P ROCEEDINGS, 47 th Workshop on Geothermal Reservoir Engineering
Stanford University, Stanford, California, February 7-9, 2022
SGP -TR-223

Techno-Economic Performance of Eavor-Loop 2.0
Koenraad F. Beckers, Henry E. Johnston
National Renewable Energy Laboratory, Golden, CO
Koenraad.Beckers@nrel.gov

Keywords: Closed-loop geothermal, advanced geothermal systems, Eavor-Loop, techno-economic analysis
ABS TRACTThis project evaluated techno-economic performance for a sample Eavor-Loop 2.0 design for electricity production and direct-use heating.
The Eavor-Loop 2.0 design investigated is a 7.5-km deep closed-loop geothermal system consisting of 12 laterals for a total of more than
90 km of downhole well and lateral length. Both a high geothermal gradient scenario of 60°C/km and a low geothermal gradient scenario
of 30°C/km were considered. With pure water injected at 60°C and 80 kg/s, reservoir simulations with the Slender-Body Theory simulator
indicate average production temperatures over a 30-year lifetime of ~125°C and ~210°C for the low and high geothermal gradient scenario,
respectively. These correspond to heat production of ~22 M Wth and ~51 M Wth, respectively. Using IPSEpro simulations, we find average
power production of ~2.2 M We and ~8.6 M We , respectively, for a subcritical organic Rankine cycle power plant with air-cooled
condensers. Cost estimates indicate the overall capital and levelized costs are dominated by the lateral drilling cost. Obtaining a levelized
cost of electricity below $70/M Wh requires a geothermal gradient of 60°C/km, a discount rate below 9%, and lateral drilling cost below$400/m. A well cost model indicates that ~$400/m for the Eavor-Loop 2.0 design investigated can be obtained for a drilling rate ofpenetration about 40 ft/hr (with bit life of 50 hours), and omitting casing and cement. Traditional (geothermal) well drilling has achieved
these drilling rate conditions, including the Utah FORGE project where the rate of penetration has exceeded 50 ft/hr in granite. However,
it is unclear if these conditions are still valid for drilling the Eavor-Loop 2.0 laterals (i.e., ~82 km of laterals at 4 to 7.5-km vertical depthwith rock temperatures up to 460°C), as such downhole completion has never been developed before. Competitive levelized cost of heatvalues ($1.2-$8.2/GJ) are calculated, even for the low geothermal gradient scenario (30°C/km) and lateral drilling cost of $600/m.
1. INTRODUCTION
Advanced geothermal systems (AGS), also called closed-loop geothermal systems, are geothermal systems in which a heat transfer fluid—e.g., water or CO 2—circulates in a closed-loop configuration (i.e., without penetrating the reservoir) to extract heat from the subsurface
and bring to the surface. Proponents of AGS highlight its ability to develop geothermal anywhere, without the need for in-situ fluids orreservoir permeability. Challenges of AGS include a potentially complex subsurface completion, and typically low thermal output andrapid initial temperature decline due to a combination of low rock thermal conductivity and limited area for heat transfer between the fluid
and the rock. Simulations indicate that multi-M We systems require developing AGS in very high reservoir temperatures (several 100s of°C) and/or several dozen of kilometers of subsurface heat exchanger length (Beckers et al., 2022).
Various AGS designs have been proposed over the last several decades, including co-axial heat exchangers (“pipe-in-pipe” configurations
in which the fluid is injected either in the center pipe or annulus) and U-loop type configurations (in which the fluid is injected in one welland flows through multiple laterals before being produced from a second well). Several AGS studies were recently reviewed by Beckers
et al. (2022). For example, M orita and Tago (1995) and M orita et al. (2005) studied co-axial AGS configurations and estimated heatproduction on the order of 1 M Wth for a 2-km deep system with bottom-hole temperature of ~300°C. Riahi et al. (2017) estimated heatproduction on the order of 3 M Wth for a 2-km deep co-axial AGS with 1.1-km horizontal extension and bottom-hole temperature of 240°C.
Oldenburg et al. (2016) and Riahi et al. (2017) estimated several M Wth of heat production for a 2.5-km deep U-loop design with a single
1.1-km long horizontal lateral and bottom-hole temperature of ~250°C. Beckers et al. (2022) performed a techno-economic analysis ofboth co-axial and U-loop scenarios under different operating conditions, and found relatively high levelized cost of energy, particularly
for electricity generation, unless significant reductions can be obtained in drilling costs. However, their focus was on direct-use heat
instead of electricity as the end use, and only relatively small systems were considered. A handful of AGS demonstration projects havealso been undertaken. GreenFire Energy successfully demonstrated their co-axial downhole heat exchanger technology at Coso in
California (Higgins et al., 2019), with results indicating potential electricity generation up to 1.2 M We using supercritical CO 2 ascirculating fluid. Eavor Technologies (“Eavor”) successfully tested a 2.4-km deep U-loop configuration with two horizontal laterals of
1.7-km length each, in Alberta, Canada (Vany and Toews, 2020). With bottom-hole temperature of 78°C, the thermal output was on theorder of 800 kWth. M easurements at this test site, referred to as Eavor-Lite, were used in our study to validate our reservoir model.
Eavor recently designed a commercial-scale system of their AGS technology, referred to as Eavor-Loop 2.0, consisting of 12 laterals up
to 7.5-km deep. Eavor contracted the National Renewable Energy Laboratory (NREL) to conduct an independent techno-economic
analysis of their system, the results of which are presented in this paper. The methodology of our study, including an overview of thesoftware we used, is provided in Section 2. Our reservoir simulation results for the Eavor-Loop 2.0, assuming a low geothermal gradient(30°C/km) and high geothermal gradient (60°C/km), are presented in Section 3. This section also provides results of our validation study
with measurements from the Eavor-Lite demonstration site. The heat production with the Eavor-Loop 2.0 is investigated both for directuse heating as well as electricity generation using an organic Rankine cycle (ORC) power plant. Surface plant simulation results are1

