Time years

25.0

30.0

Figure 4. Results of GEOCRACK HDR reservoir simulation.

drawdown in the reservoir depends primarily on the distribution of the fracture joints through which the fui d flows. With narrow joint spacing (10 meters or less), the temperature will remain fairly flat for the first 18 to 2 0 years, and then drop fairly rapidly over the following 8 or 10 years. For this analysis, it is assumed the temperature will remain constant for the first twenty years and then drop by 20 0oC (392oF) over the following ten years.

Other key technical assumptions include:

• Thermal dilation of the reservoir fractures will contribute to achieving projected flow rates

• Reservoir injection pressure is 3,000 psi (20,684 kPa) and reservoir production pressure is 1,000 ps i (6,895 kPa)

• Injection pump efficiency is 80% and pump motor efficiency is 95%.

• Well depth is 4,000 meters

Current Technology through Second Generation Technology employs a single triplet of wells. The technolog y in the year 2020 employs two triplets, and the Mature Technology employs 4 triplets.

The discussion below describes the basis for and calculations of the numbers in Table 1. The Second Generation and Mature technologies are referred to as the 2015 and 2030 technologies, respectively.

Net Brine Effectiveness (NBE) and Power Output: The net brine effectiveness is derived from Figure 5-2 of Reference [5]. For a plant inlet temperature of 226oC (439oF), the specific output is approximately 11.5 kW/1000 lb/hr brine. The parasitic power for injection and production pumps is about 9.8% of the ne t power [5]. Therefore, adjusting for injection and production pumping parasitic power yields:

specific output = 11.5 / (1 - 0.098) = 12.75 kW/1,000 lb/hr brine:

It is estimated by the authors that R&D can improve the NBE effectiveness in this temperature range by abou t 10%, and that this will be achieved incrementally by 2015.

System power output is the product of the net brine effectiveness, the number of well triplets, and the brine flow rate per well triplet. The net power output is the system output less the parasitic power required for injection. Power plant costs are based on the system power output.

Injection Parasitic Power: An injection pressure of 20,684 kPa (3,000 psi) and a production backpressure of 6,895 kPa (1,000 psi) is anticipated to maintain the desired pressure differential across the reservoir [6]. Th e plant outlet pressure is estimated to be 6,205 kPa (900 psi). To achieve the injection pressure, the injection pump must supply 20,684 - 6,205 = 14,479 kPa (2,100 psi). The required work rate to obtain a 223,600 kg/hr (1,000-gpm) flow rate, given a pump efficiency of 0.8 and a pump motor efficiency of 0.95, is given by

Pp = [(1,000 gal/min)K2,100 lb/in2)] / 1,714 / 0.8 / 0.95 = 1,612 hp * 0.747 kW/hp = 1,202 kW

Capacity Factor: Although capacity factors for many hydrothermal binary plants are over 90% (see th e characterization of geothermal hydrothermal technology elsewhere in this document), the capacity factor for th e HDR Current Technology system is limited to 80% to reflect the fact that HDR wells will be too expensive t o have any spare production or injection wells as is the practice with hydrothermal binary plants. Without spar e wells and only one triplet, production will drop by 50% when one of the production wells is under repair, an d by 100% when the injection well is under repair. The capacity factor is increased over time to reflect improve d well completion technology and reduced time required for well repairs due to operational experience. Also, th e capacity factor increases with increasing numbers of well triplets because a smaller proportion of the total flo w will be suspended when a single well is shut in for maintenance.

Exploration Cost: Exploration costs for the Current Technology are estimated by the authors to be $2 millio n based on their knowledge of hydrothermal exploration. Factors of 0.97, 0.94, and 0.90 are applied to the 1997 exploration cost for the 2005, 2010, and 2015 technologies, respectively. Factors of 0.85 and 0.80 are applied to the 1997 cost to reflect further technology cost reductions in 2020 and 2030, respectively. These estimate d cost reductions are based on the assumptions that both HDR R&D and HDR commercial experience will lea d to improved exploration technology for HDR resources. A factor of 1.5 is applied to the 1997 cost to account for the economy of scale achieved in doubling the size of the field for the 2020 technology. A factor of 2.5 is applied to the 1997 cost to account for the economy of scale achieved in quadrupling the size of the field for the 2030 technology. These economy of scale factors are arbitrary estimates made by the authors.

