Geothermal Energy Production at Geologic CO2 Sequestration sites: Impact of Thermal Drawdown on Reservoir Pressure

Abstract

Recent geotechnical research shows that geothermal heat can be efficiently mined by circulating carbon dioxide through naturally permeable rock formations -- a method called CO2 Plume Geothermal -- the same geologic reservoirs that are suitable for deep saline aquifer CO2 sequestration or enhanced oil recovery. This paper describes the effect of thermal drawdown on reservoir pressure buildup during sequestration operations, revealing that geothermal heat mining can decrease overpressurization by 10% or more.

Full text

Energy Procedia 37 ( 2013 ) 6625 – 6635
1876-6102 © 2013 The Authors. Published by Elsevier Ltd.
Selection and/or peer-review under responsibility of GHGT
doi: 10.1016/j.egypro.2013.06.595
GHGT-11
Geothermal energy production at geologic CO2 sequestration
sites: Impact of thermal drawdown on reservoir pressure
Jimmy B. Randolpha,b,
*
, Martin O. Saara, Jeffrey Bielickic
1University of Minnesota, Department of Earth Sciences, 310 Pillsbury Dr ive SE, Minneapolis, MN 55455, United States
bHeat Mining Company LLC, 19 Main Street, Rapid City, SD 57701, United States
cUniversity of Minnesota, Humphrey School of Public Affairs, 301 19th Avenue S, Minneapolis, MN 55455, United States
Abstract
Recent geotechnical research shows that geothermal heat can be efficiently mined by circulating carbon dioxide
through naturally permeable rock formations -- a method called CO2 Plume Geothermal -- the same geologic
reservoirs that are suitable for deep saline aquifer CO2 sequestration or enhanced oil recovery. This paper describes
the effect of thermal drawdown on reservoir pressure buildup during sequestration operations, revealing that
geothermal heat mining can decrease overpressurization by 10% or more.
© 2013 The Authors. Published by Elsevier Ltd.
Selection and/or peer-review under responsibility of GHGT
Keywords: CO2 sequestration; geothermal energy; CCS; CCUS; carbon dioxide sequestration and utilization; CCS risk
1. Introduction
1.1. Motivation
Part of the effort to limit anthropogenic CO2 emissions to the atmosphere requires that existing and
emerging energy systems shift away from using fossil fuels as primary energy inputs and towards
renewable sources. Renewable sources of energy, including geothermal heat, offer the potential to
produce electricity with little or no operational CO2 emissions. However, the transition towards these
renewable energy sources will be slow, in part because of established infrastructure that naturally turns
over on the order of several decades, and in part because the high energy density of hydrocarbons and
well-developed hydrocarbon power systems result in produced electricity that is inexpensive relative to
emerging renewable options. Given that CO2 emissions are increasing and unlikely to be abated by
* Corresponding author. Tel.: 1-952-457-8959; fax: 1-612-625-3819.
E-mail address: rando035@umn.edu.
Available online at www.sciencedirect.com
© 2013 The Authors. Published by Elsevier Ltd.
Selection and/or peer-review under responsibility of GHGT

