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OUTLINE

 1.  Highlights
 2.  Abstract
 3.  Abbreviation
 4.  Keywords
 5.  1. Introduction
 6.  2. Methods
 7.  3. Results and discussion
 8.  4. Conclusions and suggestions for future investigations
 9.  Declaration of Competing Interest
 10. Acknowledgments
 11. Appendix A. Supplementary data
 12. References

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CITED BY (8)




FIGURES (9)

 1. 
 2. 
 3. 
 4. 
 5. 
 6. 

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TABLES (4)

 1. Table 1
 2. Table 2
 3. Table 3
 4. Table 4




EXTRAS (1)

 1. Supplementary data 1




ENERGY CONVERSION AND MANAGEMENT

Volume 253, 1 February 2022, 115082



FLEXIBLE CO2-PLUME GEOTHERMAL (CPG-F): USING GEOLOGICALLY STORED CO2 TO PROVIDE
DISPATCHABLE POWER AND ENERGY STORAGE

Author links open overlay panelMark R. Fleming a, Benjamin M. Adams b, Jonathan
D. Ogland-Hand b, Jeffrey M. Bielicki c d, Thomas H. Kuehn a, Martin O. Saar b e
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HIGHLIGHTS

 * •
   
   Introduce Flexible CO2-Plume Geothermal (CPG-F) facilities.

 * •
   
   CPG-F can provide dispatchable power, energy storage, or both simultaneously.

 * •
   
   There are multiple optimum design points that may be in tension with one
   another.




ABSTRACT

CO2-Plume Geothermal (CPG) power plants can use geologically stored CO2 to
generate electricity. In this study, a Flexible CO2 Plume Geothermal (CPG-F)
facility is introduced, which can use geologically stored CO2 to provide
dispatchable power, energy storage, or both dispatchable power and energy
storage simultaneously—providing baseload power with dispatchable storage for
demand response. It is found that a CPG-F facility can deliver more power than a
CPG power plant, but with less daily energy production. For example, the CPG-F
facility produces 7.2 MWe for 8 h (8 h-16 h duty cycle), which is 190% greater
than power supplied from a CPG power plant, but the daily energy decreased by
61% from 60 MWe-h to 23 MWe-h. A CPG-F facility, designed for varying durations
of energy storage, has a 70% higher capital cost than a CPG power plant, but
costs 4% to 27% more than most CPG-F facilities, designed for a specific
duration, while producing 90% to 310% more power than a CPG power plant. A CPG-F
facility, designed to switch from providing 100% dispatchable power to 100%
energy storage, only costs 3% more than a CPG-F facility, designed only for
energy storage.

 * Previous article in issue
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ABBREVIATION

CPG
Carbon Dioxide Plume Geothermal


KEYWORDS

Carbon Dioxide
Geothermal Energy
Renewable Energy
Carbon Dioxide Plume Geothermal (CPG)
Large-scale energy storage
Operational Strategies


1. INTRODUCTION

Least-cost pathways that limit the increase of global mean surface temperatures
to 2 °C, or less, rely on decarbonizing the electricity sector by transitioning
to a portfolio of low-carbon energy technologies and processes that work
synergistically to meet electricity demand [1], [2], [3], [4], [5]. For example,
future least-cost decarbonized electricity systems will likely be comprised of
technologies and processes that provide 1) electricity generation from variable
renewable resources (e.g., wind, sunlight), 2) balancing services (e.g.,
batteries, demand response) that adjust supply or demand, 3) carbon-dioxide
(CO2) storage services (e.g., as part of a CO2 capture and storage (CCS)
process) that permanently isolate emissions from the atmosphere by storing them
in deep naturally porous and permeable aquifers, and 4) dispatchable power that
can be delivered whenever needed (e.g., flexible nuclear power plants,
fossil-fuel power plants that are part of CCS processes) [6], [7], [8]. As a
result of this synergistic operation, low-carbon electricity system technologies
or processes that can provide more than one of these four services will likely
be valuable.

CO2 was initially proposed as a working fluid in Enhanced Geothermal Systems
(EGS) by Brown [9]. CO2 has three primary advantages over brine: 1) in contrast
to liquid water, CO2 is highly compressible, allowing the system to generate a
thermosiphon, reducing or eliminating the need for circulation pumps [9], [10],
[11], [12], [13], 2) CO2 has a lower kinematic viscosity which reduces the
pressure losses through the rock in the reservoir [14], [15], and 3) CO2 has a
lower mineral solubility that will reduce pipe and equipment scaling [9]. In
CO2-EGS systems, CO2 was found to have higher heat extraction rates than brine
and develop a thermosiphon [10], [11], [16]. However, CO2-EGS has large-scale
deployment issues, for example, it has a limited CO2 storage potential due to
the limited volume of the fractured reservoir [17], [18]. In contrast, a
different CO2-based geothermal system, first introduced by Randolph and Saar
[17], who termed it CO2-Plume Geothermal (CPG), uses common and expansive
sedimentary basins with low-permeability caprocks that limit the leakage of
buoyant CO2 [19], [20], [21], [22]. These basins have large CO2 storage
potential and are a target for Carbon Capture and Storage (CCS) efforts [19],
[23]. Previous studies have shown the effectiveness of CPG systems at extracting
heat and pressure energy from subsurface reservoirs [17], [18], [24], [25],
[26], [27], [28], power production driven by a thermosiphon [29], the benefits
of using CO2 over brine in sedimentary basins [12], [30], [31], and how CPG can
be used in depleted natural gas reservoirs [33] or depleted oil reservoirs [34].

Recent efforts have investigated technologies that use geologically stored CO2
from CCS processes and geothermal energy resources to provide energy storage or
dispatchable power: CO2-Plume Geothermal (CPG) power plants [12], [29], [35],
[36], CO2-Bulk Energy Storage (CO2-BES) facilities [37], and Compressed CO2
Energy Storage (CCES) facilities [38]. For example, CPG power plants provide
dispatchable power by intentionally producing geologically stored CO2 to the
surface, expanding it through a turbine to generate electricity, then cooling,
condensing, and re-injecting it into the subsurface [12], [24], [26], [29],
[39]. CCES facilities use CO2 compressed in a multi-level subsurface reservoir
in combination with a surface heat source to provide energy storage. CO2-BES
facilities, in contrast, can provide dispatchable power or energy storage by
alternating the timing of fluid (CO2 and/or brine) injection, production, and
re-injection [40]. As a result, these CO2-geothermal energy systems are likely
to have value to decarbonization efforts because they can directly reduce CO2
emissions by sequestering them in the subsurface while indirectly reducing CO2
emissions by working with other low-carbon technologies to meet demand [41].

This paper introduces another novel development in CO2-geothermal energy
systems: Flexible-CO2 Plume Geothermal (CPG-F) facilities. A CPG-F facility is
distinguished from a standard CPG power plant because CPG-F facilities make use
of a second, shallower aquifer within a given sedimentary basin geothermal
resource, which enables additional operational capabilities compared to
previously studied CPG power plants. In CPG-F facilities, geothermally-heated
CO2 is produced to the surface as during standard CPG power plant operations,
expanded through a high-pressure turbine to produce power, and then the option
exists to either a) inject a portion or all of the expanded CO2 in the shallow
reservoir for temporary storage or b) expand the CO2 through another
low-pressure turbine to produce more power before cooling and reinjecting it
into the deeper reservoir like in a standard CPG power plant. If CO2 is injected
into the shallow reservoir, CPG-F operators would later produce it back to the
surface, cool it, and then reinject it into the deeper reservoir. Temporarily
storing the CO2 in the shallow reservoir effectively time-shifts the parasitic
cooling and pumping power loads, thus allowing CPG-F facilities to provide
energy storage services for demand response. In this way, CPG-F facilities are
similar to CO2-BES facilities because they can provide energy storage or
dispatchable power, but by only circulating CO2. In contrast to CO2-BES
facilities, however, because it is possible to only divert a portion of the
produced CO2 to shallow reservoir storage, a CPG-F facility can also provide
both dispatchable power and energy storage, simultaneously—providing baseload
power with dispatchable storage for demand response. A CPG-F system is different
from other CO2-based subsurface energy storage systems. For example, a CO2-Bulk
Energy Storage (CO2-BES) system uses a reservoir that is initially filled with
native brine, into which CO2 is injected and used as a cushion gas to moderate
the reservoir pressure during disjoint brine production and injection phases
[42], [43]. The produced brine must be stored at the surface, and the
differences between the brine production and injection phases provide the energy
generation and storage, much like a pumped hydroelectric energy storage system.
Compressed CO2 Energy Storage (CCES) is another approach. It is similar to a
CPG-F system, in that it exchanges CO2 between high- and low-pressure reservoirs
[38], but the CCES system only uses geothermal heat to pre-heat the CO2; most of
the heat is added at the surface by combusting a fuel. Thus, CPG-F is a unique
system that operates primarily with geologic CO2, requires no surface storage of
fluid, and has no fossil fuel heat source.

Given the flexibility of this system, there are more questions to address when
designing a CPG-F facility compared to designing a CPG power plant. For example,
what service to provide? What CO2 production flowrate should the facility be
designed around? If the CPG-F facility will not be providing strictly
dispatchable power (i.e., a CPG power plant), over what duration(s) will the
CPG-F facility time-shift electricity? These questions are not independent, and
the answers will vary depending on the cost and performance of the CPG-F
facility, the value of the provided service(s) to the electricity system, and
the rate at which CPG-F operators are compensated by electric market rules for
providing the service(s).

In this study, as a starting point towards answering these interdependent
questions, we provide an initial investigation into the performance and capital
cost of a CPG-F facility designed to provide different services. We focus
primarily on CPG-F facilities designed to provide only energy storage because
our prior work focuses on systems that provide only dispatchable power (i.e.,
CPG power plants) and it is unknown if providing both dispatchable power and
energy storage services simultaneously has value to the electricity system.
Section 2 provides an overview of the CPG-F system and the tools and methods
used to simulate its operation and estimate cost; Section 3 compares a CPG power
plant to a CPG-F facility by presenting optimal operational decisions (e.g., CO2
production flowrates) across a range of diurnal energy storage duty cycles that
a) maximize net energy production, b) maximize power production, c) zero-out the
daily net energy storage, and d) minimize cost; and Section 4 discusses the
primary findings and potential avenues for future work.