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provided in Section 4. Results for capital, operations & maintenance (O&M ), and levelized cost of electricity and heat (LCOE and LCOH)
of the Eavor-Loop 2.0 are presented in Section 5. Finally, conclusions are provided in Section 6.
2. METHODOLOGY
We investigated the techno-economic performance of the Eavor-Loop 2.0 using reservoir and surface plant simulations, combined withcapital and O&M cost estimates and overall LCOE and LCOH calculations. Production temperature, production pressure, and thermal
output over a 30-year lifetime are estimated using reservoir simulations with the Slender-Body Theory (SBT) tool (Beckers et al., 2015).
The SBT tool was developed by Beckers et al. (2015) and recently upgraded (Beckers et al., 2022). Validation studies of the SBT tool
were conducted by Beckers et al. (2015; 2022) by comparing with results using the Ramey (1962) analytical model and COM SOL (2019)
numerical simulator. Additional validation was performed as part of this study by comparing with Eavor-Lite measurements. Power plantmodels were developed in IPSEpro (SimTech, 2021) to estimate heat-to-power conversion using air-cooled and water-cooled subcriticaland supercritical ORC cycles. System capital and O&M costs were assessed using cost correlations published in the literature. A drilling
cost model was developed to generate a range of drilling costs (in $/m) for drilling of the laterals. Overall cost-competitiveness of theEavor-Loop 2.0 was assessed by calculating the LCOE and LCOH for a 30-year lifetime and discount rates in the range of 5% to 9%.
3. RES ERVOIR MODELING
3.1 Eavor-Lite Validation
M easurements at the Eavor-Lite demonstration site from December 2019 (start-up) through April 2021 were used to validate the SBT
reservoir simulator. The Eavor-Lite is a 2.4-km deep AGS with two horizontal laterals of about 1.7 km length each (Figure 1). Rockdensity and specific heat capacity are 2,663 kg/m3 and 1,112 J/kg-K, respectively. Rock thermal conductivity is 2.25 W/m-K around theinjection and production well and 4.64 W/m-K around the two horizonal laterals. The geothermal gradient is approximately linear withsurface temperature of 3°C and bottom-hole temperature of 78°C. Water is injected with a total flow rate of about 6 kg/s (Figure 2) andinjection temperature fluctuating around 24°C (Figure 3). At a few instances (around October 1, 2020, and January 1, 2021), the flow rate
was zero. Simulated production temperatures with the SBT model are in good agreement with Eavor measurements (Figure 4). M easured
and simulated injection and production pressures are plotted in Figure 5. From April 2020 until October 2020, Eavor staff made someminor changes to the working fluid chemistry , which had a large impact on outlet pressure but minor impact on outlet temperature. Ourmodeling studies assume pure water for the entire operating period. The SBT model requires a constant injection pressure, which was set
to 150 kPa. The simulated production pressure is in approximate agreement with the measured production pressure, confirming t he strong
thermosiphon effect observed (i.e., production pressure is about 250 kPa above injection pressure).

