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PROCEEDINGS, Fortieth Workshop on Geothermal Reservoir Engineering
Stanford University, Stanford, California, January 26-28, 2015
SGP-TR-204
1
Superheating of Low-Temperature Geothermal Working Fluids to Boost Electricity
Production: Comparison between Water and CO2 Systems
Nagasree Garapati1, Jimmy B. Randolph1,2, and Martin O. Saar1,2,3
1.Department of Earth Sciences, University of Minnesota; 2.TerraCOH Inc., Minneapolis, MN; 3.Department of Earth Sciences, ETH-
Zürich
ngarapat@umn.edu
Keywords: Low-temperature geothermal, Superheating, Carbon dioxide, Hybrid system, CPG.
ABSTRACT
Low-temperature geothermal resources (<150°C) are typically more effective for direct use, i.e., district heating, than for electricity
production. District or industrial heating, however, requires that the heat resource is close to residential or industrial demands in order to
be efficient and thus economic. However, if a low-temperature geothermal resource is combined with an additional or secondary energy
source that is ideally renewable, such as solar, biomass, biogas, or waste heat, but could be non-renewable, such as natural gas, the
thermodynamic quality of the energy source increases, potentially enabling usage of the combined energy sources for electricity
generation. Such a hybrid geothermal power plant therefore offers thermodynamic advantages, often increasing the overall efficiency of
the combined system above that of the additive power output from two stand-alone, separate plants (one using geothermal energy alone
and the other using the secondary energy source alone) for a wide range of operating conditions. Previously, fossil superheated and solar
superheated hybrid power plants have been considered for brine/water based geothermal systems, especially for enhanced geothermal
systems. These previous studies found, that the cost of electricity production can typically be reduced when a hybrid plant is operated,
compared to operating individual plants. At the same time, using currently-available high-temperature energy conversion technologies
reduces the time and cost required for developing other less-established energy conversion technologies. Adams et al. (2014) found that
CO2 as a subsurface working fluid produces more net power than when brine systems are employed at low to moderate reservoir depths,
temperatures, and permeabilities. Therefore in this work, we compare the performance of hybrid geothermal power plants that use brine
or, importantly, CO2 (which constitutes the new research component) as the subsurface working fluid, irrespective of the secondary
energy source used for superheating, over a range of parameters. These parameters include geothermal reservoir depth and superheated
fluid temperature before passing through the energy conversion system. The hybrid power plant is modeled using two software
packages: 1) TOUGH2 (Pruess, 2004), which is employed for the subsurface modeling of geothermal heat and fluid extraction as well
as for fluid reinjection into the reservoir, and 2) Engineering Equation Solver (EES), which is used to simulate well bore fluid flow and
surface power plant performance. We find here that for geothermal systems combined with a secondary energy source (i.e., a hybrid
system), the maximum power production for a given set of reservoir parameters is highly dependent on the configuration of the power
system. The net electricity production from a hybrid system is larger than that from the individual plants combined for all scenarios
considered for brine systems and for low-grade secondary energy resources for CO2 based geothermal systems.
1 INTRODUCTION
The total amount of extractable thermal energy in the United States is estimated to be 200,000 EJ (exajoules), which is approximately
2000 times the current U.S. annual primary energy consumption (Tester et al., 2006). Currently most US geothermal power plants are
installed in California and Nevada where there exist high geothermal temperature gradients and relatively shallow fracture networks in
the subsurface (Reinhardt, 2013). Recent advancements in binary cycle power plants with improved selection of secondary working
fluids have helped extend the geothermal resource base to lower temperature gradient fields. However, due to low thermal efficiency
and high initial cost, they are not economically attractive for power production. Hence these are considered to be more effective for
direct use. District or industrial heating, however, requires that the heat resource is close to residential or industrial demands in order to
be efficient and thus economic. If this low-temperature resource is combined with an additional energy source that is ideally renewable,
such as solar, biomass, biogas, or waste heat, but could be non-renewable, such as natural gas, its thermodynamic quality increases,
enabling usage for electricity generation. A hybrid geothermal power plant offers a thermodynamic advantage and outperforms stand-
alone individual plants for a wide range of operating conditions, increasing the overall efficiency of the system (DiPippo et al., 1978).