6626 Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635
sudden and dramatic changes in how societies capture, convert, and use energy, new technologies that can
use significant quantities of CO2 -- particularly to produce electricity -- may enable transitions to
renewables that are not disruptive to economies and the climate.
While sequestration of CO2 in naturally porous and permeable geologic formations is considered one
of the most feasible methods for preventing significant atmospheric emissions given existing and
upcoming technology [1], large-scale injection of fluid into deep reservoirs has the potential to induce
seismic activity [2]. Such activity may compromise the integrity of CO2 storage formations, leading to
leakage [3]. However, decades of experience with CO2 injection in the oil and gas industry -- as well as
extensive studies specifically concerned with saline aquifer CO2 sequestration -- suggest otherwise [4],
[5]. Nonetheless, in order to maximize CCS safety, public acceptance of CCS, and thus the likelihood of
substantial CCS implementation, technologies and CO2 sequestration operational strategies that minimize
long-term reservoir pressurization should be examined.
Several recent studies have examined the extraction of brine from CO2 injection formations during
sequestration for the purpose of pressure management (e.g., Buscheck et al., 2012 [6]), however we
provide here a preliminary study of the effect of geothermal heat mining on CO2 injection reservoir
pressure management.
1.2. Background -- CO2
Plume Geothermal (CPG) systems.
Numerous previous studies have discussed using supercritical CO2 as the subsurface working fluid for
geothermal energy capture (e.g., [7], [8], [9], [10], [11], [12], [13]). Numerical analyses suggest CO2
transfers heat more efficiently than water, particularly in naturally permeable and porous geologic
formations, i.e., in CO2-Plume Geothermal (CPG) systems (Randolph and Saar, 2010 [11]; 2011[12]), as
a result of its relatively high mobility (inverse kinematic viscosity) and compressibility in deep geologic
formations, the latter contributing to a strong thermosyphon (e.g., Adams et al., in preparation [14]).
Therefore, CO2-based geothermal operations may permit use of lower temperature and lower permeability
geologic formations than those currently deemed economically viable for geothermal development.
CPG systems involve injecting CO2 -- produced by hydrocarbon power systems and/or other industries
-- into deep, naturally permeable geologic formations where the CO2 displaces native reservoir fluid and
is heated by the natural in-situ heat and the background geothermal heat flux. A portion of the heated CO2
is piped to the surface, providing energy for electricity production or direct heat use, before being
returned to the subsurface. The injected CO2 is ultimately geologically stored, as in standard CCS
systems (Figure 1) [12]. As such, CPG results in efficient geothermal power production with a negative
carbon footprint.
Other upcoming advanced geothermal technology -- i.e., engineered geothermal systems (EGS) --
target crystalline rock of low intrinsic permeability and therefore require hydraulic stimulation to form an
artificial reservoir. CPG explicitly avoids such hydrofracturing, reducing geotechnical challenges and
environmental concerns associated with reservoir creation, such as inducing seismicity and contaminating
overlaying freshwater aquifers. Moreover, shallow (1-4 km) and permeable sedimentary formations that
are attractive for CPG can be accessed at lower cost, provide greater heat mining efficiency, and have
significantly larger CO2 sequestration potential than the deep crystalline units considered for EGS.

Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635 6627
Fig. 1. Schematic of Carbon Dioxide Plume (CPG) system, incorporating several system configurations. Modified
from Randolph and Saar, 2011 [12].
Previous studies have predicted that CPG is technically feasible for power generation with geothermal
temperatures above 60 ºC, depending on site-specific geology [12]. Therefore, CPG should naturally
complement geologic CO2 sequestration in numerous sedimentary basins worldwide, enhancing both
CCS and geothermal energy development.
2. Numerical Model Construction
In order to compare CO2 sequestration reservoir evolution with and without geothermal heat energy
extraction, numerical models are constructed using the well-established coupled geologic heat and fluid
flow code TOUGH2 [15] with equation of state module ECO2N [16]. A base-case geologic model is
developed -- see Table 1 for a summary of the assumed geologic conditions and Table 2 for reservoir
fluid properties. The base-case model is evaluated for two cases: CO2 injection only and CO2 injection +
production. A CO2 storage reservoir initial temperature of T = 100 oC, often considered the lower limit for
geothermal electricity production (e.g., [17]), is chosen. Note, though, that T = 150 oC is more typical for
water-based geothermal systems, as ~90% of the US geothermal electrical capacity operates on higher-
temperature (T > 150 oC) dry and flash-steam systems (unpublished data, 2010, available from the
Geothermal Energy Association (http://geo-energy.org/plants.aspx). With a moderate geothermal gradient
of 34 oC/km and an average annual surface temperature of 15 oC -- acceptable average values for the
continental United Statees -- 100 oC is reached at a depth of 2.5 km. Conservative reservoir permeability
and porosity are chosen, consistent with Randolph and Saar, 2011 [12].