2. METHODS

Section 2.1, presents a description of a CPG-F facility and how the components
are operated to provide different services. Following that identification,
Section 2.2 describes how CPG-F is modeled, and then Section 2.3 provides the
cost analysis methodology. The nomenclature is defined in Table 1.

Table 1. Nomenclature

VariableParameterAArea [m2]CCost [$]fFriction factor [-]gGravitational
acceleration [m/s2]ηEfficiency [-]hEnthalpy [kJ/kg]λParasitic loss fraction
[-]ṀDaily CO2 Circulation Rate [kt/day]ṁMass Flow Rate [kg/s]mfMass Fraction
[-]PPressure [kPa]Q̇Heat Rejection [kW]ρDensity [kg/m3]SCCSpecific Capital Cost
[$/kWe]TTemperature [°C]tTime [h]TPCCTotal Project Capital Cost [$]VVelocity
[m/s]ẆPower [kWe]WEnergy [kWe-h]xCost Fraction [-]ZReservoir Thickness
[m]zReservoir Depth [m]
UnitDescriptionMWeMegawatt (electrical)MWthMegawatt (thermal)MWe-hMegawatt hour
(electrical)MWth-hMegawatt hour (thermal)KtKiloton (metric)MtMegaton (metric)


2.1. OVERVIEW OF CPG-F

This section presents a system diagram differentiating how a single CPG-F
facility would be operated to provide three different services, if designed to
do so: 1) dispatchable power, 2) energy storage, or 3) both dispatchable power
and energy storage simultaneously.

2.1.1. CPG-F OPERATED TO PROVIDE DISPATCHABLE POWER

The solid red lines in Fig. 1 highlight the system components that are used when
CPG-F is operated to provide dispatchable power: a deep porous and permeable
aquifer beneath a low- to zero-permeability caprock, a surface power plant, and
vertical injection and production wells [17], [18], [25]. Geologically stored
CO2 that is heated by the geothermal heat flux (State 1) is produced from the
geothermal reservoir to the surface through vertical wells (State 2). That CO2
is expanded in a high-pressure turbine (HPT) (State 3) and a low-pressure
turbine (LPT) (State 4) to generate electricity. These turbines are shown
separately, but they may be combined into a single stage if the CPG-F facility
is designed to only provide dispatchable power (i.e., a CPG power plant). After
the turbines, the CO2 is cooled using a wet cooling tower (State 5). If used, a
production pump can increase the pressure of the CO2 (State 6) to achieve the
necessary downhole pressure (State 7). A production pump is not required to
drive fluid production, but using one generally increases the net power
production of the system [12], [29].

 1. Download : Download high-res image (427KB)
 2. Download : Download full-size image

Fig. 1. (A) System diagram for a CPG-F facility operating to provide
dispatchable power (red lines), energy storage (blue lines for power
consumption; green lines for power generation), and both services simultaneously
(red + green + blue lines). The CO2 gas saturation with mesh grid overlay of the
shallow (B) and deep (C) reservoirs at the end of the CO2 plume development
period and start of the energy storage operation. (For interpretation of the
references to colour in this figure legend, the reader is referred to the web
version of this article.)

2.1.2. CPG-F OPERATED TO PROVIDE ENERGY STORAGE

When a CPG-F facility is operated to provide energy storage, the shallow
reservoir is used to temporally store the CO2, effectively creating two
different processes from the surface components – one using the power cycle
components that produce power (i.e. the turbine), and the other that uses the
components that store, or consume, power (i.e. the cooling towers and the pump).
Energy storage occurs by alternating between two modes:

 * 1.
   
   Electricity Generation (Dispatch) (Green lines in Fig. 1): The CO2 is
   produced from the deep reservoir (State 1), brought to the surface in the
   production well (State 2), and expanded in the HPT (State 3) to produce
   power. After the HPT, the CO2 is minimally cooled in a cooling tower (State
   8) to increase the density of the CO2 enough to obtain the necessary downhole
   pressure to inject the CO2 into the shallow reservoir (State 9). By
   increasing the CO2 density in the injection well, the downhole pressure is
   increased, which is less energy intensive than pumping [44]. In the shallow
   reservoir, the CO2 is stored isothermally. During this mode, the gross
   turbine power less the parasitic power—the power required to operate the
   pre-injection cooling tower (States 2 to 8)—is positive.

 * 2.
   
   Power Consumption (Storage) (Blue lines in Fig. 1): The CO2 that is stored in
   the shallow reservoir (State 10) is produced to the surface through the
   vertical well (State 11). Then, similar to when the CPG-F facility is
   operated for dispatchable power, the density of the CO2 is increased in the
   cooling towers (State 5), it is pumped (State 6), and reinjected into the
   deep reservoir (State 7). Although shown in Fig. 1, the throttling valve
   between States 11 and 4 is not used when a CPG-F facility is designed to only
   provide energy storage as a stand-alone system because the pressure in the
   cooling tower (State 4) is equivalent to the wellhead pressure from the
   shallow reservoir (State 11).



When operating to provide energy storage, the shallow reservoir is used to
temporarily store CO2 and is not the primary source of extracting geothermal
heat. Also, note that when operated to provide energy storage, a CPG-F facility
cannot use the LPT that is used when operated to provide dispatchable power. The
same pressure difference between States 3 and 4 that is used for generating
dispatchable power in the LPT is lost in piping and reservoir frictional losses
when storing CO2 in the shallow reservoir. Thus, the thermal efficiency of CPG-F
facility when operating to provide energy storage will be inherently lower than
when operating to provide dispatchable power.

2.1.3. CPG-F OPERATED TO PROVIDE BOTH DISPATCHABLE POWER AND ENERGY STORAGE
SIMULTANEOUSLY

The facility operates continuously to generate dispatchable electricity, while
also providing either additional power production (electricity generation mode)
or power consumption (storage mode). Despite being called the storage mode, the
combined power output of the CPG-F facility operated in this way may still be
positive if the power that is being consumed is less than the dispatchable power
that being produced at the same time.

When a CPG-F facility is operated to provide dispatchable power and to produce
power that was previously stored, the CO2 stream is split after the
high-pressure turbine (State 3). The fraction of CO2 for energy storage is
cooled (State 8) and injected into the shallow reservoir for storage (State 9).
The remaining CO2 stream is further expanded in the low-pressure turbine (State
4) to produce power, then cooled (State 5), compressed (State 6), and
re-injected back into the deep reservoir (State 7). The split flow stream allows
the system to vary from operating 100% for dispatchable power to operating 100%
for energy storage, designated by the mass flow rate division, detailed in
Section 2.2.2.

When the CPG-F facility is operated to provide dispatchable power and to consume
(store) additional power for later, the fraction of CO2 for energy storage is
produced from the shallow reservoir (State 10), arrives at the surface (State
11), is throttled to the turbine back-pressure (State 4), and then re-combined
with the CO2 stream leaving the low-pressure turbine. The produced CO2 is
typically supercritical at the wellhead pressure (State 11) and thus larger than
the LPT backpressure (State 4). Additionally, the wellhead pressure decreases as
the shallow reservoir depletes of CO2. Thus, a throttling valve is added to
reduce the wellhead pressure (State 11) to the constant condenser pressure
(State 4).


2.2. SYSTEM MODELING

The CPG-F facilities are simulated using two separate models: the subsurface
reservoir model and the surface power plant model. The subsurface reservoir is
modeled using TOUGH2 [45] with the ECO2N [46] equation of state module. The
wells and the surface power plant are modeled using Engineering Equation Solver
(EES) [47]. The computational workflow constitutes: 1) simulate the deep
reservoir, 2) simulate the shallow reservoir, 3) input the reservoir model
output into the well and surface power plant model; then these steps are
iterated for each mass flow rate and duty cycle.

2.2.1. RESERVOIR MODELING

An overview of the multi-reservoir system with the injection and production well
design is shown in Fig. 2. Each reservoir is a two-dimensional, axisymmetric
model using the reservoir parameters given in Table 2. The reservoirs are
initially filled with 20% NaCl (by weight) brine. Both the deep and the shallow
reservoirs have horizontal and vertical permeabilities of 5 × 10-14 m2 (50 mD)
and a porosity of 10% as these are the base case conditions we have employed
before, such as in [12], [17], [24], [27], [30]. The temperature of each
reservoir is determined using a thermal gradient of 35 °C/km, resulting in an
average reservoir temperature of 102.5 °C for the deep reservoir at 2.5 km depth
and 67.5 °C for the shallow reservoir at 1.5 km depth, consistent with previous
studies [12], [48], [49]. The initial reservoir pressure is determined using the
hydrostatic pressure, resulting in initial pressures of 25 MPa and 15 MPa for
the deep and the shallow reservoirs, respectively. Both reservoirs have a
thickness of 300 m. The simulated reservoir radius is 100 km, consistent with
previous models [24], to limit pressure boundary effects as the CO2 plume size
changes and as no-fluid-flow boundary conditions are applied on all sides.
Additionally, the conductive heat flux across the top and bottom boundaries is
modeled using a semi-analytic solution [45].

 1. Download : Download high-res image (136KB)
 2. Download : Download full-size image

Fig. 2. An overview of the horizontal and vertical well configuration for both
the shallow reservoir (blue wells) and the deep injection (red wells) and the
deep production wells (black). The bounding caprock and baserock formations are
indicated in the figure by the gray planes. The shallow well (blue) is a
huff-and-puff well as minimal heat exchange with the surrounding formation is
desired. The deep reservoir is accessed via a deeper injection well (red) and
fluid (mostly CO2) is produced from production wells (black), where the
horizontal collection well component is located immediately below the caprock
(see also Fig. 1). Note that in practice, the horizontal wells would likely not
be circular but rather linear or bent as the CO2 plume is likely to be diverted
in a preferred direction (up-caprock-dip) as described in Garapati et al. (2015)
[24]. Circular wells are chosen here mainly as they simplify numerical modeling
and figure display. (For interpretation of the references to colour in this
figure legend, the reader is referred to the web version of this article.)