Hybrid geothermal-fossil power plants (Kestin et al., 1978; Khalifa et al., 1978; DiPippo et al., 1978; Parsons; DiPippo et al., 1981;
Bettocchi et al., 1992; Bidini et al.; 1998, Bruhn, 2002) and solar-geothermal hybrid plants (Lentz and Almanza, 2006; Bryden et al.
2009; Astolfi et al. 2011; Tempesti et al., 2012), in which water and/or brine is employed as the subsurface heat exchange fluid, have
been studied previously. It is found that the cost of electricity production can typically be reduced when a hybrid plant is operated,
compared to operating individual plants (Zhou et al., 2013). Superheating of the low-temperature working fluid enables use of
Garapati, Randolph and Saar
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currently-available high-temperature energy conversion technologies, reducing the time and cost required to develop new energy
conversion technologies (Kohl et al., 2002).
CO2 was initially proposed as a geothermal working fluid only in the context of an Enhanced Geothermal System (EGS) (Brown, 2000,
2003; Fouillac et al. 2004; Pruess 2006, 2007, 2008). In contrast, CO2 Plume Geothermal (CPG) (Randolph and Saar 2011a, b; Saar et
al., 2012; Buscheck et al. 2013) involves injecting CO2 into natural, highly permeable geologic units to extract geothermal energy. It is
also found that CO2 as a subsurface working fluid produces more net power than brine systems at low to moderate reservoir depths,
temperatures, and permeabilities (Adams et al. 2015). Because of its low kinematic viscosity, allowing for effective heat advection, and
its highly temperature-dependent density, CO2 generates a stronger thermosiphon through the injection and production wells, which
reduces or eliminates the need for pumps to circulate the fluid through the reservoir (Atrens et al., 2009, Adams et al. 2014). Therefore,
we hypothesize that CO2-based geothermal systems combined with superheating by secondary energy sources increase the efficiency
and the electricity production even further than that for previously-proposed water or brine systems that use a secondary energy source.
In this work, we compare the performance of hybrid geothermal power plants that use brine and CO2-based geothermal systems
irrespective of the secondary energy source used for superheating the secondary fluid over a range of parameters. These parameters
include geothermal reservoir depth (2.5 km, 3.5 km, and 4.5 km) and the final, superheated temperature of the working fluid (200°C,
250°C, 300°C, 350°C, 400°C) as it enters the turbine. The net power obtained from the hybrid power plant is compared with the power
obtained with individual sources for various scenarios. In total, we consider three different superheating scenarios:
1) Direct CO2 plant: a turbine is used to expand the geologic heat extraction fluid (CO2) directly in a surface plant turbine after
superheating it with a secondary heat source;
2) Indirect CO2 plant: the heat from the geothermal working fluid (CO2) is transferred to a secondary working fluid (CO2) in a surface
plant heat exchanger and then superheated using a secondary heat source;
3) Indirect brine plant: the heat from the geothermal working fluid (brine) is transferred to a secondary working fluid (CO2) in a surface
plant heat exchanger and then superheated using a secondary heat source.
For comparison, we also determine the net power output from employing the geothermal energy sources alone and from using the
secondary energy source alone.
2 CONCEPTUAL AND NUMERICAL MODEL
The hybrid power plant is modeled using a coupled model of subsurface reservoir, wellbore, and surface plant. TOUGH2-ECO2N
(Pruess, 2004, 2005) is used for simulations of subsurface geothermal heat and fluid extraction with fluid reinjection into the reservoir,
and Engineering Equation Solver (EES) is employed for simulating well bore fluid flow and surface power plant performance. EES is a
simultaneous equation solver with built-in mathematical and thermophysical property functions. The CO2 property data is taken from
Span and Wagner (1996), and brine values are determined from the relationships provided by Driesner (2007) and the IAPS-84 Steam
Tables (Harr et al., 1984). The coupling of TOUGH2 and EES is accomplished using a code written in Visual Studio, where the
maximum net power produced from a geothermal system at a set of geological conditions is calculated by first running the subsurface
simulation. Then, the results are given as input in EES to obtain the optimum fluid flow rate to maximize net power production, as
discussed in the Supplemental information of Adams et al. (2015). This flow rate is used to rerun the TOUGH2 simulation, obtaining
the initial conditions for the next time step. The process is repeated until the end of the total simulation time (15 years).