6628 Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635
Table 1. Base case numerical model geologic conditions. The following table provides geologic parameters for the base case CO2
injection-only and CO2 injection + production cases. To explore the impact of varying reservoir conditions, additional cases are
examined in which certain critical parameters are adjusted, as described in the text.
Reservoir Parameter/Condition
Value
Reservoir Parameter/Condition
Value
Average depth [m]
2500
Temperature [ oC]
100
Horizontal permeability [m2]
5 x 10-14
Porosity
0.10
Vertical permeability [m2]
1 x 10-14
Rock specific heat [J/kg/oC]
1000
Rock thermal conductivity [W/m/oC]
2.10
Rock grain density [kg/m3]
2650
Thickness [m]
50
Radius [m]
100,000
To permit computational efficiency in this preliminary study, a radially symmetric numerical model is
employed, with a thickness of 50 m and radius of 100 km (Table 1, Table 3). The large radius is chosen to
permit no-flow lateral boundary conditions. The upper and lower reservoir boundaries are also assumed to
permit no fluid flow, although semi-analytic heat transfer is permitted [15]. Note that no-fluid-flow
boundaries constitute a conservative assumption regarding formation pressure buildup during CO2
injection operations, as real reservoirs permit vertical and lateral diffusion of the pressure field. For a
schematic of the numerical grid, see Figure 2. The reservoir injection well serves as the axis of symmetry;
the injection well is assumed to extend over the vertical extent of the formation and inject CO2 equally
over that depth. To permit reservoir fluid extraction, a production well is placed 500 m from the injection
well at the top of the formation. Such a production well location permits CO2 extraction operations to take
advantage of CO2 buoyant flow, maximizing CO2 recovery while minimizing brine extraction. A 500 m
well separation is chosen as it is sufficiently small that injected CO2 will extend from injection well to
production well with the assumed CO2 injection rate, but it is sufficiently large that produced CO2
temperature changes little for the duration of extraction activities. A fully circular production well may
not be employed in an actual CPG development, however its length and positioning are reasonable with
existing well technology.
Table 2. Fluid properties. The following table provides fluid parameters for the base case CO2 injection-only and CO2 injection +
production cases. To explore the impact of varying reservoir conditions, additional cases are examined in which native brine salt
(NaCl) saturation is adjusted, as described in the text.
Fluid property
Value
Fluid property
Value
Residual brine saturation
0.30
Residual CO2 saturation
0.05
van Genuchten m
0.457
van Genuchten a [1/Pa]
5.1 x 10-5
Native brine NaCl saturation [ppm]
100,000
The CO2 injection formation is assumed to be initially filled with a static, 100,000 ppm NaCl brine.
The CO2 injection rate is linearly increased from 0 tonnes/yr to 1 Mtonnes/yr over the course of the first
simulation year, then continued at 1 Mtonnes/yr until year 10, when injection of new CO2 is halted. For
the case with fluid production, the production rate is linearly increased from 0 tonnes/yr to 2 Mtonnes/yr
from the beginning of year 3 to the end of year 4, then continued at this rate (termed the CO2 circulation
rate) for the duration of the simulation (i.e., 25 years). All produced CO2 is re-injected in the injection
well; as such, from year 5 through year 10, the injection well receives 3 Mtonnes/yr.

Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635 6629
Table 3. Numerical model parameters. See the text for additional descriptions.
Numerical Model Parameter/Condition
Value
CO2 injection rate [Mtonnes/yr]
1 (yrs 2-10), increased linearly from 0 during yr 1
CO2 circulation rate, production case [Mtonnes/yr]
2 (yrs 4-25), increased linearly from 0 during yrs 3-4
Number of grid cells, vertical direction
11, thinner towards the top of the reservoir
Number of grid cells, horizontal direction
50: 25m average width to 500m radius, then logarithmically widening
Numerical grid configuration
Radially symmetric about the injection well
Well spacing, production case [m]
500
Well orientation
Vertical (injection), horizontal (production)
Boundary conditions (top/bottom)
No fluid flow, semi-analytic heat exchange
Boundary conditions (lateral)
No fluid or heat flow
Initial conditions
Hydrostatic equilibrium, no flow, all pore space occupied by brine
0100 200 300 400 500 600 700
-2525
-2520
-2515
-2510
-2505
-2500
-2495
-2490
-2485
-2480
-2475
Distance from Injection Well [m]
Depth Below Ground Surface [m]
Cross Section of Model Grid
= Injection Well = Production Well
Fig. 2. Cross section of numerical model grid from injection well to a radius of 750m. The numerical model extends to 100km, with
model cell width logarithmically increasing from a radius of 500m to the lateral edge. Recall, the model is radially symmetri c. This
grid is used for all models, with the exception that no fluid extraction is permitted in the production well in injection-only cases.
To explore parameter space and the effects of variation in critical reservoir conditions, cases in
addition to the base-case are considered. For each additional case, both an injection only and an injection
+ production simulation are run. The following cases are considered (unless otherwise specified, all
system parameters are the same as in the base case): 1) formation initial temperature decreased to 75 oC
(i.e., a 24 oC/km geothermal gradient); 2) formation depth decreased to 1.5 km and temperature, to 66 oC
(consistent with a 34 oC/km geothermal gradient); 3) formation depth decreased to 1.5 km and
temperature, to 81 oC (consistent with a higher geothermal gradient of 44 oC/km); 4) brine NaCl
saturation increased to 200,000 ppm; 5) brine NaCl saturation decreased to 0 ppm; and 6) reservoir
permeability increased to 1 x 10-13 m2 (horizontal) and 5 x 10-14 m2 (vertical). To summarize, 7 cases for a
total of 14 situations are analyzed.