Figure 1: Eavor-Lite is a 2.4-km deep U-loop type AGS with two 1.7-km long horizontal laterals. Circles represent nodes in the
S BT simulator.

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Figure 2: Measured Eavor-Lite flow rate (red circles) processed for input in S BT simulator (blue line). Average total flow rate
was approximately 6.2 kg/s.

Figure 3: Measured Eavor-Lite injection temperature (red) processed for input in S BT simulator (blue). Average injection
temperature was about 24°C.

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Figure 4: Eavor-Lite production temperature. Red circles are measurements by Eavor. Blue is simulated production temperature
with S BT simulator.

Figure 5: Eavor-Lite injection pressure (blue) and production pressure (red). Circles represent measurements by Eavor, and solidline is input and output for S BT simulator. The S BT simulator requires a constant injection pressure (solid blue line).

3.2 Eavor-Loop 2.0 Reservoir S imulations
The SBT simulator was applied to a sample Eavor-Loop 2.0 design consisting of 12-lateral U-loop type passes with total depth of about
7.5 km (Figure 6). The spacing between the laterals is about 75 m. The length of each lateral is about 6.5 km. Pure water is injected at 80kg/s and 60°C. The rock thermal conductivity is set to 2.5 W/m-K, the rock density is 2,663 W/m-K, and the rock specific heat capacity
is 1,112 J/kg-K. The well and lateral diameter is 0.216 m. Two scenarios are considered: a high geothermal gradient scenario (60°C/km)
and a low geothermal gradient scenario (30°C/km). The surface temperature is set to 10°C. The bottom-hole temperature (at 7.5-km depth)
for the high geothermal gradient scenario is 460°C, and for the low geothermal gradient scenario is 235°C. The production temperature
over a 30-year lifetime as calculated with the SBT simulator is plotted in Figure 7. Simulations were performed with and without thermalinterference between the laterals, indicating a spacing of 75 m is sufficient to limit thermal interference. The high geothermal gradientcase has an average production temperature of about 210°C, while the low geothermal gradient case has an average production temperatureof about 125°C. The corresponding heat production (in M Wth) for each scenario is plotted in Figure 8. Simulation results for difference
between production and injection pressure are shown in Figure 9. In both scenarios, a positive thermosiphon is calculated.

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Figure 6: Eavor-Loop 2.0 has 12 laterals with total depth of approximately 7 km. Blue represents the injection side; red represents
the production side. S pacing between laterals is approximately 75 m. Figure is not to scale.

Figure 7: S BT simulation results for production temperature with Eavor-Loop 2.0 with low geothermal gradient (30°C/km) andhigh geothermal gradient (60°C/km). Results are shown with and without considering thermal interference between thelaterals.

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Figure 8: S BT simulation results for heat production with Eavor-Loop 2.0 with low geothermal gradient (30°C/km) and highgeothermal gradient (60°C/km). Results are shown with and without considering thermal interference between the laterals.

Figure 9: S BT simulation results for the difference in pressure between outlet and inlet with Eavor-Loop 2.0 for the low geothermal
gradient (30°C/km) and high geothermal gradient (60°C/km) scenario. A constant inlet pressure of 100 bar was assumed.
Results show a positive thermosiphon effect in both scenarios indicating no pumping power is required.

4. S URFACE PLANT MODELING
Heat production achieved with the Eavor-Loop 2.0 system (see Section 3) is investigated for electricity generation using an ORC power
plant. Power plant models were developed in IPSEpro (SimTech, 2021) to estimate heat -to-power conversion using air-cooled condensers(ACC) and water-cooled condensers (WCC) in subcritical and supercritical cycles with and without heat recuperators. Various working
fluids within the ORC power plant were considered to maximize net efficiency for the low geothermal gradient (30°C/km) and highgeothermal gradient (60°C/km) scenarios. A constant geothermal production temperature was assumed at 125°C and 210°C, respectively.
Results for eight cases are provided in Table 1. The low geothermal gradient scenario has net efficiencies ranging from ~10% to ~13%with net power ranging from ~2 M We to ~3 M We . The best performing working fluid was propane. The high geothermal gradient scenario
has net efficiencies ranging from ~17% to ~19% with net power ranging from ~8.6 M We to ~9.7 M We . The best performing working fluid
was butane for a subcritical cycle and isobutane for a supercritical cycle. An example IPSEpro simulation is shown in Figure 10. Thiscase represents a subcritical ORC with ACC for the high geothermal gradient scenario, with butane as working fluid. The corresponding6