2.1 Subsurface Model (TOUGH2-ECO2N)
In order to facilitate direct comparison between brine and CO2 geothermal systems, for CO2 geothermal systems, the initial CO2
sequestration into the reservoir for CO2 plume formation and the brine displacement are not simulated here. Instead, the pore space in
the reservoir is assumed to be completely filled either with pure CO2 or with 20 wt% NaCl brine. The geothermal reservoir considered
has a porosity of 10%, is 300 m thick, is located at an average depth from the surface of 2.5 km to 4.5 km, is bound by impermeable
bedrock and caprock formations, and is heated from below by a typical geothermal gradient of 35 °C/km (Pollack et al., 1993). Here, we
employ a numerical 3-D axisymmetric model with the cold injection fluid entering the reservoir through a vertical injection well. After
moving through the geothermal reservoir, the heated fluid is produced from a horizontal, circular production well placed at a distance
from the injection well (Garapati et al., 2014). The model extends horizontally to 100 km to minimize numerical boundary effects, with
logarithmically increasing horizontal grid spacing away from the injection well but horizontal refinement of grid spacing near the
production well. The initial conditions of the reservoir are uniform and are determined based on the hydrostatic pressure and geothermal
gradient. Table 1 lists more details about the reservoir constants and model setup, including the use of a standard semi-analytic
conductive heat exchange boundary condition to over- and underlying layers (Pruess et al., 1999).
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2.2 Well and Surface Power Plant Models (Engineering Equation Solver (EES))
Three surface power plant models with two primary working fluid combinations are considered: 1) direct CO2 system; 2) indirect CO2
system; and 3) indirect brine system, which are similar to the models used in Adams et al. (2015). For both direct and indirect CO2
systems, no production pumps are needed due to the thermosiphon effect, i.e., the flow is generated due to the density difference
between the injection and production wells (Adams et al., 2014), while for the indirect brine system, production pumps are required. For
comparison, we have added a model of the direct CO2 system with a production pump to supplement the thermosiphon. The fluid state
in the injection and production wells and the pressure losses are calculated, as explained in Adams et al. (2015), using the first law of
thermodynamics, Bernoulli, and conservation of mass equations. The power output from the turbine is calculated as the product of the
mass flow rate and the difference between the inlet and exit enthalpies, and the exit enthalpy is determined from the isentropic turbine
efficiency. The power required for pumping is calculated similarly, based on isentropic pump efficiency. The heat extraction rate from
the reservoir and from the cooling and condensing towers is obtained as the product of mass flow rate and the enthalpy difference
between inlet and outlet fluid. The parasitic power requirements are calculated as the fraction of the heat extraction rate based on the
parasitic loss fraction, λ, as explained in the Supplemental information in Adams et al. (2015). The injection and production well and
power plant parameters, along with equipment efficiencies, are detailed in Table 1.
𝑁𝑒𝑡 𝑝𝑜𝑤𝑒𝑟 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑 = 𝑇𝑢𝑟𝑏𝑖𝑛𝑒 𝑜𝑢𝑡𝑝𝑢𝑡 𝑝𝑜𝑤𝑒𝑟 – 𝑃𝑎𝑟𝑎𝑠𝑖𝑡𝑖𝑐 𝑝𝑜𝑤𝑒𝑟 𝑙𝑜𝑠𝑠𝑒𝑠 – 𝑃𝑢𝑚𝑝𝑖𝑛𝑔 𝑝𝑜𝑤𝑒𝑟.
Table 1 Model parameters of geothermal reservoir and power plant scenarios.
Reservoir Constants
Configuration
Well Orientation
Well Spacing
Radially symmetric about the injection well
Vertical (injection), horizontal circular (production)
707 m
Reservoir Thickness
Average Depth, D
Horizontal Permeability, kx
Vertical Permeability, kz
Thermal Conductivity
300 m
2500 m, 3500 m, 4500m
5×10-14 m2
2.5×10-14 m2
2.10 W/m/°C
Rock Density
2650 kg/m3
Rock Specific Heat
Reservoir Porosity
Radius
Geothermal Gradient
1000 J/kg/°C
0.10
100,000 m
35 °C/km
Initial Condition
Uniform.