Table 2. Reservoir physical properties for the numerical simulation.

Simulated Parameter/ValueGeneral PropertiesDeep ReservoirHorizontal
Permeability5.0 × 10-14 m2 (50 mD)Mean Reservoir Depth2.5 kmVertical
Permeability5.0 × 10-14 m2 (50 mD)Initial Reservoir Temperature102.5 °CThermal
Conductivity2.1 W/m/°CInjection Horizontal Well Radius200 mPorosity10%Production
Horizontal Well Radius707 mNaCl Concentration20%Number of grid cells,
vertical42Geothermal Gradient35 °C/kmNumber of grid cells,
horizontal117Reservoir Thickness300 mRock Density2650 kg/m3Shallow ReservoirRock
Specific Heat1000 J/kg/°CMean Reservoir Depth1.5 kmSimulated Radius100 kmInitial
Reservoir Temperature67.5 °CInitial ConditionsHydrostatic equilibrium, pore
space occupied by brineHorizontal Well Radius400 mNumber of grid cells,
vertical34Boundary Condition Top/BottomNo fluid flow, semi-analytic heat
transferNumber of grid cells, horizontal121Boundary Condition LateralNo fluid or
heat transfer

2.2.1.1. DEEP RESERVOIR

Geothermal heat is extracted from the deep reservoir which acts and the thermal
energy source in CPG-F facilities. The deep reservoir has two horizontal wells:
an injection well and a production well, shown in Fig. 1, Fig. 2. The injection
well is horizontal, located at the bottom of the reservoir at a radius of 200 m
from the center axis and is connected to a single vertical injection well. This
differs from previous work, which used a single vertical injection well with no
horizontal component [12], [24], [26], [29], [50]. The injection well is located
at the bottom of the reservoir to increase the volume swept by the CO2 plume, as
the CO2 will buoyantly rise towards the caprock, extracting heat from the entire
thickness of the reservoir. At the top of the reservoir, the CO2 accumulates
beneath the caprock. The horizontal production well is located just beneath the
caprock at a radius of 707 m, consistent with prior work [12], [24], [25], [26],
[29], and the horizontal production well is connected to four vertical
production wells, spaced equidistant along the horizontal well. Unlike a
vertical production well, a horizontal production well under the caprock limits
the brine produced with CO2 as the entire well is in a CO2-rich location.
Horizontal wells within the reservoir are used to reduce the overall reservoir
pressure losses as a horizontal well is longer, has increased surface area, and
thus can facilitate a lower mass flux.

To dry out the reservoir, it is assumed that CO2 is continuously injecting for
2.5 years before any CO2 is extracted from the reservoir for power production.
Over this period, 15.8 Mt of CO2 is injected into the reservoir that was
initially filled with brine, consistant with previous studies [48]. After this
volume is injected, the CO2 gas saturation near the production well is over 30%
and the wellbore CO2 mass fraction is over 94%. A minimum 94% CO2 mass fraction
in the produced fluid was previously used as the allowable water content within
CO2 turbines [24], [26], [51].

2.2.1.2. SHALLOW RESERVOIR

When the CPG-F facility is operated to provide energy storage, the shallow
reservoir stores the CO2 in between when power is produced and consumed. The
reservoir has a single horizontal well, which functions as both the injection
and production well. The single well limits the CO2 plume advection and
diffusion losses by keeping the CO2 concentrated in a single area, allowing most
of the injected CO2 to be recovered later. The well is located beneath the
caprock at a radius of 400 m. Similar to the deep reservoir, a horizontal well
is used instead of a vertical well. Two vertical wells connect the surface
equipment with the horizontal well.

The depth of the shallow reservoir is an important parameter for the performance
of the system. The depth of the shallow reservoir must ensure that the CO2 is in
the supercritical state (7.38 MPa, i.e. reservoir depths exceeding 1 km), be
shallower than the deep reservoir depth, and have a reservoir temperatures that
is not suitable as a CPG system heat source (i.e. reservoir temperatures must be
significantly below 100 °C). Additionally, the depth of the shallow reservoir
impacts the operation of the CPG-F system operating during energy storage; with
deeper shallow reservoir depths increasing the amount of cooling that is
required during the power generation mode, thereby decreasing the ability of the
system to time-shift power dispatch and storage [49]. This limits the ideal
depth of the shallow reservoir to between 1 km and 2 km in depth. Thus, a
shallow reservoir depth of 1.5 km was selected for this study to maintain
supercritical CO2 conditions during the injection and production processes, and
to reduce parasitic power losses during the power generation mode.

The CO2 plume in the shallow reservoir is developed by injecting 0.67 Mt of CO2
over 12 weeks, consistent with previous studies [48]. The pre-injection of CO2
into the shallow reservoir is used to displace the native brine and develop high
CO2 saturations in the pore space surrounding the screen of the huff-and-puff
combined injection-production well in the shallow reservoir (see also Fig. 1B).
Sufficient pore-space CO2 saturations surrounding a production well inlet enable
the recovery of CO2 from the reservoir with minimal uptake of native brine [28],
reducing water extraction from the shallow reservoir. Low water extraction rates
are important because any CO2-coproduced water or brine from the shallow
reservoir has to be removed (and disposed of) before the CO2 is injected into
the deep reservoir as water injection into a reservoir reduces the fluid
mobility and increases the fluid pressure near the deep injection well screen,
reducing the well injectivity index and thus the injection well performance
[24]. Unlike the deep reservoir, the shallow reservoir is designed to temporary
store CO2, not to extract heat, thus the swept volume by the CO2 in the
reservoir is minimized and much less CO2 is used than in the deep reservoir.
Additionally, the displacement of the native brine by the CO2 plume decreases
the injection overpressure and the extraction pressure drawdown that occurs
during the operation of the CPG-F system, as CO2 has a lower kinematic
viscosity, experiencing lower pressure losses in the reservoir [49]. This also
reduces the overall pressure losses in the shallow reservoir compared to the
deep reservoir.

Consequently, the injection of 0.67 Mt of CO2 was selected to limit the amount
of CO2 required for the shallow reservoir, while establishing the CO2 saturation
required for the injection/production operation. Increasing the mass of the
injected CO2, while further displacing the brine from the combined
injection-production huff-and-puff well, had little effect on the brine
concentration in the produced CO2 and the pressure drop that occurred between
the fluid injection and production modes [49]. Decreasing the pre-injection CO2
mass, increases the amount of water that is recovered and increases the fluid
pressure drop between the injection and production modes (decreasing CPG-F power
plant performance), due to brine encroachment on the well [49]. Injecting the
CO2 over a 12-week period was used to prevent large reservoir overpressures and
reduce the amount of cooling that would be required during the power generation
mode.

The shallow reservoir is designed to operate with minimal amounts of CO2;
however, diffusion and advection cause CO2 to become inaccessible and lost to
the surrounding reservoir over time [49]. To make up for these losses, only 98%
of the injected CO2 mass is produced each cycle. This provides a repeated
resupply of CO2 from the deep reservoir to the shallow reservoir and maintains
the high saturation of CO2 near the combined injection-production well in the
shallow reservoir over the lifetime of the CPG-F system [49].

2.2.2. POWER SYSTEM MODELING

The power system is comprised of the turbine, cooling towers, pump, throttling
valve, and the vertical wells. The state points for the CPG-F facility are
defined in Fig. 1 and the main surface plant parameters are given in Table 3.
The surface power plants are simulated using Engineering Equations Solver (EES)
with CO2 property relations from Span and Wagner [52]. The surface power plant
component models are consistent with previous CPG power system models [12],
[40], [48], [49], discussed in detail in Fleming 2019 [49], and thus are only
summarized below. The CPG-F power plant is assumed to be in a quasi-steady state
for the analysis.

Table 3. Parameters used for the surface power plant simulations.

Parameter/ValueEmpty CellSurface Wet Bulb Temperature15 °CVertical Well Inner
Diameter0.41 mVertical Well Surface Roughness55 µm [53]Deep Reservoir Vertical
Production Wells4Deep Reservoir Vertical Injection Wells1Shallow Reservoir
Vertical Wells2High-pressure Turbine Backpressure7.5 MPaTurbine Isentropic
Efficiency78%Pump Isentropic Efficiency90%CPG Condensing Tower Approach
Temperature7 °CCPGES and CPG + CPGES Condensing Tower Approach Temperature,
lesser of7 °CT11 – 15 °C

The vertical portion of the wells is numerically simulated using the well model
of Adams et al. [12], using a steady state finite volume approximation, with the
vertical wells subdivided into 100-meter elements. The model neglects fluid
pressure losses in the horizontal wells within the reservoir. The model
numerically integrates across each element (i.e. from state i to state i + 1),
starting with the reservoir state (State 1), which is determined from the
subsurface reservoir model, to the surface. Across each element, the energy
balance equation (Equation (1)), momentum equation (Equation (2)), and
continuity equation (Equation (3)) are solved simultaneously (for variable
definitions, see Table
1).(1)hi103J1kJ+gzi=hi+1103J1kJ+gzi+1(2)Pi103Pa1kPa+ρigzi=Pi+1103Pa1kPa+ρi+1gzi+1-ΔPloss103Pa1kPa(3)ṁ=ρiAVi=ρi+1AVi+1

The well is assumed to be adiabatic and neglects kinematic energy [12], [13].
The frictional pipe losses are modeled using the Darcy–Weisbach relation
(Equation (4)), where the friction factor is determined from the moody chart
[54] using a surface roughness, ε, of 55 µm, based on bare Cr13 oil piping
[53].(4)ΔPloss=fLpipeDρV221kPa103Pa

A well diameter of 0.41 m is used to reduce the pressure losses in the well,
which can be significant. Small well diameters significantly reduce power output
and several simulations have shown that larger pipe diameters can be a cost
minimization strategy [11], [12], [40]. However, smaller pipe diameters may also
reduce costs by reducing the heat extraction rate from a reservoir, thereby
reducing the required capacity of the power plant at the land surface and
increasing its utilization, resulting in reduced power generation costs [30].
The CPG-F system has seven vertical wells (Fig. 2), the five deep reservoir
vertical wells (one injection, four production) plus two vertical
(huff-and-puff) wells to the shallow reservoir. Once at the reservoir, the
vertical wells connect to the horizontal collection wells described in previous
sections.