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temperature-entropy diagram is visualized in Figure 11. Additional IPSEpro input assumptions and pinch point delta temperatures for thiscase are provided in Appendix A.
Table 1: IPS Epro simulation results for air- and water-cooled ORC cycles for the low and high geothermal gradient scenario.
Case

Conditions

ORC with ACC
ORC with WCC
ORC with ACC
ORC with WCC
ORC with ACC
ORC with WCC
ORC with ACC
ORC with WCC

Subcritical
Subcritical
Supercritical
Supercritical
Subcritical
Subcritical
Supercritical
SupercriticalGeofluid
Temperature
(°C)
125
125
125
125
210
210
210
210

Recuperator

Working Fluid

Net Efficiency(%)

Net Power(MW e)

No
No
No
No
Yes
Yes
Yes

PropanePropanePropanePropaneButaneButaneIsobutane
Isobutane

10.3
11.3
11.7
12.6
16.8
17.8
18.0
18.9

2.2
2.5
2.6
2.8
8.6
9.1
9.2
9.7

Yes

Figure 10: IPS Epro model for a subcritical ORC with air-cooled condenser and heat recuperator.

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Figure 11: IPS Epro temperature vs. entropy diagram for subcritical ORC with air-cooled condenser and heat recuperator. Butane
is the working fluid.
5. TECHNO-ECONOMIC EVALUATION
5.1 Capital and O&M Cost Estimates
Overnight capital costs are estimated for the Eavor-Loop 2.0 for electricity generation and direct-use heating. Drilling and completion of
the wells and laterals represents the major cost item. The Eavor-Loop 2.0 consists of 2 vertical wells of about 4.2 km depth each and 12
laterals with total length of about 82 km (see Figure 6). The GeoVision drilling cost curves are applied to estimate drilling costs for thevertical wells (Lowry et al., 2017). Based on recent drilling activities at FORGE (e.g., Winkler and Swearingen, 2021), the two verticalwells may be drilled at a drill rate of about 50 ft/hr, suggesting the GeoVision baseline drilling curves may be too conservative. Hence,here we assume each well can be drilled at $5M , corresponding to about a 40% reduction in drilling costs from the baseline, comparable
to the Intermediate I drilling cost curve for vertical wells with small diameter (Lowry et al., 2017).
No drilling cost correlations or published cost data are available for drilling the laterals given the new nature of this technology. The
laterals are envisioned to be completed without casing or cement as demonstrated in the Eavor-Lite project, resulting likely in a significant
cost reduction from traditional well drilling as casing and cement can represent over 50% of total well cost (Lowry et al., 2017). Here, wedevelop a simple cost model to estimate open-hole lateral drilling costs as a function of drill rate and bit life. We consider similarassumptions as in the GeoVision Study (Lowry et al., 2017), presented in Table 1. The main difference with traditional geothermal welldrilling is that casing and cement are not included. Also, we assume that the laterals do not require any other completion after being
drilled.
Table 1: Lateral drilling cost assumptions
Mobi lization / de-mobilization
Fixed costs

Tripping

Mud costs$250,000 (tota l )Si te preparation$250,000

Pre-s pud engineering$10,000

Wel lhead equipment$80,000

In a nd out of hole1000 ft/hr

Ha ndling ti me

6 hrs

Ini tial vol ume$10,000

Ma ke-up volume$4,000/da y8

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Bi t cos t
BHA cost$3,800 × (di ameter in inch) – $21,800

Bi t di ameter

8.5”

Bottom-hole assembly
Directional drilling

Drilling costs

50% of bi t cos t

Specialized labor$75/hrMotor a nd s teering tools$500/hr

Ra te of penetration (ROP)