Land Cost: Estimated at $4,942/ ha ($2,000/acre) and requirements of 6.1 ha (15 acres) for the plant and one well triplet, 8.1 ha (20 acres) for the plant and 2 well triplets (year 2020), and 10 ha (25 acres) for the plant and 4 well triplets (year 2030).

Well Cost: The 1997 costs of $3.5 million per well are estimated by an experienced geothermal drilling engineer based on the costs of recently drilled deep (average depth of 3261 m, or 10,700 feet) geothermal wells in th e Basin and Range [6]. The $3.5 million includes all costs for drilling and completing a 4,000 m (13,124 ft) well. Well costs for the 2030 technology are estimated to be only 50% of those for the Current Technology. This is the authors' estimate of the greatest possible reduction in drilling costs that might be reasonably projected. It i s premised on 4 propositions: (1) Sandia National Laboratory states that "Advanced technology development...has the potential for reducing geothermal drilling costs by at least 30% [9]; (2) New technology is capable of providing radical reductions in drilling cost as evidenced by Unocal's reference to its Thailand operation s "Drillers learned to drill wells for 75% less the cost of wells in 1980" due to new technology [10]; (3) The Massachusetts Institute of Technology's National Advanced Drilling and Excavation Technology Institute ha s as its goal a 50% reduction in the cost of drilling [11]; and (4) In a 1994 study of future drilling technology, the National Research Council, an arm of the National Academy of Sciences, concluded "that revolutionary advances are within reach" and that "Rapid innovation in microelectronics and other fields of computer science an d miniaturization technology holds the prospect for greater improvements - even revolutionary breakthroughs - in these (drilling) systems." [12]

For the 2015 well cost, a factor of 0.80 is applied to the 1997 cost of $3.5 million per well to reflect cumulative incremental drilling and completion technology improvements. This results in a cost of $2.8 million per well . For the 2030 cost, as stated above, a factor of 0.5 is applied to the 1997 cost of $3.5 million per well to reflect further drilling and completion technology improvements. This results in a cost of $1.75 million per well . Factors of 0.95 and 0.90 are applied to well costs in 2020 and 2030, respectively, to reflect economies of drilling multiple wells at the same location.

Fracturing Cost: The Current Technology fracturing costs are based on experience at Fenton Hill and ar e estimated to be $3.09 million. The authors estimate that experience creating HDR reservoirs will result i n improved techniques by 2015 that will intensify fracturing sufficiently to gain 30% more flow through the same size reservoir with a proportional increase in the cost. This increased cost is offset partially by technolog y improvements (expected from the combination of HDR R&D and experience with commercial HDR applications) accounted for by applying factors of 0.95, 0.90, and 0.85 to the 1997 costs to reflect costs in 2005, 2010, and 2015, respectively. Thus, the 2015 cost of fracturing is 0.85 x 1.3 x $3.09 million, or 545 $/kW. Further technology improvements (expected from the combination of HDR R&D and experience with commercial HDR applications) will reduce the base cost by 17% and 20% in 2020 and 2030, respectively. Factors of 0.95 and 0.90 are applied to the fracturing costs in 2020 and 2030, respectively, to reflect economies of scale.

Fresh Water System Cost: The Current Technology cost is based on the cost of a fresh water well [4]. The cost remains unchanged through 2015. By 2030, it is reduced by 20% to reflect improved drilling technology . Factors of 0.95 and 0.90 are applied to the water system costs in 2020 and 2030, respectively, to reflect discounts for drilling multiple fresh water wells at the same location.

Injection Pumps Cost: Working from cost relationships adapted from Armstead and Tester [13], the installed cost of the injection pump and its electric motor drive is estimated to be $710k. A factor of 1.2 is applied to this cost for 2015 to reflect the 30% increase in flow (the relationship between pump cost and flow rate is not linear). For 2030, a factor of 0.9 is applied to the 2015 cost to reflect improved technology. Factors of 0.97 and 0.95 are applied to the injection pump costs in 2020 and 2030, respectively, to reflect discounts for buying multipl e pumps.

Power Plant Cost: The 1997 binary power plant cost is derived from cost data in Reference [5] for hydrothermal binary power plants. The plant cost is adjusted to account for the fact that downhole production pumps are not necessary with the HDR system. It is also adjusted to remove the embedded cost for injection pumps since th e HDR system will require larger injection pumps (which are included in the field costs in the HDR TC).