The power produced from the turbine is calculated using the mass flow rate and
the enthalpy difference across the turbine using an isentropic efficiency of
78%. The high-pressure turbine (HPT) backpressure for the system is 7.5 MPa
(State 3) to provide sufficient pressure to overcome CO2 injection into the
shallow reservoir and to maintain the CO2 supercritical, preventing multiphase
flow in the vertical well (State 8). The system operates with a low-pressure
turbine (LPT) backpressure of 6.0 MPa (State 4), the saturation pressure for CO2
at a temperature of 22 °C that is set by State 5, the saturated liquid condition
at the exit of the condensing tower. The condensing pressure for the energy
storage configuration (State 4) is equivalent to the shallow reservoir wellhead
pressure (State 11). A CPG-F facility cannot operate when the wellhead
temperature (State 11) is less than the ambient temperature (15 °C) as heat
rejection (and thus the phase change of the CO2 from the gas to liquid) cannot
occur. In these cases, values were omitted from the figures and tables.

A CPG-F facility may use an isenthalpic throttling valve to reduce the shallow
reservoir wellhead pressure (State 11) to the condensing pressure (State 4) of
CO2 at a temperature of 22 °C (5.4 MPa), when the system is operated to provide
dispatchable power and energy storage simultaneously (Section 3.5). If the
shallow reservoir production temperature is below 22 °C, but above 15 °C, no
throttle is used and the condensing pressure is reduced to the wellhead pressure
(State 11), thereby reducing the approach temperature (see Table 3) and the
condensing tower outlet temperature (State 5).

The components that consume power are the pumps and the cooling towers. Pumps
are used to increase the fluid pressure at the land surface before the fluid is
injected into the deep reservoir. The power that is used by a pump is calculated
by the mass flow rate times the change in enthalpy across the pump, using an
isentropic efficiency of 90%. The cooling towers consume parasitic power to
operate the fans which reject heat from the CO2 to the surrounding atmosphere.
The parasitic power consumption for the cooling towers is modeled as a fraction
of the total heat rejection, given as(5)ẆCoolingTower=λQ̇CoolingTower

where λ is the parasitic loss fraction, which is a function of the cooling tower
approach temperature and the ambient wet bulb temperature, as defined in Adams
et. al [12], and the heat transfer rate is defined as the mass flow rate times
the enthalpy difference across the cooling tower.

For the CPG-F dispatchable power system, the net power is the sum of the turbine
power, cooling tower power, and pump power (Equation (6)). The cooling tower
power and pump powers are parasitic powers and are, therefore,
negative.(6)ẆCPG,net=ẆCPG,turbine+ẆCPG,cooling+ẆCPG,pump

For the CPG-F designed for energy storage, the generation power is the sum of
the turbine power and the (zero or negative) shallow reservoir pre-injection
cooling tower power (Equation
(7)).(7)ẆCPG-F,generation=ẆCPG-FS,turbine+ẆCPG-F,cooling,generation

Similarly, the storage power is the sum of the cooling tower power and the pump
power, both of which are zero or negative (Equation
(8)).(8)ẆCPG-F,storage=ẆCPG-F,cooling,storage+ẆCPG-F,pump

The generation and storage powers of the CPG-F system change over the generation
or storage period as the reservoir pressures change. When a single value is
reported to represent an entire period, it is a time-averaged value.

The energy is the integral of the power over time. The energies of the CPG and
the CPG-F systems are given in Equations (9), (10), (11),
(12).(9)WCPG,net=∫024hẆCPG,netdt(10)WCPG-F,generation=∫0tgenerationẆCPG-F,generationdt(11)WCPG-F,storage=∫tgeneration24hẆCPG-F,storagedt(12)WCPG-F,net=WCPG-F,generation+WCPG-F,storage

In the modeling for this study, a CPG-F facility operates continuously for 24 h
when only dispatchable power is provided. In contrast, when operating to provide
other services, the facility may produce power for only a portion of a 24-hour
period. The ratio of the electricity generation time to total operation time is
the duty cycle, given in Equation (13).(13)DutyCycle=tgeneration24hours

For this analysis, four duty cycles were selected for production periods of 16h,
12h, 8h, and 4h. These are respectively labeled: “16h-8h”, “12h-12h”, “8h-16h”,
and “4h-20h,” also shown in Table 4.

Table 4. Duty cycles examined in this study.

Duty CycleCycle ParameterCycle Characteristics16h-8h16-hour power production
followed by 8-hours of power consumptionPeaking power consumption with extended
power production12h-12h12-hour power production followed by 12-hours of power
consumptionBalanced power production and consumption8h-16h8-hour power
production followed by 16-hour of power consumptionModerate peaking power
production with extended power consumption4h-20h4-hour production followed by
20-hour of power consumptionFull peaking power production with extended power
consumption

The CO2 stream is split when the CPG-F facility operates to provide both
dispatchable power and energy storage and the ratio of the dispatchable power
CO2 mass flow rate divided by the total CO2 mass flow rate used to make power is
the split mass fraction, mfsplit (Equation
(14)).(14)mfsplit=ṁdispatchableṁdispatchable+ṁenergystorage

The facility can operate with mass fractions from 0% (0% dispatchable and 100%
energy storage) to 100% (100% dispatchable and 0% energy storage). For this
analysis, five energy storage mass fractions (mfenergy storage) were chosen: 0%,
25%, 50%, 75%, and 100%. Mass flow rates, and daily circulation rates are
calculated using the same method as prior work [49]. All mass flow rates are
provided is the supplemental information (Table S1, S2).


2.3. COST ESTIMATION

The capital costs of the CPG-F facility are calculated with genGEO capital cost
model [55]. The capital cost consists of three components: reservoir and
monitoring wellfield development, geothermal wells, and surface power plant. The
geothermal wells and wellfield costs are fixed for all sizes of surface
equipment and mass flow rate. Conversely, the surface plant has no fixed cost
and varies exclusively with equipment (turbine, pump, and cooling tower) size
and flow rate. In all cases, greenfield development costs are used, and all
costs are overnight values in United States dollars (USD) for 2019. Assuming
brownfield development (i.e. an existing CO2 sequestration site with adequate
injection wells) would substantially reduce costs, but would be an optimistic
assumption. The reservoir development cost model includes the site
characterization, leasing, tracer tests, stimulation, air and groundwater
monitoring equipment, stratigraphic wells, and monitoring wells. No cost or
credit for acquiring the CO2 is considered.

The specific capital cost, SCC [$/MW], of the system is the total project
capital cost, divided by the power generation capacity of the system. The
specific capital cost of the facility as a power capital cost ($/MW) is reported
instead of other cost metrics, such as the levelized cost of electricity, or
levelized cost of storage, to avoid using financing assumptions. In addition to
the power capital cost, energy storage technologies are also described with an
energy capital cost ($/MW-h), which takes into account the length of time energy
can be stored or discharged. This metric does not apply as cleanly to CPG-F
facilities designed to provide energy storage as other energy storage approaches
(e.g., batteries) because the energy storage occurs in the reservoir and thus
the length of time a CPG-F facility can dispatch and store electricity is more
of an operator decision than a system constraint. In other words, the energy
capital cost of a CPG-F facility designed to provide energy storage over any
duration, could be thought of as being $0/MW-h because it does not change
capital costs to increase or decrease the hours of energy stored. At the same
time, the size of the surface equipment (e.g., turbine), and thus the specific
capital cost, could change for a facility designed to provide energy storage
over a specific duration compared to another (e.g., 16h-8h vs 12h-12h). As a
result, the total capital cost [$] of the CPG-F facility is reported instead of
the specific capital cost in some situations for simplicity.


3. RESULTS AND DISCUSSION

Here, CPG-F facilities, designed to provide different services, are
characterized in terms of the net daily energy production, power production,
power storage, and cost. The complete results are in tables in the appendix. The
results presented here are for a single day after 10 years of continuous
operation once the CO2 injection and production pressures have stabilized. At
some elevated CO2 circulation rates (flow rates exceeding 20kt/day for the
4h-20h duty cycle, and 40 kt/day for the 8h-16h and 16h-8h duty cycles), the
wellhead temperature of CO2 extracted from the shallow reservoir is below the
minimum temperature (i.e. the ambient wet bulb temperature) necessary to reject
heat from the CO2. In these high flowrate cases, a solution cannot be found, and
no value is reported.

A standard CPG power plant, without the addition reservoir (i.e., not CPG-F), is
modeled for the given reservoir to provide a reference point for CPG-F
simulations. Thus, a brief description of the CPG results is provided (section
3.1). The results of a CPG-F facility designed for energy storage are provided
as a function of duty cycle and CO2 production flow rate (section 3.2), followed
by design cases determined based on optimal flow rates (section 3.3). The cost
of designing a CPG-F facility that can operate across all duty cycles and
flowrates is discussed in section 3.4. Lastly, a CPG-F facility designed to
provide both dispatchable power and energy storage simultaneously is discussed
in section 3.5.


3.1. CPG POWER PLANT RESULTS

The amount of power, and thus energy, produced by the CPG power plant varies
with the mass flow rate, shown in Fig. 3. As the mass flow rate increases the
turbine produces more power. However, the pressure losses within the reservoir
and surface piping also increase with mass flow rate, decreasing the pressure
differential across the turbine and increasing the amount of pumping required.
This turbine pressure reduction counteracts the turbine output gains due to
increased mass flow rate and results in maximums in both the net power and
energy. For the system parameters (e.g. reservoir depth, temperature,
permeability) considered here and shown in Fig. 3, the optimal mass flow rate
which provides the most power and energy is 39 kt/day (450 kg/s). At this mass
flow rate, 60 MWe-h of energy is produced per day at a continuous rate of 2.5
MWe.