25 – 50 – 75 ft/hr

Ri g rental rate

$40,000/da y

Bi t l i fe
Trouble time

50 – 100 – 150 hr

Conti ngency

5%

CasingOmi tted

Cement

Omi tted

For the assumptions listed in Table 1, the resulting lateral drilling cost for drilling 12 laterals with total length of 82.4 km (with the depthof the laterals from ~4 km to ~7.5 km), as a function of rate of penetration (ROP) and bit life is provided in Table 2. For example, for the
scenario with ROP of 25 ft/hr and bit life of 50 hr, the total lateral drilling costs is $49.9M , corresponding to $606/m. The total rig rental
time for this scenario is ~895 days when drilling with one rig. When drilling with two rigs simultaneously, the total drilling time would
be about half. For a bit life of 50 hr, a lateral drilling cost of $400/m is calculated for an ROP of 38 ft/hr. Drilling ~82 km of open-holelaterals at 4 to 7.5 km vertical depth with rock temperatures in the range of ~250°C to ~460°C (high geothermal gradient scenario) has
never been done before. Hence, the assumptions listed in Table 1, derived from a well cost model for traditional geothermal wells, arepotentially no longer applicable. Therefore, the drilling cost results should not be interpreted as predictions but rather as estimated costs
if lateral drilling can be performed under the conditions listed in Table 1. Also, the relation between $/m and ROP and bit life as presented
in Table 2 applies specifically to the Eavor-Loop 2.0 design studied, for which the fixed costs become negligible given the long lateral
length and total drill time. For laterals with length of only a few kilometers, higher ROP and longer bit life are required to obtain the same$/m drilling cost. The lateral drilling cost results presented in Table 2 assume a range of drilling parameters as listed in Table 1. Additional
sensitivity is performed regarding the tripping speed and rig rental rate. These results are presented in Table 3, indicating significant
sensitivity to these two parameters.
Table 2: Calculated lateral drilling cost for Eavor-Loop 2.0 (82.4 km total lateral length) using assumptions listed in Table 1.
Bit life = 50 hr

Bit life = 100 hr

Bit life = 150 hr

ROP = 25 ft/hr$606/m$472/m$427/mROP = 50 ft/hr$306/m$239/m$217/mROP = 75 ft/hr$206/m$161/m$147/mTable 3: Calculated lateral drilling cost for Eavor-Loop 2.0 (82.4 km total lateral length) using assumptions listed in Table 1.
Tripping speed
Rig rental rate

-50%$403/m (500 ft/hr)$198/m ($20,000/day)Base Case$306/m (1,000 ft/hr)$306/m ($40,000/day)+50%$274/m (1,500 ft/hr)$414/m ($60,000/day)

The capital cost for an ORC plant is estimated in the range of $2,000/kWe to $3,000/kWe with $2,500/kWe as baseline, based on the ORC
cost correlations in GETEM (M ines, 2016) and GEOPHIRES (Beckers and M cCabe, 2019), and ORC cost numbers estimated by Bianchi
et al. (2019) and Ergun et al. (2017). This translates into a baseline ORC plant cost of $21.5M for the high geothermal gradient scenario(assuming 8.6 M We output) and $5.5M for the low geothermal gradient scenario (with 2.2 M We output). For direct-use heating, we
consider a single plate-and-frame heat exchanger as main surface equipment. Heat exchanger size is estimated using the standard 𝑄 =𝑈𝐴∆𝑇𝐿𝑀𝑇𝐷 equation with a heat transfer coefficient 𝑈 of 2,000 W/m2-K (Peters et al., 2003) and ∆𝑇𝐿𝑀𝑇𝐷 in the range of 5 to 10°C. The
required heat exchanger area 𝐴 (m2) is 2,500 – 5,000 m2 for the high geothermal gradient scenario (with 𝑄 = ~51 M Wth) and 1,250 –
2,500 m2 for the low geothermal gradient scenario (with 𝑄 = ~22 M Wth). Based on cost correlations for plate-and-frame heat exchangers
by Peters (2003), brought from 2002 to today’s dollars using the Bureau of Labor Statistics producer price index for power boiler and heatexchanger manufacturing (BLS, 2022), the heat exchanger cost is estimated at $350k–$450k for the high geothermal gradient scenario
and $220k–$350k for the low geothermal gradient scenario. Using “Lang Factors” to account for other project cost components such as
instrumentation, electrical work, engineering, and supervision, etc. (Peters, 2003), the total direct-use surface plant cost is estimated at$1.75M for the high geothermal gradient scenario and $1.25M for the low geothermal gradient scenario.