6630 Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635
3. Wellbore flow
Supercritical CO2 compresses and increases in temperature during injection, whereas it expands and
cools during production (Figure 3). Thus, while CO2 is assumed to have an injection wellhead
temperature of 15 oC, bottomhole conditions must be calculated. A non-isentropic wellbore flow model is
developed using Engineering Equation Solver, which allows for frictional losses in the injection and
production wells. Note, though, that heat transfer away from the well is not considered, as previous
studies have found it negligible (Randolph et al., 2012 [18]). Injection wellhead pressure is set for each
injection and injection + production case such that injection well bottomhole pressure matches the well
gridblock values determined by the TOUGH2 reservoir models.
-2500
-2000
-1500
-1000
-500
0
15 25 35 45 55 65 75 85 95
Depth from Ground Surface
[m]
Temperature [deg C]
Injection well, depth=1.5km Injection well, depth=2.5km, k=5 x 10^-14 m^2
Injection well, depth=2.5km, k=1 x 10^-13 m^2 Production well, reservoir T=66 deg C
Production well, reservoir T=81 deg C Production well, reservoir T=75 deg C
Production well, reservoir T=100 deg C
Fig. 3. Injection and production well temperature profiles. Unless otherwise specified in the figure legend, model parameters
correspond to base case conditions. Supercritical CO2 compresses and increases in temperature during injection, whereas it expands
and cools during production. This behavior can result in a thermosyphon, which can circulate CO2 through the subsurface as well as
the surface system without the need for pumping (Adams, et al., in preparation [14]).
4. Reservoir Numerical Model Results
4.1. Base case pressure, temperature, and gas saturation
Here, we examine vertical cross sections through the base-case geologic injection and injection +
production models, considering a snapshot 10 years after the onset of injection (i.e., immediately before
the injection of new CO2 at 1 Mtonnes/yr ceases). Figure 4 reveals contours of formation temperature,
with the injection-only case at left and the injection + production case at right. Considering Figure 3, we
see that CO2 injection bottomhole temperature is 46 oC. In the injection-only case, the thermal front
extends to less than 500 m, and the temperature contours reveal subdued buoyant flow, a consequence of
anisotropic permeability (simulated in order to capture the common sub-layering within sedimentary
formations). In the injection + production case, we see a small degree of production well thermal
breakthrough as well as considerably more of the formation at a temperature less than 50 oC. The latter is
a result of considerably more cold CO2 being circulated than in the injection-only case.

Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635 6631
Distance fro m Injection We ll [m]
Depth Below Ground Surface [m]
T 10 Yrs After Onse t of Injection, No Prod uction, [
o
C]
0100 200 300 400 500
-2520
-2515
-2510
-2505
-2500
-2495
-2490
-2485
-2480
Distance fro m Injection We ll [m]
T 10 Yrs After Onse t of Injection, with CO2 P roducti on, [oC]
0100 200 300 400 500
0
5
0
5
0
5
0
5
0
50
60
70
80
90
100
Fig. 4. Temperature sections, base-case reservoir models.
Distance fro m Injection We ll [m]
Depth Below Ground Surface [m]
Gas Sat. 10 Yrs After Onset of Injection, No Producti on
0200 400 600 800 1000
-2520
-2515
-2510
-2505
-2500
-2495
-2490
-2485
-2480
Distance fro m Injection We ll [m]
Gas Sat. 10 Yrs After Onset of Injection, with CO2 Prod.
0200 400 600 800 1000
0.1
0.2
0.3
0.4
0.5
0.6
Fig. 5. CO2 saturation sections, base-case reservoir models.
Distance fro m Injection We ll [m]
P Increase 10 Yrs Afte r Onset of Injectio n, with CO2 Prod . [MPa]
0200 400 600 800 1000
0
5
0
5
0
5
0
5
0
4
4.5
5
5.5
6
Distance fro m Injection We ll [m]
Depth Below Ground Surface [m]
P Increase 10 Yrs Afte r Onset of Injection, No Pro d. [MPa]
0200 400 600 800 100
0
-2520
-2515
-2510
-2505
-2500
-2495
-2490
-2485
-2480
Fig. 6. Pressure sections, base-case reservoir models.

6632 Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635
In Figure 5, we see CO2 saturation sections for both injection and injection + production cases. Notice
that injected CO2 effectively dries out the formation in the vicinity of the injection well. Farther from the
injection well, most mobile brine has been displaced, leaving only 30% residual brine saturation. In the
production case, this well and fluid injection/production configuration results in nearly pure CO2 being
produced (97% or greater at all times, and 99% or greater for the majority of times, not shown). The
injection + production case reveals some upconing of the CO2 saturation contours in the vicinity of the
production well. However, this does not translate to brine being produced with CO2, indicating effective
system design for CPG operations.
Pressure contours are shown in Figure 6. Notice that the contour levels are very similar between the
injection-only and the injection + production cases for radii greater than approximately 500 m (i.e., the
production well). However, pressure near the injection well is higher in the injection + production case
than in the injection-only case, a consequence of more CO2 being injected in the former than the latter.
Future modeling will examine scenarios to avoid this near-injection-well pressure increase in CPG
systems -- for example, through the use of multiple, spatially-distributed injection wells and staged well
installation.
4.2. Reservoir pressure change: Base case and exploration of parameter space
Here, we examine the change in reservoir pressure above pre-injection values, for the top of the
formation from the injection well to a radius of 5 km, comparing the base case to all other examined
cases. Figure 7 displays such profiles 10 years after the onset of CO2 injection, i.e., immediately before
injection of 1 Mtonnes/yr of new CO2 ceases. Notice that during this injection period, the profiles for
injection-only and injection + production are very similar for radii greater than 500 m, with the injection
+ production cases showing higher pressures for smaller radii, consistent with Figure 6.
01000 2000 3000 4000 5000
1
2
3
4
5
6
7
8
Distance from Injection Well [m]
Reservoir Overpressurization [MPa]
10 Years After Onset of Injection
No Product ion, T = 66 oC, Depth = 1. 5 km
CO2 Product ion, T = 66 oC, Dept h = 1. 5 km
No Product ion, T = 81 oC, Depth = 1. 5 km
CO2 Product ion, T = 81 oC, Dept h = 1. 5 km
No Product ion, Bri ne Salt Concentrat ion = 20%
CO2 Product ion, B rine Salt Concent ration = 20%
No Product ion, T = 75 oC
CO2 Product ion, T = 75 oC
No Product ion, B ase Case
CO2 Production, Base Case
No Product ion, B rine Salt Concentrat ion = 0%
CO2 Product ion, B rine Salt Concent ration = 0%
No Product ion, Res ervoir k = 1x10-13 m2
CO2 Product ion, Res ervoir k = 1x10 -13 m2
Fig. 7. Pressure profiles at the top of the formation 10 years after the onset of injection (i.e., immediately before injection of 1
Mtonnes/yr of new CO2 ceases).

Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635 6633
01000 2000 3000 4000 5000
0
0.5
1
1.5
2
Distance from Injection Well [m]
Reservoir Overpressurization [MPa]
15 Years After Onset of Injection
No Product ion, T = 81
o
C, Depth = 1.5 km
CO
2
Product ion, T = 81
o
C, Dept h = 1. 5 k m
No Product ion, T = 66
o
C, Depth = 1.5 km
CO
2
Product ion, T = 66
o
C, Dept h = 1. 5 k m
No Product ion, Bri ne Salt Concentrat ion = 20%
CO
2
Product ion, B rine Salt Concentrat ion = 20%
No Product ion, T = 75
o
C
CO
2
Product ion, T = 75
o
C
No Product ion, Bas e Case
CO
2
Product ion, B ase Case
No Product ion, Bri ne Salt Concentrat ion = 0%
CO
2
Product ion, B rine Salt Concentrat ion = 0%
No Product ion, Res ervoir k = 1x10
-13
m
2
CO
2
Product ion, Res ervoir k = 1x10
-13
m
2
Fig. 8. Pressure profiles across the top of the CO2 injection formation 15 years after the onset of injection.
Figure 8 displays the same profiles as Figure 7, however with the former being 5 simulated years later.
Clearly, reservoir pressure has diffused considerably since injection of new CO2 ended, and pressure
values are gradually trending towards pre-injection levels. Notice that for all cases, the injection +
production values are less than those for the corresponding injection-only simulation, with the difference
being 10% or more of the total overpressurization. Thermal drawdown and the associated increase in CO2
density in cooled regions of the reservoir do, therefore, decrease formation pressure in the long term.
Considering Figures 7 and 8, we see that CO2-injection-resultant pressure increase in the reservoir is
lower for higher permeability, as would be expected -- brine can more easily flow away from the injection
well. Similarly, the degree of pressure buildup is directly proportional to brine salt saturation. Moreover,
pressure buildup increases with decreasing temperature, a logical result since formation native and
injected fluids are less mobile at lower temperatures and thus, more slowly move away from the injection.
0 5 10 15 20 25
0
0.5
1
1.5
2
2.5
3
3.5
Time [years]
Overpressure Difference [MPa]
Difference in P Increase at Production Well Node
T = 8 1 oC, Depth = 1. 5 km
T = 6 6 oC, Depth = 1. 5 km
Brine Sal t Concent ration = 20%
T = 7 5 oC
Base Case
Brine Sal t Concent ration = 0%
Reservoir k = 1x10 -13 m2
Fig. 9. Difference in pressure at the production well node between the injection-only and injection + production simulations. Note
that the baseline for each curve is offset so that all curves can be visualized together.

6634 Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635
Finally, Figure 9 shows, for each case, the pressure in the production well grid cell in the injection-
only case minus the pressure in the same cell in the injection + production case. Pressure is shown as a
function of time, and the baselines are vertically offset so that the various lines do not overlap. Increments
on the y axis serve to provide a vertical scale. Figure 9 shows that reservoir thermal drawdown can
decrease long-term overpressurization by 0.1 to 0.3 MPa, given the geologic and CO2
injection/production conditions assumed here.
5. Discussion
This preliminary study demonstrates that geothermal heat extraction from a geologic CO2
sequestration formation using CO2 as the subsurface heat transfer fluid -- a method termed CO2 plume
geothermal (CPG) -- can eliminate approximately 10% of the reservoir overpressurization caused by
subsurface fluid storage. While relatively small, this degree of pressure management is not
inconsequential, helping in particular to decrease the lateral extent of reservoir pressure perturbation.
To enhance this examination and determine whether more significant CO2 reservoir pressure
management can be achieved with geothermal heat mining, additional scenarios will be simulated in the
future. In particular, we will consider varying placement and number of injection and production wells,
increased CPG circulation and heat extraction rates, and brine extraction and reinjection. Thermal
drawdown and associated pressure management constitute a nice ancillary benefit of CPG, itself
potentially of significant value to CCS because it converts geologically stored CO2 into a resource for
revenue and renewable energy generation.
Acknowledgements
Research support was provided by 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); by
the US Department of Energy (DOE) Geothermal Technologies Program under grant number DE-
EE0002764; and by the National Science Foundation (NSF) under grant number CHE-1230691.
J. B. Randolph is a Scientific Advisor to Heat Mining Company (HMC) LLC, and M. O. Saar is Chief
Scientific Officer of HMC. Any opinions, findings, conclusions, or recommendations in this material are
those of the authors and do not necessarily reflect the views of the DOE, NSF, IREE, IonE, UMN, or
HMC LLC. Patents regarding the CPG technology have been filed by and granted to the UMN and
licensed exclusively and worldwide to HMC LLC.
References
[1] Metz B, Davidson O, de Coninck HC, Loos M, Meyer LA, editors. IPCC Special Report on Carbon Dioxide Capture and
Storage. Cambridge, GB and New York, NY, US: Cambridge University Press. 2005.
[2] Hitzman MW, Clarke DD, Detournay E, Dieterich JH, Dillon DK, Green SJ, et al. Induced Seismicity Potential in Energy
Technologies. Washington, D.C., US: The National Academics Press. Prepublication 2012.
[3] Zoback MD, Gorelick SM. Earthquake triggering and large-scale geologic storage of carbon dioxide. PNAS, 2012. doi:
10.1073/pnas.1202473109.
[4] Haszeldine S. Comment on Zoback and Gorelick 2012, Scottish Carbon Capture and Storage, www.sccs.org.uk, 2012.

