].

• Conventional drilling technology : 10 to 20 years. The pace here will depend mainly on the pace of hydrothermal commercial development during the next 10 years, and the degree to which the 500-fold larger market fo r equipment for drilling oil and gas wells in harder rock at higher temperature improves technologies that the n will spill over to improve geothermal operations [20].

• Advanced drilling technology: 20 to 30 years. Systems studies are in progress for drilling technologies tha t could substantially reduce the costs of both removing rock and maintaining the integrity of the wellbore durin g drilling and production (i.e., alternatives to conventional casing). Such systems would be applicable t o geothermal drilling under adverse conditions [21,22].

• Power plant technology: 10 to 20 years. Flash power plant technology is substantially mature, but analyse s indicate that a number of cost-effective modifications of designs are possible [4,23]. Binary power plan t technology is somewhat less mature [24,25].

Solar Stirling Engine Basics Explained

Solar Stirling Engine Basics Explained

The solar Stirling engine is progressively becoming a viable alternative to solar panels for its higher efficiency. Stirling engines might be the best way to harvest the power provided by the sun. This is an easy-to-understand explanation of how Stirling engines work, the different types, and why they are more efficient than steam engines.

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