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The O&M cost for the ORC power plant is estimated at 1.5% of the plant capital cost (Shenjun et al., 2011; Casartelli et al., 2015; Fiaschi
et al., 2017). For the direct-use plant, given its more simple technology, the plant O&M cost is estimated at 1% of the plant capital cost.
No pumping power is required for circulating the fluid downhole due to the positive thermosiphon effect. Given the closed-loop natureand use of pure water as heat transfer fluid, no O&M cost for surface piping and heat exchanger cleaning, and scaling mitigation are
considered. Also, we assume that no rework on the wells and laterals is required throughout the lifetime. Further, no exploration costs,
royalties, or leasing costs are considered.
5.2 Levelized Cost of Energy Estimates
LCOE and LCOH values are estimated for the Eavor-Loop 2.0 considering the thermal and electricity output calculated in Sections 3 and4, and the capital and O&M cost estimates presented in Section 5.1. For electricity generation as the end use, we assume for the highgeothermal gradient scenario that the average net output is 8.6 M We (see Section 4) and availability is 95%, corresponding to ~72 GWhof electricity production per year. For the low geothermal gradient scenario, we assume a net power output of 2.2 M W e (see Section 4)
and availability of 95%, resulting in ~18 GWh of electricity per year. For direct-use heating, for the high geothermal gradient scenario,
we consider an average thermal output of 51 M Wth, combined with 95% availability, resulting in ~424 GWh of heat per year. For the low
geothermal gradient scenario, the annual heat production is ~183 GWh per year.
Levelized costs are calculated with a standard discounting levelized cost model as implemented in GEOPHIRES 2.0 (Beckers andM cCabe, 2019). We consider a discount rate in the range of 5% to 9%. Given the large uncertainty in lateral drilling costs (see Section5.1), we considered a range for lateral drilling costs of $200/m to $600/m. The calculated LCOE values are presented in Table 4; thecalculated LCOH values are presented in Table 5.
Table 4: Eavor-Loop 2.0 LCOE estimates (in $/MWh) for high and low geothermal gradient scenario.

Lateral Drilling Cost = $600/m
Lateral Drilling Cost = $400/m
Lateral Drilling Cost = $200/m

Lateral Drilling Cost = $600/m
Lateral Drilling Cost = $400/m
Lateral Drilling Cost = $200/m

High Geothermal Gradient S cenario (60°C/km)
Discount Rate = 9%
Discount Rate = 7%
LCOE = $105/M Wh
LCOE = $90/M Wh
LCOE = $85/M Wh
LCOE = $72/M Wh
LCOE = $64/M Wh
LCOE = $55/M Wh
Low Geothermal Gradient S cenario (30°C/km)
Discount Rate = 9%
Discount Rate = 7%
LCOE = $321/M Wh
LCOE = $272/M Wh
LCOE = $241/M Wh
LCOE = $204/M Wh
LCOE = $160/M Wh
LCOE = $136/M Wh

Discount Rate = 5%
LCOE = $75/M Wh
LCOE = $60/M Wh
LCOE = $46/M Wh
Discount Rate = 5%
LCOE = $224/M Wh
LCOE = $168/M Wh
LCOE = $113/M Wh

Table 5: Eavor-Loop 2.0 LCOH estimates for high and low geothermal gradient scenario. LCOH values are provided in $/GJ,
which is approximately equal to $/MMBtu.

Lateral Drilling Cost = $600/m
Lateral Drilling Cost = $400/m
Lateral Drilling Cost = $200/m

Lateral Drilling Cost = $600/m
Lateral Drilling Cost = $400/m
Lateral Drilling Cost = $200/m

High Geothermal Gradient S cenario (60°C/km)
Discount Rate = 9%
Discount Rate = 7%
LCOH = $3.6/GJ
LCOH = $3.0/GJ
LCOH = $2.6/GJ
LCOH = $2.2/GJ
LCOH = $1.7/GJ
LCOH = $1.4/GJ
Low Geothermal Gradient S cenario (30°C/km)
Discount Rate = 9%
Discount Rate = 7%
LCOH = $8.2/GJ
LCOH = $7.0/GJ
LCOH = $6.0/GJ
LCOH = $5.1/GJ
LCOH = $3.8/GJ
LCOH = $3.2/GJ

Discount Rate = 5%
LCOH = $2.5/GJ
LCOH = $1.8/GJ
LCOH = $1.2/GJ
Discount Rate = 5%
LCOH = $5.7/GJ
LCOH = $4.2/GJ
LCOH = $2.6/GJ