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Fig. 3. The daily energy production and consumption for major system elements
and the specific capital costs for a CPG power plant. Net power production is
maximized at a CO2 mass flow rate of 39 kilotonnes per day (450 kg/s), while
specific capital costs are minimized at a CO2 mass flow rate of 35 kilotonnes
per day (400 kg/s).

The specific capital cost of a CPG power plant is also shown in Fig. 3. As an
alternative to selecting a CO2 mass flow rate to maximize net power, a flow rate
can be chosen to minimize the specific capital cost. Thus, a CPG power plant has
at least two optimal mass flow rates: 1) for maximum net power production, and
2) for minimum specific capital cost, the latter of which has not been
considered previously [10], [11]. Here, the minimum specific capital cost occurs
at a mass flow rate of 35 kt/day (400 kg/s), while the maximum net power occurs
at a mass flow rate of 39 kt/day (450 kg/s). Operating at the minimum specific
capital cost mass flow rate produces 2.49 MWe, or 59.7 MWe-h/day, which is 99%
of the power/energy when operating at the maximum net energy flow rate, but at
98.6% of the specific capital cost. Thus, in this scenario, the two operational
points are very similar.

This work continues to determine the power production at the mass flow rate of
maximum power production, which is consistent with previous analyses [12].
Future work may include operating a CPG power plant at a flow rate which
minimizes specific costs.


3.2. CPG-F DESIGNED FOR ENERGY STORAGE DUTY CYCLES: VARIATIONS IN DAILY CO2
CIRCULATION

Fig. 4A shows that a CPG-F facility designed for energy storage has a
circulation rate that delivers maximum power. This is due to the relationship
between the turbine power production and the parasitic power consumption of the
cooling towers, similar to the maximum in a CPG power plant, discussed
previously. Additionally, Fig. 4A shows that for the same CO2 circulation rate,
the production power is higher for short production periods (e.g. 4h-20h duty
cycle) than for longer production periods due to the higher production period
CO2 mass flow rate for the same rate of daily CO2 circulation.

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Fig. 4. The performance metrics of CPG-F facilities designed for energy storage
and a CPG power plant for varying CO2 circulation rate: A) the power production,
B) the power consumption during the storage mode, C) the energy produced during
the production mode, D) the energy consumed during the storage mode, E) the net
daily energy produced, and F) the total project capital cost.

Fig. 4B shows that storage power, which consists of parasitic powers and is
therefore a proxy for system losses or inefficiencies, becomes large at high
storage mass flow rates. For a given daily CO2 circulation rate, a duty cycle
with a shorter storage period (e.g. 16h-8h) will have a higher storage mass flow
rate than a duty cycle with a longer storage period (e.g. 4 h-20 h). Thus, duty
cycles with shorter storage periods (e.g. 16h-8h) have higher power consumption
for a given CO2 circulation rate than those with longer storage periods.

Fig. 4C and Fig. 4D show the energy produced and stored over a 24-hour period.
Fig. 4C shows that the electricity generation energy is similar to, or slightly
larger than, the CPG power plant net energy. Thus, a CPG-F facility designed for
energy storage can produce approximately the same energy as a CPG power plant,
but in a smaller window of time. The energetic cost of this increased power
availability is shown in Fig. 4D, wherein the CPG-F facility energy storage
curves increase polynomially with flow rate, but a CPG power plant has no
storage energy. This results in a CPG power plant generating the greatest net
daily energy, shown in Fig. 4E. This is expected, as the CPG-F facility designed
for energy storage eliminates the low-pressure turbine (Fig. 1) and its
corresponding energy production to incorporate the shallow reservoir and add
energy storage capability. Thus, the CPG power plant and CPG-F facilities
designed for energy storage naturally fall into separate groups in Fig. 4E.
Additionally, there are less energy efficient duty cycles than others,
particularly at larger daily circulation rates. Both the 4h-20h duty cycle and
16h-8h duty cycle have substantially less net daily energy due to their
imbalance of production and storage mass flowrates, discussed previously.

Fig. 4F shows the total project capital cost for both a CPG power plant and a
CPG-F facility designed for energy storage. The systems have different costs for
two primary reasons: CPG-F facilities need 1) the additional reservoir,
geothermal wells, and monitoring wellfield and 2) increased surface equipment.
The well and wellfield costs shift the CPG-F facility cost curves up by a fixed
value of $43.4 M. The equipment costs tend to both shift the cost upwards and
increase with daily circulation rate. The upward shift in equipment cost is due
to the intermittent operation of the equipment. For example, if the 12h-12h
system operates at the same CO2 daily circulation rate as a CPG power plant, the
production and storage mass flow rates will need to be double the flow rates of
the CPG power plant, and therefore the equipment (e.g. turbine and cooling
tower) both have to be twice as large. Additionally, the increase in equipment
cost with daily circulation rate is due to the growing inefficiencies (pipe and
reservoir friction losses) at large flow rates and their associated parasitic
powers. In general, the reservoir accounts for over 85% of the pressure loss,
but at the largest flow rates in the energy storage configuration, the well
pressure losses (mainly the deep injection well) can exceed 20% of the total
pressure loss. Thus, a CPG power plant has the lowest capital costs and the
highest daily average energy. Conversely, the CPG-F facility here has up to 310%
more production power than the CPG power plant at the expense of system
inefficiency and capital costs. However, either option may be financially viable
depending on the value of the services provided and the market incentives to
provide those services.


3.3. CPG-F DESIGNED FOR ENERGY STORAGE DUTY CYCLES: OPTIMAL FLOW RATE DESIGN
POINTS

So far, the operation of CPG-F facilities designed for energy storage has been
shown with respect to the daily CO2 circulation rate, or average daily mass flow
rate. The mass flow rate is a design condition which is chosen by the system
engineer, i.e. it is an input to the system. In the CPG power plant analysis
(Section 3.1), it was demonstrated that the mass flow rate can be chosen to
maximize power (and thus energy), as done in previous studies [12], [29], or to
minimize the specific capital cost.

A similar approach to CPG-F facilities, designed to provide energy storage, was
applied, however, the variable nature of providing energy storage and the market
needs, which the CPG-F facility needs to meet, are different than for CPG power
plants, so that multiple design point mass flow rates are possible. Therefore,
four potential mass flow rate operational cases for CPG-F facilities, designed
to provide energy storage, are defined:

 * •
   
   Case 1: Maximum Daily Net Energy: The facility delivers the largest net
   energy to the grid over a complete daily cycle. This is similar to the design
   point for the CPG power plant.

 * •
   
   Case 2: Maximum Power: The facility delivers the maximum possible power
   during the production mode, despite the large energy penalties during the
   storage mode.

 * •
   
   Case 3: Zero Daily Net Energy: The facility produces and stores energy such
   that the net is zero. This usually provides an operational point between
   Cases 1 and 2. This operation is similar to an ideal battery with a
   round-trip efficiency of one.

 * •
   
   Case 4: Minimum Specific Capital Cost: The facility operates so that the
   specific capital cost of power production is minimized.



Fig. 5A through 5D show the dependency of energy and cost on the CO2 circulation
rate. For each duty cycle, the operational points for Cases 1 through 4 are
shown with a numbered vertical line. The daily circulation for each of the
optimized cases was determined directly using the simulation data for maximum
daily net energy, maximum power, and minimum specific capital cost cases. The
zero daily net energy case is determined by linear interpolation of the data.

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Fig. 5. Energy and cost values of a CPG-F facility designed for four different
energy storage duty cycles: the A) 16 h-8 h case, B) 12 h-12 h case, C) 8 h-16 h
case, and D) 4 h-20 h case. The daily CO2 circulation is marked for each of the
following cases: Case 1) maximum daily net energy, Case 2) the maximum power
production, Case 3) zero daily net energy, and Case 4) the minimum specific
capital cost.

The Case 1 (Maximum Daily Net Energy) operational point occurs at the lowest
daily circulation rates for all duty cycles. While this design point balances
the net energy production with the parasitic losses for a CPG power plant, it
generally limits the amount of power dispatched and stored from a CPG-F facility
designed for energy storage, and thus should only be considered as a lower bound
design point.

The Case 2 (Maximum Power) operational point tends to occur at large daily
circulation rates, but this can vary depending on the duty cycle. As discussed
earlier, the net production energy delivered to the grid will always
theoretically reach a maximum after which pressure losses reduce energy output;
however, this maximum is not always observed. For example, in Fig. 5A, the
temperature of CO2 produced (State 11 in Fig. 1) during the storage period above
40 kt/day is below the ambient temperature at the surface; therefore, heat can
no longer be rejected, and the system simulation cannot be solved. Thus, no
results, including a maximum in energy production, are reported above 40 kt/day
for the 16h-8h duty cycle, 46 kt/day for the 12h-12h duty cycle, and 23 kt/day
for the 4h-20h duty cycle. Additionally, the Case 2 operational points can have
very large, negative net daily energy as these points occur at high flowrates
which have large storage period energy consumption.

The Case 3 (Zero Net Daily Energy) operational points tend to be a compromise
between those of Cases 1 and 2, providing increased production power but without
the increasing inefficiency that occurs at large mass flowrates. The Case 3
point has equal parts energy production and storage, thus, this scenario can be
best compared to traditional energy storage technologies (e.g. pumped-hydro or
batteries). In some duty cycles with long storage periods (i.e. 8h-16h and
4h-20h), the Case 3 operation point occurs at higher daily circulation rates
than Case 2. When this occurs, the production power and the daily net energy
decrease from Case 2, and there is no practical application for Case 3 in these
duty cycles.

The Case 4 (Minimized Specific Capital Cost) operational points occur at flow
rates greater than those of Case 1 (Maximum Daily Net Energy) but equal to or
below Case 2 (Maximum Power). Similar to Case 3, the minimum specific capital
cost is a compromise between high power production and large net daily energy
production.

Fig. 6 shows the power production and net daily energy production for a CPG
power plant and a CPG-F facility designed for each energy storage duty cycle and
four flow rate cases. All the CPG-F energy storage design cases considered
deliver more power than the CPG power plant. For a given duty cycle, there is no
apparent advantage to operating at circulation rates lower than those specified
by Case 1 or greater than that of Case 2. If the flow rate is reduced below that
of Case 1 (maximum net daily energy), both the power and energy decrease while
the specific capital cost increases. Similarly, circulation rates greater than
Case 2 will decrease production power and net daily energy while specific
capital costs increase.