Lateral Boundary Condition
Vertical Boundary Condition
No heat or fluid flow
No fluid flow; heat conduction using TOUGH2 semi-analytic model
Primary System Fluids or
Reservoir Working Fluids
Power Plant Constants
- 100% CO2
- 20 wt% H20-NaCl (brine)
Secondary (ORC) System Fluid
- CO2
Downhole Production Well Pressure
Hydrostatic
Direct Turbine Efficiency
78%
ORC Turbine Efficiency
80%
Pump Efficiencies
90%
Well Pipe Material
Well Pipe Diameter
Bare CR13
0.33 m
Well Pipe Roughness
55 µm (Farshad & Rieke, 2006)
Condensing or Cooling Tower Approach Temperature
7 °C
Ambient Temperature
Super Heating Temperature
15 °C
200 °C, 300 °C, 400 °C, and 500 °C
2.2.1 Direct CO2 System
The fluid flow through the wells and the surface power plant is illustrated in Figure 1. The cold CO2 is injected at the surface at State 1,
where it travels down the injection well to State 2, expanding isentropically to a super critical fluid. The supercritical fluid then flows
through the reservoir and heats to the reservoir temperature, reaching the bottom of the production well at State 3. The fluid then rises
adiabatically (Randolph et al., 2012) through the production well to the surface to State 4. At the surface the fluid is further heated
Garapati, Randolph and Saar
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isobarically to State 5 by a secondary energy source. This superheated fluid is expanded through a turbine for power production to State
6. The fluid is then cooled and condensed isobarically to the approach temperature of 7°C, which is selected based on Adams et al.
(2015). The condensation pressure is set to 10 kPa above the saturation pressure of CO2 at 22°C. The cooled CO2 is (minimally) pumped
from State 8 to State 1.
Figure 1: Direct CO2 System Diagram. In this case, the geothermal fluid (CO2) itself is superheated to the required temperature
and expanded directly in the turbine to generate power. The thermosiphon generated by the buoyant CO2 flow
eliminates the need for injection pumping (modified from Adams et al., 2015).
2.2.2 Indirect CO2 or Brine System
In an indirect system, the geothermal heat is transferred from the geothermal working fluid to the secondary fluid through a heat
exchanger that drives the secondary Rankine cycle, as shown in Figure 2. Benefits of indirect systems include that “off-the-shelf”
components can be used and that minimal equipment comes in contact with the potentially corrosive geothermal fluid; however, they
have low overall system thermal efficiency. In order to avoid a “pinch point” problem in the heat exchanger, CO2 is used as the
secondary working fluid of the Rankine cycle. The main power cycle components are: a preheater (i.e., heat exchanger), where the
geothermal energy is transferred between the working fluids; a superheater, where the secondary fluid is heated to higher temperatures
isobarically using a secondary energy source; a turbine, where the fluid is expanded for power production; isobaric fluid cooling and
condensing towers; and a pump for pumping the secondary fluid to the heat exchanger. The optimum secondary high-side pressure is
calculated based on the inlet temperature to the turbine, using the equation developed in the supplemental information of Adams et al.
(2015). The secondary cycle is similar for both CO2 and brine systems, however, for the brine system, a downhole lineshaft pump is
placed 500 m below the production wellhead to bring brine to the surface. The downhole pump specifications are considered similar to
the specifications in Adams et al. (2015). The hot geothermal fluid produced at the surface passes isobarically through a boiler, then the
cooled fluid is reinjected into the subsurface. In the case of CO2, a throttling valve is used to reduce the pressure and control mass flow
rate before reinjecting the fluid. The saturation temperature of dissolved amorphous silica limits the injection temperature of the brine,
as in the reservoir, the brine is saturated with dissolved quartz. When it is produced to the surface and cooled below the saturation
temperatures -- which are 9.5 °C, 45 °C and 82 °C for 20 wt% NaCl brine at depths of 2.5 km, 3.5 km, and 4.5 km, respectively --
quartz starts to precipitate from the solution as amorphous silica (DiPippo, 1985). Quartz precipitation can cause scaling within the
pipes and other equipment and is avoided by injecting the brine at a temperature above the saturation temperature of amorphous silica.