Jimmy B. Randolph et al. / Energy Procedia 37 ( 2013 ) 6625 – 6635 6635
[5] Thompson J. Statement from John Thompson, Director, Fossil Transition Project, on opinion paper by Dr. Mark Zoback et al.
on seismic risk of geologic storage of carbon dioxide, Clean Air Task Force, 2012.
[6] Buscheck TA, Sun Y, Chen M, Hao Y, Wolery TJ, Bourcier WL, et al. Active CO2 reservoir management for carbon storage:
analysis of operational strategies to relieve pressure buildup and improve injectivity, International Journal of Greenhouse Gas
Control, 2012, 6: 230 245. doi:10.1.1016/j.ijggc.2011.11.007.
[7] Brown D. A hot dry rock geothermal energy concept utilizing supercritical CO2 instead of water. Proceedings of the Twenty-
Fifth Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, CA, 2000, 233 8.
[8] Pruess K. Enhanced geothermal systems (EGS) using CO2 as working fluid a novel approach for generating renewable energy
with simultaneous sequestration of carbon. Geothermics, 2006, 35: 351-367.
[9] Pruess K. On production behavior of enhanced geothermal systems with CO2 as working fluid, Energy Conversion and
Management, 2008, 49: 1446-1454.
[10] At rens AD, Gurgenci H, Rudolph V. CO2 thermosyphon for competitive geothermal power generation, Energy and Fuels, 2009
23: 553-7.
[11] Randolph JB, Saar MO. Coupling geothermal energy capture with carbon dioxide sequestration in naturally permeable, porous
geologic formations: A comparison with enhanced geothermal systems, Geothermal Resource Council Transactions, 2010, 34:
433-8.
[12] Randolph JB, Saar MO. Combining geothermal energy capture with geologic carbon dioxide sequestration, Geophysical
Research Letters, 2011, 38: L10401. doi:10.1029/2011GL047265.
[13] Saar MO, Randolph JB, Kuehn TH. Carbon dioxide-based geothermal energy generation systems and methods related thereto,
US Patent Application 20120001429, 2009.
[14] Adams B, Randolph JB, Bielicki JM, Kuehn TM, Saar MO. A self-developing thermosyphon for carbon dioxide plume
geothermal energy. 2012 in preparation.
[15] Pruess K. The TOUGH codes A family of simulation tools for multiphase flow and transport processes in permeable media,
Vadose Zone Journal, 2004, 3: 738 746.
[16] Pruess K. ECO2N: A TOUGH2 fluid property module for mixtures of water, NaCl, and CO2, Rep. LBNL-57952, Lawrence
Berkeley National Laboratory, Berkeley, CA., 2005.
[17] Hulen JB, Wright PM. Geothermal energy: Clean, sustainable energy for the benefit of humanity and the environment, Energy
& Geoscience Institute, University of Utah, Salt Lake City, UT, 2001.
[18] Randolph JB, Adams B, Kuehn TH, Saar MO. Wellbore heat transfer in CO2-based geothermal systems,Geothermal Resources
Council Transaction, 2012, 36.