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Fig. 6. The A) net production power and B) net daily energy of a CPG power plant
and a CPG-F facility designed for different energy storage duty cycles and
operational flow rate cases.

The 8h-16h and 4h-20h duty cycles both provide positive net daily energy while
also providing the highest production power. This is due to their long storage
periods with corresponding low storage mass flow rates. As previously noted,
large pump powers occur at high storage mass flow rates and are a primary driver
for large storage energy, and thus negative net energy for a complete cycle.

Therefore, our general finding is that CPG-F facilities designed for energy
storage will tend to have fewer inefficiencies, higher net energy, and increased
power production if operators adopt a strategy which provides slower, more
consistent injection into the deep reservoir. This is also the reasoning for
designing a CPG-F facility to provide both dispatchable power and energy storage
simultaneously (described in section 3.5), whereby partial continuous injection
reduces the average flowrate into the deep reservoir.


3.4. CPG-F DESIGNED FOR ANY ENERGY STORAGE DUTY CYCLE: COST

The capital cost breakdown for each of the CPG-F facilities from the previous
section is compared with the breakdown for CPG power plant in Fig. 7. The
largest costs in all cases are the geothermal wells and well drilling costs,
which are fixed at $105 M for CPG-F facilities. This cost ranges from 56% to 74%
of the total project capital cost, but on average is 68%. The reservoir
configuration chosen here uses horizontal wells which provide large power output
but adds substantially to the cost. Future work may optimize length of well
drilled to balance power production and cost. Aside from the geothermal well and
drilling costs, the next largest costs tend to be the monitoring wells and
reservoir exploration costs, which are both fixed for CPG-F facilities. When
these costs are combined with the geothermal well and drilling costs, the cost
to find, assess, and access the geothermal sources for CPG-F facilities is
$132 M, or on average 85% of the total project capital cost.

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Fig. 7. The cost breakdown for each of the CPG-F facility designs for energy
storage considered in this study. The vertical well costs represent
approximately two thirds of the total capital costs. The “16 h-8 h to 4 h-20 h”
flexible system can operate during most duty cycles and cases while costing 4%
to 27% more.

The CPG power plant in Fig. 7 costs $115 M, while most of the CPG-F facilities
cost between $154 M and $190 M. Thus, in the cases considered, CPG-F facilities
designed for energy storage can reasonably cost between 34% and 65% higher than
CPG power plants.

Thus far, power, energy, and cost for each of the four duty cycles and the four
cases have been reported (i.e. daily circulation rates). However, it is very
likely that a CPG-F facility designed for energy storage will not be permanently
operated at any one duty cycle and flow rate, but rather vary its operation
based on the electrical grid demand and market conditions. For example, on peak
demand days, the system may operate at the 4h-20h Case 2 condition, while it may
operate in a 12h-12h Case 3 condition on other days. Thus, a CPG-F facility
designed to provide energy storage across all duty cycles and cases was
investigated. Here, this “any duration” CPG-F facility is only defined by the
size of the power equipment (i.e. turbine, cooling tower, and pump) required to
provide adequate capacity for all the defined operational conditions.

Fig. 7 shows the cost breakdown for the CPG-F facility that operates over all
cycles (16h-8h to 4h-20h) and cases examined (i.e. Cases 1 to 4). For such a
system that can operate over all cycle durations, the components (e.g. turbine,
cooling tower, pump) are of the maximum size required for the underlying
simulations, and these sizes are used to determine the total surface plant cost.
Thus, designing a CPG-F facility to provide energy storage across varying duty
cycles requires oversizing the components for most operating cycles and cases.
Such an “any duration” system costs $196 M, which replaces a range of systems
that cost from $154 M to $190 M. Additionally, Fig. 6 shows that this “any
duration” CPG-F facility can produce between 4.7 MWe and 10.2 MWe, compared to
2.5 MWe produced with a CPG power plant. Thus, the cost of a flexible system,
which can produce 90% to 310% more power than a CPG power plant, is 4% to 27%
higher than most duty-cycle-specific CPG-F facilities and 70% higher than a CPG
power plant.


3.5. CPG-F SYSTEM DESIGNED TO SIMULTANEOUSLY PROVIDE DISPATCHABLE POWER AND
ENERGY STORAGE

In this section the operational capabilities of CPG-F facility are combined to
provide both dispatchable power and energy storage simultaneously. This allows
for continuous, dispatchable net energy production and periodic additional
(peaking) power production and storage. Designing a CPG-F facility in this way
adds flexibility in operation to meet the fluctuating electricity grid demands.

For this analysis, it is assumed that the energy storage portion of a CPG-F
facility operates on an 8h-16h duty cycle, however, any of the duty cycles could
have been chosen. The system is simulated at five daily mass fractions (equation
(14)), specifically: “100% dispatchable”, “75% dispatchable + 25% energy
storage”, “50% dispatchable + 50% energy storage”, “25% dispatchable + 75%
energy storage”, and “100% energy storage”. For this section, a combined daily
CO2 circulation rate of 34.6 kt/day was selected, the circulation rate for
minimized specific capital cost for CPG-F facilities, designed to only provide
energy storage (also near the maximum power production for that design).

Fig. 8 shows the combined power produced from a CPG-F facility during a 24-hour
period. The first eight hours is the production period, followed by the storage
period for the remaining 16h. Note, the term “storage period” is used here to be
consistent with the terminology from earlier sections; however, this may be
confusing as the facility still supplies net power to the electrical grid during
most storage periods.

 1. Download : Download high-res image (160KB)
 2. Download : Download full-size image

Fig. 8. The net power produced and consumed over a complete diurnal cycle for
CPG-F operating to provide both dispatchable power and energy storage
simultaneously, including the CPG and CPG-F designed for only 8 h-16 h energy
storage duty cycle. All results are for a daily CO2 circulation rate of 34.6
kt/day.

In Fig. 8, the 100% dispatchable power output is a horizontal line of 2.5 MWe.
As the operational combination shifts from “100% dispatchable” to “75%
dispatchable + 25% energy storage”, the output during the production period
increases to 3.4 MWe and drops to 2.0 MWe during the storage period. At a mass
fractions of “25% dispatchable + 75% energy storage” and “100% energy storage,”
the storage period power output is negative, and power is removed (i.e. stored)
from the grid. Thus, in this variable, the power output can be adjusted
throughout the day to meet demand while still continuously generating power to
maximize revenue.

Fig. 9 shows the CPG-F facility power, daily net energy, and cost for multiple
flow rates. Generally, adding some dispatchable production functionality to the
facility designed to only provide energy storage increases the daily net energy
but decreases the peak production power. For example, Figs. 8 and 9A shows that
shifting from “100% energy storage” to “25% dispatchable + 75% energy storage”
for a CO2 circulation rate of 34.6 kt/day decreases the average production power
from 7.2 MWe to 6.4 MWe, or −11%. At the same time, Fig. 9B shows the daily net
energy increases by 431% from 7.2 MWe-h to 38.2 MWe-h. Thus, by designing a
CPG-F facility to provide both dispatchable power and energy storage, the daily
net energy increases at the expense of power production, when compared to a
CPG-F system designed to only provide energy storage.

 1. Download : Download high-res image (559KB)
 2. Download : Download full-size image

Fig. 9. The performance of a CPG-F facility designed to provide both
dispatchable power and energy storage simultaneously, compared to a CPG power
plant and a CPG-F facility designed to provide only energy storage over a
8 h-16 h duty cycle in terms of A) the power produced during the production and
recharge modes, B) the daily net energy, C) the total and specific capital
costs.

In some cases, designing a CPG-F facility to provide both services
simultaneously can increase both the power production and daily net energy,
compared to a system designed for only energy storage. For example, in Fig. 9A
for daily CO2 circulation rates above 40 kt/day, the “25% dispatchable + 75%
energy storage” system produces more power than the “100% energy storage” system
alone. This phenomenon is a result of distributing the CO2 amongst multiple
pathways in the system, allowing them all to operate more efficiently. For
example, at a daily CO2 circulation rate of 40 kt/day, the 100% energy storage
produces mass flow rate is 1400 kg/s. At that same daily circulation rate, the
“25% dispatchable + 75% energy storage” system has a dispatchable production
mass flow rate of 233 kg/s and an energy storage mass flow rate of 700 kg/s. As
a result, both reservoirs have reduced injection and production mass flow rates,
and the system operates with fewer pressure losses and higher storage
efficiency. Thus, Fig. 9 shows the “25% dispatchable + 75% energy storage”
system produces about the same production power at 43 kt/day as the 100% energy
storage system does at 29 kt/day, but with 27% more daily net energy.

Fig. 9C shows that despite the variation in operation, a CPG-F facility designed
for only providing energy storage over an 8h-16h duty cycle and a CPG-F facility
designed to provide both services simultaneously have similar costs. The capital
cost of a CPG-F facility designed to provide both services simultaneously are
offset from the CPG power plant by a nearly constant value, which is primarily
the cost of the shallow reservoir and the additional wells.

A CPG-F facility designed to provide both services simultaneously extends the
maximum daily circulation rates beyond the useful values for either “100%
dispatchable“ or “100% energy storage.” Fig. 9A shows that a CPG-F facility
designed for both services all have maximum production powers at CO2 circulation
rates higher than the CO2 circulation rate of 39 kt/day that maximized energy
for CPG power plants. However, in Fig. 9B, the daily net energy maximums of the
CPG-F facilities designed for both services all occur between the “100% energy
storage” and the “100% dispatchable” daily net energy maximums, both in terms of
energy production and the daily CO2 circulation rate. Thus, while a CPG-F
facility designed for both services can increase and extend the power that is
produced, the net energy production is always bounded by the “100% energy
storage” and “100% dispatchable systems.”