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Figure 2: Indirect CO2 or Brine System Diagram. The indirect system utilizes a secondary Rankine cycle, with CO2 as the
secondary working fluid, that obtains energy from the geothermal fluid in the heat exchangers and is superheated to
higher temperatures. When brine is the geothermal fluid, a downhole pump is necessary to circulate the brine;
however, when using CO2 as the geothermal fluid, no pumping is necessary (but may be included), and the fluid may
even be throttled (State 7 to 1) to maximize net power output (modified from Adams et al., 2015).
3 RESULTS AND DISCUSSION
Three surface plant models for three different depths and five superheated temperatures are investigated, and for each model and depth,
an individual geothermal power plant and a secondary-source power plant are also modeled for comparison. Firstly, the net power
output for different scenarios for each surface plant is assessed. The net power output for each scenario is calculated by first running the
subsurface simulation, then these results are given as input to run EES to optimize the mass flow rate, and this optimum mass flow rate
is then used to rerun the TOUGH2 reservoir simulation to obtain the initial conditions for the next time step. Though time dependent
behavior is not studied here, the results at the end of 15 years are compared with a 5 year time step to obtain the correct optimum flow
rate for maximum net power output and corresponding conditions. Next, the amount of heat extracted from the geothermal reservoir and
the amount of secondary source energy needed to achieve the same superheated temperature for different surface plants and for different
depths is considered. The net power produced using only the secondary heat source without preheating by the geothermal fluid is
calculated using the EES model with the corresponding quantity of secondary source energy incorporated for each scenario.
3.1 Direct CO2 System
The net power produced for a Direct CO2 system with respect to the inlet temperature to the turbine is shown in Figure 3. The net power
produced by the hybrid plant is always greater than the power produced only by the geothermal source, as expected. At higher depths
and when a lower-grade secondary heat source is available, the net power produced by the hybrid plant is more than the sum of the
individual plants combined. However at shallow reservoir depths, plants operating only with the secondary source outperform the
hybrid system. This is because, in the hybrid system, the geothermal fluid (CO2) is used to run the surface plant too, consequently the
pressure and density of the CO2 entering into the turbine is fixed by the thermosiphon, while for the plant operating with the secondary
source alone the density can be maintained to maximize net power output. As the superheated temperature increases, the optimum mass
flow rate and the amount of heat extracted from the reservoir also increases, as seen in Figure 4. Therefore, in this configuration, the
hybrid plant is favorable only if the amount of heat from the secondary source is also low for low-temperature geothermal systems. The
afore-mentioned limitations may be overcome using a pump after the CO2 is produced, as shown in Figure 5.
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Figure 3: Net power output with respect to inlet temperature of the turbine for Direct CO2 power plant at depths of a) 2.5 km,
b) 3.5 km, and c) 4.5 km.
Figure 4: Optimum geothermal working fluid mass flow rate (a) and reservoir heat energy extracted (b) with respect to the inlet
temperature to the turbine for a Direct CO2 power plant at various depths.
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Figure 5: Net power output with respect to the inlet temperature to the turbine for a Direct CO2 power plant with a production
pump at the surface to boost the thermosiphon flow; results provided at depths of a) 2.5 km, b) 3.5 km, and c) 4.5 km.
3.2 Indirect CO2-CO2 System
When considering an Indirect CO2-CO2 system, the heat from the geothermal working fluid (CO2) is transferred to a secondary working
fluid (CO2), which is then further heated by the secondary source before entering the turbine. The net power is calculated at an optimum
geothermal working fluid mass flow rate and is plotted with respect to the temperature of the fluid entering turbine in Figure 6. Similar
to the Direct CO2 system, the net power produced by the hybrid plant is more than the power produced by the geothermal source and
secondary source combined at higher depths and lower-temperature secondary heat resources. At low geothermal temperatures and large
secondary heat resources, the heat is transferred from the secondary fluid to the geothermal fluid, hence the geothermal heat extracted is
negative, as shown in Figure 7, and the geothermal reservoir acts as an energy storage unit instead of a resource for energy production.
Therefore, the power plant with a secondary source alone provides more energy output than the hybrid plant.