LCOE values less than $70/M Wh are calculated for the Eavor-Loop 2.0 in case the laterals can be drilled below $400/m and the geothermal
gradient is relatively high (~60°C/km). As presented in Section 5.1, a low lateral drilling cost requires high ROP values and long bit life.
A geothermal gradient of 60°C/km is not typically found in the eastern United States but occurs at “hot spots” in the western UnitedStates. While the LCOE values calculated are higher than those for wind and solar, the electricity generated with the Eavor-Loop 2.0 isavailable 24/7 and not subject to variability , which can ultimately reduce the average end-use price in a fully decarbonized electricity
system (Sepulveda et al., 2018).
Competitive LCOH values are found with the Eavor-Loop 2.0, even for the low geothermal gradient of 30°C/km, lateral drilling cost of$600/m and discount rate of 9%. This requires that the underlying assumptions are met, including system availability of 95% over a 30year lifetime, O&M cost of 1% of surface plant capital cost, all heat between the production temperature and the injection temperature isutilized by the end-use application, and a single heat exchanger with no energy losses as surface equipment. We only considered a single
flow rate and injection temperature in our analysis. These parameters can be adjusted to obtain production temperatures that match thesurface application, and higher flowrates (with correspondingly higher thermal outputs and lower levelized costs) are likely achievable
due to the excess thermosiphon pressure generated. This level of optimization was outside the scope of this project.
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Tables 4 and 5 indicate the levelized cost values are strongly dependent on lateral drilling cost, discount rate, and geothermal gradient.
Additional sensitivity analysis is performed to investigate dependence of the LCOE of the high geothermal gradient scenario on ORC
capital cost, O&M cost, vertical well drilling cost, and ORC plant electricity output (Table 6). All cases in Table 6 assume a lateral drilling
cost of $400/m and discount rate of 7%. The calculations reveal that the LCOE is moderately sensitive to the ORC capital cost, and only
to a small degree sensitive to the vertical well drilling cost and O&M cost. The LCOE is strongly dependent on the ORC power output,
e.g., a 5% increase in electricity production would result in a ~5% decrease in LCOE. We selected the lower-end value of 8.6 M We forbaseline ORC power output (see Table 1) as subcritical ORC plants are more common and to avoid water consumption for operatingwater-cooled condensers.
Table 6: Eavor-Loop 2.0 LCOE (in $/MWh) for high geothermal gradient scenario (60°C/km) for various ORC capital cost, ORC
power output, ORC O&M cost and vertical well drilling cost. For all cases, the lateral drilling cost is $400/m and thediscount rate is 7%.
ORC Capital Cost
Vertical Well Drilling Cost
O&M Cost-50%$61/M Wh ($1,250/kW)$67/M Wh ($2.5M /well)$70/M Wh ($160k/yr)

Base Case$72/M Wh ($2,500/kW)$72/M Wh ($5M /well)$72/M Wh ($320k/yr)+50%$84/M Wh ($3,750/kW)$78/M Wh ($7.5M /well)$75/M Wh ($480k/yr)

ORC Electricity Output-5%$75/M Wh (8.2 M We)

Base Case$72/M Wh (8.6 M We)+5%$70/M Wh (9.0 M We)