In Section 3.4, the cost of an “all duration” CPG-F facility designed to provide
only energy storage across all duty cycles and flow rates was found. The same
approach is taken here, but for a CPG-F facility that is designed to provide
anywhere between 100% dispatchable power and 100% energy storage. To do this,
the maximum cost of each component (i.e. turbine, pump) is summed for all mass
fractions between “100% dispatchable” and “100% energy storage” at a duty cycle
of 8 h-16 h. This CPG-F facility costs $173 M. This system cost is 50% higher
than that of an energy-maximized CPG power plant and only 3% higher than the
cost of the most expensive CPG-F facility designed to provide only energy
storage over an 8h-16h duty cycle. This increase in cost is mainly due to the
slightly larger flow rates that the system can achieve. Thus, the costs of a
CPG-F facility, designed to provide anywhere between 100% dispatchable power and
100% energy storage, are close to the costs for a CPG-F facility designed to
only provide energy storage, but with the former providing significantly more
flexibility to react to price signals from the electricity market.


4. CONCLUSIONS AND SUGGESTIONS FOR FUTURE INVESTIGATIONS

This paper has demonstrated how a CO2 Plume Geothermal (CPG) power plant can be
expanded to a Flexible-CPG (CPG-F) facility by adding wells and a second,
shallow reservoir. Unlike a CPG power plant, CPG-F facilities may be designed to
provide dispatchable power, energy storage over a range of charge and discharge
cycle durations (i.e., duty cycles), or both dispatchable power and energy
storage simultaneously—providing baseload power with dispatchable storage for
demand response. While this flexibility, coupled with the additional incentive
for geologically storing CO2, likely means that CPG-F facilities will be
valuable to decarbonization efforts broadly, designing any given CPG-F facility
is non-trivial. For example, there are multiple optimum design points (e.g.,
minimum cost, maximum power, maximum net energy) that may be in tension or have
non-intuitive relationships with one another. As a result, in this study, an
initial investigation into these relationships and design criteria was
conducted. Some of the primary findings include:

 * 1.
   
   A CPG-F facility can deliver more instantaneous power than a CPG power plant,
   but at the expense of decreased net energy production because a CPG-F
   facility, operated for energy storage, has a lower efficiency than a CPG
   power plant (Fig. 4).

 * 2.
   
   The CO2 circulation rate that maximizes net power production is different
   than the rate that minimizes the specific capital cost when a CPG-F facility
   is designed to provide dispatchable power (Fig. 3). But these flowrates are
   generally the same or close to the same when the facility is designed to
   provide energy storage (Fig. 5).

 * 3.
   
   While the duty cycle of a CPG-F facility, designed to provide energy storage,
   is an operational decision, duty cycle decisions may influence the ability to
   operate at optimal design points. For example, a CPG-F facility, designed for
   energy storage, produces power more efficiently over duty cycles of equal
   durations (e.g., 12h-12h), compared to duty cycles of unequal durations
   (e.g., 4h-20h) (Fig. 4). Further, the maximum power produced by a CPG-F
   facility, designed to provide energy storage, may be impossible to reach
   because the temperature of the produced fluid can decrease below ambient air
   temperatures (Fig. 5).

 * 4.
   
   The power capacity and capital cost of a CPG-F facility, designed to provide
   only energy storage, increases with shorter duty cycle durations, but can
   provide a similar amount of energy across all duty cycles as a CPG-F
   facility, designed to only provide dispatchable power (Fig. 4).

 * 5.
   
   Across all cases considered, the total project capital cost of a CPG-F
   facility, designed for a given energy storage duty cycle, is 34% to 65%
   greater than the cost of a CPG power plant; the total project capital cost of
   a CPG-F facility, designed to provide energy storage over all durations, is
   70% greater than that of a CPG power plant (Fig. 7). This increase in cost is
   largely due to the increased drilling and well completion costs and the
   increased size of the surface equipment. However, due to the increased
   production power of the CPG-F facility, the specific capital cost of a CPG-F
   facility decreases below that of a CPG power plant.

 * 6.
   
   Compared to a CPG-F facility, designed to provide only energy storage,
   designing a CPG-F facility to provide dispatchable power and energy storage
   simultaneously generally results in an increased daily net energy production
   and a decreased daily power output. However, there are some scenarios, where
   it is possible to produce more daily net energy and power output (Fig. 9).
   Also, a CPG-F facility, designed to provide dispatchable power and energy
   storage simultaneously, only costs 3% more than a CPG-F facility designed to
   provide only energy storage (Fig. 9).



Future decarbonized electricity systems will likely be comprised of a portfolio
of technologies and processes that work synergistically to meet demand. The
results show that the CPG-F facility has promise in these future decarbonized
electricity systems because they demonstrate that a single electricity system
component can provide many different services: geologic CO2 storage,
dispatchable power, energy storage, and both dispatchable power and energy
storage simultaneously. Here, a few directions for potential future work, that
was outside the scope of this initial CPG-F investigation, but build off its
findings, are provided:

 * •
   
   Pursue design modifications that increase the power production capacity (and
   power storage capacity, if applicable) of a CPG-F facility. In this study,
   one horizontal injection well and one horizontal production well in each
   aquifer were assumed, but a CPG-F facility could be scaled by increasing the
   number of wells because more wells would enable larger injection and
   production flowrates. But adding and using more wells would 1) increase the
   cost of a CPG-F facility and 2) increase the rate that the geothermal heat
   resource is depleted. As a result, future work could also investigate the
   cost and heat-depletion tradeoffs that are introduced when this design
   modification is considered, similar to the work by [30] for CPG systems.

 * •
   
   Investigate energy storage duty cycles that are longer than 24 hours. It is
   likely that technologies that can provide long duration energy storage (e.g.,
   weeks or months of storage) will have value in future low-carbon electricity
   systems and it is possible for a CPG-F facility to operate over durations
   greater than single days [48], [56], [57]. In this study, the duty cycle was
   limited to 24-hour periods, but the deep aquifers that are targets for
   geologic CO2 storage may enable long-duration energy storage because they
   have the capacity to store large volumes of fluids. For example, these
   subsurface formations underlie half of North America [58], [59]. As a result,
   if electricity market rules are created to incentivize long-duration energy
   storage, technologies like CPG-F may be uniquely positioned to provide these
   services.

 * •
   
   Conduct a parametric analysis that covers a wide range of reservoir, well,
   and surface power plant parameters to evaluate the CPG-F system performance
   and what operational parameters should consequently be chosen. In the current
   study we limited the operation to a single reservoir and surface parameter
   set, however, it is likely that CPG-F facilities can be operated economically
   under a wide range of reservoir and ambient conditions. Thus, a future
   sensitivity study of CPG-F systems should investigate parameters such as
   reservoir permeability, permeability anisotropy, porosity, thickness, and
   depth as well as various ambient air heat rejection temperatures and
   geothermal temperature gradients to identify suitable system operation
   conditions.

 * •
   
   Integrate a CPG-F facility into an energy system model to investigate how it
   is optimally dispatched and quantify its value. Prior work integrated CO2-BES
   facilities into optimization-based, systems-level, models [40], [41]. A
   similar approach could be taken for CPG-F facilities [40], [41]. Given the
   increased flexibility of a CPG-F facility, compared to a CO2-BES facility,
   this avenue for future work would likely be particularly helpful in guiding
   future CPG-F system design modifications (e.g., those that investigate
   scaling-up a CPG-F facility). For example, if integration with a system model
   demonstrated that it was most profitable to provide both energy storage and
   dispatchable power simultaneously, future work could focus specifically on
   optimizing the CPG-F design for that service. Additionally, it is recommended
   that a risk analysis of CPG-F systems be conducted in the future to aid
   potential system operators in implementing and operating the CPG-F
   technology. Further, future integration studies could also consider how
   decarbonization policies (i.e., a CO2 price) could influence how a CPG-F
   facility should be operated to maximize profit. In the design considered for
   this study, over 15 MtCO2 were injected during the development of the deep
   reservoir and the maximum project capital cost was just under $200 million.
   As a result, if CPG-F operators were compensated for storing CO2 at a rate of
   $14/tCO2, the revenue from storing CO2 would exceed the capital cost of the
   most expensive CPG-F facility investigated in this study. For reference, both
   the social cost of carbon and 45Q tax incentive in the US. are larger than
   $14/tCO2 [60], [61]. As a result, depending on the electricity prices and the
   rate at which operators are compensated for storing CO2, the value of
   providing CO2 storage services may influence design and operation decisions
   more than the value of providing grid services.




CREDIT AUTHORSHIP CONTRIBUTION STATEMENT

Mark R. Fleming: Conceptualization, Methodology, Software, Validation, Formal
analysis, Investigation, Data curation, Writing – original draft, Visualization.
Benjamin M. Adams: Conceptualization, Methodology, Formal analysis,
Investigation, Supervision, Writing – original draft, Visualization. Jonathan D.
Ogland-Hand: Writing – original draft. Jeffrey M. Bielicki: Writing – review &
editing. Thomas H. Kuehn: Supervision, Writing – review & editing. Martin O.
Saar: Funding acquisition, Resources, Writing – review & editing.


DECLARATION OF COMPETING INTEREST

The authors declare that they have no known competing financial interests or
personal relationships that could have appeared to influence the work reported
in this paper.


ACKNOWLEDGMENTS

We gratefully acknowledge funding from the National Science Foundation (NSF)
under the Sustainable Energy Pathways (SEP) Grant SEP-123069, the NSF National
Research Traineeship (Grant 1922666) and the Sloan Foundation, and the
Innovations at the Nexus of Food, Energy, and Water Systems (INFEWS) Grant
1739909; and the Sustainability Institute and the Center for Energy Research,
Training, and Innovation (CERTAIN) at the Ohio State University (OSU). We also
thank the Initiative for Renewable Energy and the Environment (IREE), a
signature program of the Institute on the Environment (IonE) at UMN for initial
CPG research support. We furthermore thank the Werner Siemens Foundation (Werner
Siemens-Stiftung) for their support of the Geothermal Energy and Geofluids
(GEG.ethz.ch) Group at ETH Zurich, Switzerland. Any opinions, findings,
conclusions, or recommendations in this material are those of the authors and do
not necessarily reflect the views of the NSF, UMN, OSU, IREE, IonE, the Werner
Siemens Foundation, the GEG Group or ETH Zurich. We also thank the anonymous
reviewers for their helpful comments and suggestions that improved an earlier
version of the manuscript.