The difference s in the unit costs of the binary HDR plant and the binary hydrothermal plant (see geotherma l hydrothermal technology characterization) are attributable to three factors. The cost adjustments mentioned i n the previous paragraph and the higher inlet temperature for the HDR plant make it slightly less expensive tha n the hydrothermal binary. Also, it is assumed that there is an economy of scale inherent in the 50 MW binar y hydrothermal plant cost in Reference [5]. A scaling factor of 0.9 is used to adjust the 50 MW cost to the appropriate size in each given year. For example, for the Current Technology:

6.26 MW unit cost = 50 MW unit cost * (6.26/50)09/(6.26/50) = 50 MW unit cost * 1.2309

The unit cost for the HDR binary plant is derived from Reference [5] cost data in the following manner:

Field Cost (from Table 6-3, Reference [5], Vale resource):

production wells $24,705,882 injection wells $10,500,000 gathering system $ 1,333,187

Calculation of plant costs (1993 $/kW):

Total Project Cost

2,125

Figure 5-4 of 2/96 NGGPP

Field Cost

-731

Table 6-3 of 2/96 NGGPP, Vale resource

Injection Pumps

- 3

cost estimate

Production Pumps

- 38

cost estimate

Electrical Interconnect

+20

cost estimate

1,373

Power plant cost

Adjust to 1997 dollars:

1,500 $/kW

Extract economy of scale: 1.2309*1,500 = 1,847 $/kW

Extract economy of scale: 1.2309*1,500 = 1,847 $/kW

Binary power plant cost reductions due to technology improvements are estimated to total 25% over the entire period. This is allocated by applying the factors 0.95, 0.90, 0.85, 0.825, 0.80 and 0.75 in the years 2000, 2005, 2010, 2015, 2020, and 2030, respectively. This is based on reference [5], as well as the authors' combined 2 5 years of experience analyzing geothermal technology and R&D. The reader may refer to the characterization o f hydrothermal geothermal for further discussion.

Total Capital Cost: The total project unit cost is the sum of the individual costs listed above plus a project cos t of $109/kW [5]. The project cost covers the owner's administrative costs and plant start-up costs.

Operation and Maintenance Costs: HDR power plant O&M costs are estimated to be equal to those of a hydrothermal binary power plant. The reader is referred to the section on hydrothermal binary for a discussio n of binary power plant O&M.

Well field O&M cost components are taken from Reference [4] and adjusted to 1997 dollars. Daily operatio n and maintenance will cost about $218k/yr. This cost assumes one person's labor plus maintenance and repai r contracts. Additionally, hydrothermal wells require work-over and clean-out every one to two years dependin g primarily on brine chemistry. It should be possible to maintain a certain amount of control over the chemistr y in HDR wells, thus reducing the maintenance schedule when compared to hydrothermal wells. On this basis , it is assumed that each HDR well will need a work-over every three years; thus the site average will be one wel l per year.

Clean-out and work-over will require a work-over rig for about 15 days at $11k/day ($165k). Mobilization and demobilization of the rig will cost another $109k. Materials for work-over (wellhead, cement, casing, etc.) are estimated to cost between $164k and $545k. Using a mid-range value of $350 for materials yields an estimat e of $624k for work-over. Combining work-over and daily maintenance, well field O&M is estimated to cos t $842k/yr.

Uncertainty: Considerable uncertainty is inherent in projecting future costs and technology improvements. Thi s uncertainty is estimated subjectively with plus/minus percentage figures for key parameters in Table 1. Th e projections are for the very best technology that it is believed could be reasonably achieved, and so the estimates for uncertainty are weighted heavily toward lower performance, less improvement and less reduction in cost. The most uncertain estimates are the flow rate per triplet of wells and the 50% reduction in the cost of deep wells . Therefore, the uncertainty estimates for the flow rate are based on 20% less flow for the Current Technology and failure to achieve the 30% increase in flow rate for the Second Generation Technology. Also, the uncertaint y estimate for the well cost is based on achieving only a 30%, rather than 50%, reduction in the cost of wells . These two major uncertainties and other less significant uncertainties combine to result in the uncertainty for the total capital requirement. The uncertainty for the total capital requirement in the year 2030 is that it may cost 3% less than or 51% more than the projected $2,977 per installed kW of capacity.

Solar Stirling Engine Basics Explained

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