6. CONCLUS IONSIn this paper, we present the results of a techno-economic assessment NREL conducted during the fall of 2021 of a sample Eavor-Loop
2.0 design for direct-use heating and electricity production. The Eavor-Loop 2.0 design studied is a U-loop type 7.5-km deep closed-loop
geothermal system consisting of 1 injection well, 1 production well, and 12 lateral passes. The injection and production well are verticaland each about 4 km deep. The laterals are each about 6.5 km long, spaced ~75 m apart, and occur from ~4 km to ~7.5-km depth. We
considered pure water as heat transfer fluid, injected at 60°C and 80 kg/s over a 30-year lifetime. We considered a low geothermal gradient(30°C/km) and high geothermal gradient (60°C/km), with bottom-hole temperature of 235°C and 460°C, respectively.
Reservoir simulations with the SBT simulator for heat conduction only in the reservoir indicate long-term average production temperaturesof about 210°C for the high geothermal gradient scenario and about 125°C for the low geothermal gradient scenario. This corresponds toaverage heat production of ~50 M Wth and ~22 M Wth, respectively. Due to a positive thermosiphon effect, no pumping power is requiredfor circulating the water, and ~50 to ~100 bar of excess thermosiphon pressure is generated for the high geothermal gradient scenario.
Using IPSEpro simulations for an ORC power plant with air-cooled condensers, we find a net power output of about 8.6 M We for thehigh geothermal gradient scenario and about 2.2 M We for the low geothermal gradient scenario.
Cost assessment of the Eavor-Loop 2.0 design suggests that the overall capital costs are dominated by the lateral drilling cost. A simplified
well cost model suggests lateral drilling cost for the Eavor-Loop 2.0 design are in the range of ~$200 to ~$600/m for an ROP in the rangeof 25 to 75 ft/hr, bit life in the range of 50 to 150 hours, and omitting casing and cement. Published cost correlations are applied for an
ORC power plant for electricity generation and a plate-and-frame heat exchanger for direct-use heating. O&M costs are set to 1.5% of the
ORC plant for electricity generation and 1% of the surface plant for direct-use heating. Using a standard discounting levelized cost modelwith discount rate in the range of 5% to 9% and lateral drilling cost in the range of $200/m to $600/m, we find LCOE values in the range
of $46/M Wh to $105/M Wh for the high geothermal gradient scenario and $113/M Wh to $321/M Wh for the low geothermal gradientscenario. The LCOH values are $1.2/GJ to $3.6/GJ for the high geothermal gradient scenario and $2.6/GJ to $8.2/GJ for the low
geothermal gradient scenario.
The levelized cost results indicate that LCOE values under $70/M Wh can be obtained with the Eavor-Loop 2.0 if the laterals can be drilled
under $400/m, the local geothermal gradient is relatively high at 60°C/km, and the discount rate is under 9%. For the Eavor-Loop 2.0
design studied, a lateral drilling cost of ~$400/m would require an ROP of ~40 ft/hr, a bit life of 50 hours, and omitting casing and cement.
Traditional (geothermal) well drilling has achieved this ROP, including recent wells drilled in granite at the Utah FORGE site. However,the Eavor-Loop 2.0 requires drilling of ~82 km of open-hole laterals at 4 to 7.5 km vertical depth in rocks with temperatures up to 465°C.
Such downhole completion has never been developed before. Hence, it is unclear if traditional geothermal well drilling conditions are stillvalid. In comparison with electricity generation, competitive LCOH values are calculated even for the lower geothermal gradient scenario
of 30°C/km, and higher lateral drilling costs of $600/m. These LCOH values assume a 95% system availability over its 30-year lifetime,and a single heat exchanger as surface equipment. Both the electricity and direct-use heat scenario assume that once the subsurface system
is installed, no maintenance is required over its lifetime (e.g., rework of a lateral).
ACKNOWLEGMENTS
We would like to thank Eavor Technologies for providing data and support for this project. The analysis was performed independently,
and the views expressed in this paper belong solely to the authors. We would like to thank Craig Turchi and Deanna Cook for their reviewof the manuscript. This work was authored by the National Renewable Energy Laboratory, operated by Alliance for Sustainable Energy,
LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. The views expressed herein do not necessarily
represent the views of the DOE or the U.S. Government. The U.S. Government retains and the publisher, by accepting the article for11

Beckers and Johnston
publication, acknowledges that the U.S. Government retains a nonexclusive, paid-up, irrevocable, worldwide license to publish or
reproduce the published form of this work, or allow others to do so, for U.S. Government purposes.
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APPENDIX A. IPS EPRO INPUT AS S UMPTIONS AND PINCH POINT TEMPERATURES FOR HIGH-TEMPERATU R E
S UBCRITICAL ORC WITH ACC

Table A1: IPS Epro Input Assumptions
S urface Plant Input Parameter

Parameter Value

Turbine Inlet Pressure

36 bar

Turbine Inlet Temperature

159°C

Turbine Isentropic Efficiency

90%

Turbine M echanical Efficiency

100%

Generator Electrical Efficiency

98%

Generator M echanical Efficiency

98%

Turbine Outlet Pressure

3 bar

Recuperator Thermal Duty

5,007 kWACC Fan/Air Flow Ratio

0.12 kW / kg/s air

Pump Isentropic Efficiency

90%

Pump M echanical Efficiency

90%

Pump M otor Electrical Efficiency

98%

Pump M otor M echanical Efficiency

98%

Geothermal Fluid Inlet Pressure

100 barGeothermal Fluid Outlet Temperature

60°C

Table A2: Pinch Point delta Temperatures
S urface Plant Heat Exchangers

Pinch Point delta Temperature

Recuperator

13.9°CAir Cooled Condenser

3.3°C

Primary Heat Exchanger

5.8°C

14