APPENDIX A. SUPPLEMENTARY DATA

The following are the Supplementary data to this article:
Download : Download Acrobat PDF file (396KB)

Supplementary data 1.

Recommended articles



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CITED BY (8)


 * NUMERICAL ANALYSIS AND ECONOMIC EVALUATION OF PINNATE HORIZONTAL WELL FOR
   SUPERCRITICAL CO<INF>2</INF>-BASED ENHANCED GEOTHERMAL SYSTEM
   
   2024, Geothermics
   Show abstract
   
   Supercritical carbon dioxide (scCO2) is considered an alternative heat
   carrier for enhanced geothermal system due to its superior thermophysical
   property. Extensive investigations have been conducted to improve the heat
   extraction performance of scCO2-based EGS. However, few investigations have
   focused on the response mechanism of thermal reservoir for the scCO2-based
   EGS with fully coupled thermal-hydraulic-mechanical (THM) method. The
   evaluation differences between THM and TH coupling model are still not clear
   for the scCO2-based EGS. To further improve the heat extraction performance
   of scCO2-based EGS, a pinnate horizontal well (PHW) EGS is proposed in
   present work. Three-dimensional (3D) model with fully coupled
   thermal-hydraulic-mechanical (THM) is established considering the in-situ
   stress, which is used to evaluate the geothermal energy utilization and
   economic performance of PHW EGS. The effects of injection-production
   parameters, reservoir properties and fracture parameters on the heat
   extraction performance of PHW are probed. The results revealed that reservoir
   permeability shows a descending tendency while fracture aperture experiences
   a significant increase, when the effects of in-situ stress are taken into
   account. If the in-situ stress is ignored, the production temperature and
   maximum useful work will be overestimated by about 13 K and 16.4%,
   respectively. PHW EGS is characterized by the low pump consumption, high
   system efficiency and net revenue. Compared with doublet EGS, pump power is
   decreased by 58.1%, the system efficiency is boosted by 2.6 times, and the
   net revenue is increased by 35.3% at the terminal stage. It has been proved
   that the heat extraction performance is evidently affected by the injection
   flow rate and temperature of working fluid, initial reservoir permeability,
   initial aperture and maximum closure. Appropriate operation strategy can
   effectively improve the performance of PHW EGS. In addition, the optimized
   average electricity price, accumulative income and net revenue of PHW EGS can
   reach to 0.251 CNY/(kW·h), 9.27 × 108 CNY and 6.65 × 108 CNY after 40 years
   of operation, respectively.


 * EVALUATION AND RANKING OF THE CO<INF>2</INF> STORAGE POTENTIAL IN LOW TO
   MEDIUM TEMPERATURE GEOTHERMAL FIELDS IN INDONESIA
   
   2023, Case Studies in Chemical and Environmental Engineering
   Show abstract
   
   Carbon capture and storage (CCS) is considered as a solution for achieving
   CO2 emission reduction targets in Indonesia. On a commercial scale,
   geological carbon storage (GCS) systems have significant capital costs and
   energy penalties that the production of geothermal energy could somewhat
   compensate it. Coupling geothermal energy and geologic CO2 storage in
   sedimentary basins is promising because of their large CO2 storage
   capacities. The finding of this preliminary assessment indicates the
   attractiveness of combining CO2 sequestration and geothermal utilization in
   low to medium temperature geothermal fields. The crucial criteria of this
   evaluation are the geothermal gradient, maturity, tectonic setting, geology,
   and hydrogeology. Due to their favorable tectonic conditions (rift valley),
   minimal faulting and fracture, and lack of active faults, the presence of
   geological structures are very minimal, leading to the conclusion that they
   are suitable for storing CO2. There is no prior research has specifically
   identified the suitability of low to medium temperature geothermal fields in
   Indonesia to be combined with CO2 storage, a rank of locations based on the
   suitability as CO2 storage, and its utilization. The output of this study is
   an indicative map of low- to medium-temperature geothermal fields for CO2
   storage. It brings up new possibilities for using low to medium temperature
   geothermal fields as geological CO2 storage in addition to hydrocarbon
   reservoirs, CBM, and deep saline water.


 * THERMODYNAMIC INVESTIGATION OF A CENTRIFUGAL REVERSE BRAYTON CYCLE FOR
   REFRIGERATION IN AIR CONDITIONING FILED
   
   2023, International Journal of Refrigeration
   Show abstract
   
   The reverse Brayton cycle (RBC) is known to exhibit a lower coefficient of
   performance (COP) when compared to conventional vapor-compression
   refrigeration systems. To tackle this issue, this study proposes a
   centrifugal reverse Brayton cycle (CRBC) that features a rotating heat
   exchanger, which utilizes the conversion mechanism between equal potential
   energy and pressure energy to enhance system performance. The findings
   indicate that the COP of the CRBC is roughly inversely proportional to the
   working fluid density, making CO2 a more suitable option for CRBC systems
   than conventional working fluids. We propose three different cycles for the
   CRBC system: the diamond cycle, trapezoid cycle, and rectangle cycle. From
   both technical and operational perspectives, the trapezoid cycle appears to
   be the preferred choice for CRBC. When the isentropic efficiency of the CRBC
   system exceeds 95%, its coefficient of performance (COP) ranges from 5.31 to
   5.7, whereas the COP of transcritical carbon dioxide refrigeration cycle
   (tCO2), air RBC, and CO2 RBC are around 4.3, 1.9, and 0.79, respectively.
   This suggests that the performance of the CRBC system surpasses that of RBC
   by a significant margin, while achieving comparable performance to
   conventional vapor compression refrigeration systems. Moreover, the
   dimensionless power reflecting the installation capacity requirements for
   CRBC, tCO2, air RBC and CO2 RBC are around 0.2, 0.35, 5.3 and 1.9,
   respectively. This indicates that the compressor/expander capacity demand for
   system CRBC approaches the thermodynamic minimum.


 * NUMERICAL SIMULATION OF THE HEAT PRODUCTION POTENTIAL OF GUIDE BASIN IN CHINA
   CONSIDERING THE HETEROGENEITY AND ANISOTROPY OF THE RESERVOIR
   
   2022, Geothermics
   Citation Excerpt :
   
   In this work, the flow impedance was within 0.48 -0.55 MPa/(kg/s), which was
   higher than the evaluation criteria. Therefore, measures need to be taken to
   reduce the flow impedance of the system, such as using CO2 as working fluid
   (Fleming et al., 2022). The pump efficiency is taken as 80% (Zeng et al.,
   2016), and the energy efficiency is calculated.
   
   Show abstract
   
   Understanding heat production performance is crucial for the development and
   utilization of geothermal reservoirs. This study investigates the heat
   production characteristics of a geothermal heating system in naturally
   fractured reservoirs of the Guide Basin in China while considering the
   heterogeneity and anisotropy of the reservoir. A 3D discrete fracture network
   (DFN) model is established based on the fracture information obtained from
   Guide Basin and then the permeability at different locations in the model is
   calculated. Finally, the calculated permeability is used to analyze heat
   production performance using TOUGH2. The results indicate the cumulative heat
   production in 40 years is 987 GWh, which is equivalent to the heat produced
   by 1.48×108 kg of standard coal. The proposed methodology, which considers
   the heterogeneity and anisotropy of the reservoir, combines the advantages of
   the DFN model and continuous medium model and can be used to analyze other
   geothermal reservoirs.


 * USING CO<INF>2</INF>-PLUME GEOTHERMAL (CPG) ENERGY TECHNOLOGIES TO SUPPORT
   WIND AND SOLAR POWER IN RENEWABLE-HEAVY ELECTRICITY SYSTEMS
   
   2022, Renewable and Sustainable Energy Transition
   Citation Excerpt :
   
   Electricity demand data were not available outside 2010 for Rugby and as a
   result our sensitivity analysis does not incorporate winter-peaking
   electricity demand conditions. We have not included (heat or electric) power
   performance or sensitivity analyses of CPG or CPG-F systems in the
   publication here, as we addressed such performance analyses in Randolph and
   Saar [14], Adams et al. [15], Garapati et al. [17], Ezekiel et al. [43],
   Ezekiel et al. [44], Fleming et al. [24] and Fleming et al. [19].
   Furthermore, we conducted CPG parameter sensitivity analyses regarding power
   generation [45] as well as both power generation and reservoir heat depletion
   rates [18].
   
   Show abstract
   
   CO2-Plume Geothermal (CPG) technologies are geothermal power systems that use
   geologically stored CO2 as the subsurface heat extraction fluid to generate
   renewable energy. CPG technologies can support variable wind and solar energy
   technologies by providing dispatchable power, while Flexible CPG (CPG-F)
   facilities can provide dispatchable power, energy storage, or both
   simultaneously. We present the first study investigating how CPG power plants
   and CPG-F facilities may operate as part of a renewable-heavy electricity
   system by integrating plant-level power plant models with systems-level
   optimization models. We use North Dakota, USA as a case study to demonstrate
   the potential of CPG to expand the geothermal resource base to locations not
   typically considered for geothermal power. We find that optimal system
   capacity for a solar-wind-CPG model can be up to 20 times greater than
   peak-demand. CPG-F facilities can reduce this modeled system capacity to just
   over 2 times peak demand by providing energy storage over both seasonal and
   short-term timescales. The operational flexibility of CPG-F facilities is
   further leveraged to bypass the ambient air temperature constraint of CPG
   power plants by storing energy at critical temperatures. Across all
   scenarios, a tax on CO2 emissions, on the order of hundreds of dollars per
   tonne, is required to financially justify using renewable energy over
   natural-gas power plants. Our findings suggest that CPG and CPG-F
   technologies may play a valuable role in future renewable-heavy electricity
   systems, and we propose a few recommendations to further study its
   integration potential.


 * AN INTEGRATED DECISION-MAKING APPROACH WITH GOLDEN CUT AND BIPOLAR Q-ROFSS TO
   RENEWABLE ENERGY STORAGE INVESTMENTS
   
   2023, International Journal of Fuzzy Systems
   
   

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