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Figure 6: Net power output with respect to the inlet temperature to the turbine for an Indirect CO2-CO2 power plant at depths
of a) 2.5 km, b) 3.5 km, and c) 4.5 km.
Figure 7: Optimum geothermal working fluid mass flow rate (a) and reservoir heat energy extracted (b) with respect to the inlet
temperature to the turbine for an Indirect CO2-CO2 power plant at various depths.
Garapati, Randolph and Saar
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3.3 Indirect Brine-CO2 System
The Indirect Brine-CO2 system has the same surface plant as that of the Indirect CO2 system, however brine is produced from the
subsurface to the surface using a downhole lineshaft pump placed 500 m below the production wellhead. Similar to the Indirect CO2
system, the heat from the geothermal working fluid (brine) is transferred to a secondary working fluid (CO2), which is used to drive the
surface plant. In this system, the net power produced by the hybrid plant exceeds the sum of the power produced by individual plants
under all scenarios, as seen in Figure 8. At shallow reservoir depths, the heat extracted from the reservoir initially increases with the
addition of the secondary heat source, as the optimum mass flow rate increases, as seen in Figure 9b. However, with further addition of
secondary heat, the reservoir heat extraction decreases (Figure 9b) as the injection temperature of brine increases. For higher depths, the
heat extracted from the reservoir is constant, as the injection temperature is limited to the saturation temperature of dissolved amorphous
silica, as discussed in Section 2.2.2.
Figure 8: Net power output with respect to the inlet temperature to the turbine for an Indirect Brine-CO2 power plant at depths
of a) 2.5 km, b) 3.5 km, and c) 4.5 km.
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Figure 9: Optimum geothermal working fluid mass flow rate (a) and reservoir heat energy extracted (b) with respect to the inlet
temperature to the turbine for an Indirect Brine-CO2 power plant at various depths.
4 CONCLUSIONS
Hybrid plants produce more net power than geothermal power plants alone in all cases irrespective of the geothermal working fluid, as
expected. The hybrid plant with brine as the subsurface working fluid produces more power than that produced by the sum of the
individual power plants. In comparison, the hybrid plant with CO2 as the working fluid produces more power with low-grade secondary
heat sources, while with higher-grade secondary heat sources the individual plant out performs the hybrid plant, irrespective of whether
it is a direct or an indirect system. In the case of an Indirect CO2-CO2 system, as the secondary energy resource increases, the
geothermal resource acts as an energy storage unit. In stand-alone geothermal systems, the net power generated with CO2 as a
subsurface working fluid is more than that of a brine system, due to the formation of a vigorous thermosiphon and related elimination of
parasitic pumping power requirements in such CO2-based geothermal systems (Adams et al., 2014). However, when direct CO2-
geothermal systems are considered for hybrid systems, the thermosiphon limits the heat energy that can be extracted across the turbine
so that the CO2 leaves the turbine at a relatively high energy state, reducing the net power generated. This can be overcome by using a
production pump, similar to the injection pump at the surface to augment the thermosiphon flow in case of Direct CO2 systems. With the
addition of such a pump, the net power produced by the CO2 hybrid plant increases and is more than the total power produced by
individual plants added together for low-intensity secondary energy sources.
Acknowledgments
We thank Benjamin M. Adams for help with Visual C# for coupling the TOUGH2 and EES models. This work was supported in part by
a Sustainable Energy Pathways (SEP) grant from the National Science Foundation (NSF) under Grant Number SEP-1230691, by the
U.S. Department of Energy (DOE) under Grant Number DE-EE0002764, and by a grant from the Initiative for Renewable Energy and
the Environment (IREE), a signature program of the Institute on the Environment (IonE) at the University of Minnesota (UMN). Any
opinions, findings, conclusions and/or recommendations expressed in this material are those of the authors and do not necessarily reflect
the views of the NSF, DOE, IREE, IonE, or UMN.
Disclaimer
Drs. Randolph and Saar have significant financial and business interests in TerraCOH Inc., a company that may commercially benefit
from the results of this research. The University of Minnesota has the right to receive royalty income under the terms of a license
agreement with TerraCOH Inc. These relationships have been reviewed and managed by the University of Minnesota in accordance
with its conflict of interest policies.
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