Hybrid Uses of High-Temperature Reservoir Thermal Energy Storage: Lessons Learned from Previous Projects

Abstract

One of the critical challenges of the green energy transition is resolving the mismatch between energy generation provided by intermittent renewable energy sources such as solar and wind and the demand for energy. There is a need for large amounts of energy storage over a range of time scales (diurnal to seasonal) to better balance energy supply and demand. Subsurface geologic reservoirs provide the potential for storage of hot water that can be retrieved when needed and used for power generation or direct-use applications, such as district heating. It is important to identify potential issues associated with high-temperature reservoir thermal energy storage (HT-RTES) systems so that they can be mitigated, thus reducing the risks of these systems. This paper reviews past experiences from moderate and high-temperature reservoir thermal energy storage (RTES) projects, along with hot water and steam flood enhanced oil recovery (EOR) operations, to identify technical challenges encountered and evaluate possible ways to address them. Some of the identified technical problems that have impacted system performance include: 1) insufficient site characterization that failed to identify reservoir heterogeneity; 2) scaling resulting from precipitation of minerals having retrograde solubility that form with heating of formation brines; 3) corrosion from low pH or high salinity brines; 4) thermal breakthrough between hot and cold wells due to insufficient spacing. Proper design, characterization, construction, and operational practices can help reduce the risk of technical problems that could lead to reduced performance of these thermal energy storage systems.

Full text

SPE-215750-MS
Hybrid Uses of High-Temperature Reservoir Thermal Energy Storage:
Lessons Learned from Previous Projects
P. F. Dobson, Energy Geosciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA, USA; T.
A. Atkinson, W. Jin, and M. Acharya, Idaho National Laboratory, Idaho Falls, ID, USA; D. Akindipe, National
Renewable Energy Laboratory, Golden, CO, USA; B. Li and T. McLing, Idaho National Laboratory, Idaho Falls, ID,
USA; R. Kumar, Energy Geosciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA, USA
2023. Not subject to copyright. This document was prepared by government employees or with government funding that places it in the public domain. DOI
10.2118/215750-MS
This paper was prepared for presentation at the SPE Energy Transition Symposium held in Houston, Texas, USA, 22-23 August 2023.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents
of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect
any position of the Society of Petroleum Engineers, its officers, or members.
Abstract
One of the critical challenges of the green energy transition is resolving the mismatch between energy
generation provided by intermittent renewable energy sources such as solar and wind and the demand for
energy. There is a need for large amounts of energy storage over a range of time scales (diurnal to seasonal)
to better balance energy supply and demand. Subsurface geologic reservoirs provide the potential for storage
of hot water that can be retrieved when needed and used for power generation or direct-use applications,
such as district heating. It is important to identify potential issues associated with high-temperature reservoir
thermal energy storage (HT-RTES) systems so that they can be mitigated, thus reducing the risks of these
systems. This paper reviews past experiences from moderate and high-temperature reservoir thermal energy
storage (RTES) projects, along with hot water and steam flood enhanced oil recovery (EOR) operations, to
identify technical challenges encountered and evaluate possible ways to address them. Some of the identified
technical problems that have impacted system performance include: 1) insufficient site characterization
that failed to identify reservoir heterogeneity; 2) scaling resulting from precipitation of minerals having
retrograde solubility that form with heating of formation brines; 3) corrosion from low pH or high salinity
brines; 4) thermal breakthrough between hot and cold wells due to insufficient spacing. Proper design,
characterization, construction, and operational practices can help reduce the risk of technical problems that
could lead to reduced performance of these thermal energy storage systems.
Introduction
The world is facing unprecedented challenges in responding to climate change, and one of the major actions
being taken is to transition energy generation from a fossil-fuel based system to renewable energy sources
to reduce greenhouse gas emissions. However, two of the major renewable energy technologies being
deployed, wind and solar, generate energy intermittently, resulting in large imbalances between electricity
supply and demand. This has resulted in heightened interest in energy storage technologies that can provide
grid stability and resilience (e.g., Heuberger and Mac Dowell, 2020; Schill, 2020; Hunter et al., 2021;
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Balducci et al., 2021). The need for improved energy storage systems has prompted the US Department
of Energy to initiate an energy storage grand challenge (US DOE, 2020). Many different energy storage
technologies are under consideration, including electrochemical batteries (such as lithium-ion, sodium-ion,
nickel-cadmium, sodium-sulfur, and redox flow), superconducting magnetic energy storage, mechanical
energy storage (such as pumped hydro storage, flywheel energy storage, and compressed air energy storage),
and thermal energy storage (such as molten salts, phase change materials, and geologic thermal energy
storage) (e.g., Wang et al., 2022; Kebede et al., 2022). These energy systems have a wide range of storage
durations, recharge and discharge times, and costs.
The focus of our current research is to evaluate the viability of using porous and permeable sedimentary
formations in the subsurface for high temperature reservoir thermal energy storage (HT-RTES). It involves
taking water from a subsurface reservoir formation using a cold well, bringing it to the surface and heating it,
reinjecting it into a hot well, and then withdrawing the stored hot water when needed for either generation of
electricity or for direct use applications (Fig. 1). The recharge and discharge can either be seasonal (storing
excess heat in the summer months and recovering it in the wintertime), or a shorter daily cycle, depending
on the availability of energy to supply heat and the need for the stored thermal energy.
Fig. 1—A conceptual model of a reservoir thermal energy storage (RTES) system (US DOE, 2020).
While there are thousands of low temperature aquifer thermal energy storage (ATES) systems deployed
worldwide (Fleuchaus et al., 2018), there are only a few high temperature ATES/RTES systems that have
developed. There are several current research initiatives, such as HEATSTORE (Koornneef et al., 2019),
VESTA (Bremer et al., 2022), and the US DOE's Hybrid Geothermal projects (e.g., Zhu et al., 2023) that
are focusing on developing these types of thermal energy storage resources. The attractions for storing
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higher temperature fluids are multiple: it provides a higher energy density storage system, and the high
temperatures allow for more ways to use the stored heat (including power generation). However, a number
of challenges have arisen that have impeded large-scale deployment of these systems (e.g., Fleuchaus et al.,
2020; McLing et al., 2022). Below we briefly review some of the issues that have occurred for previous
HT-ATES systems as well as from hot water and steam flood EOR operations.
Examples of Past HT-ATES Operational Issues
Previous reviews of past, current, and planned HT-ATES systems were conducted by Fleuchaus et al. (2020)
and McLing et al. (2022). They noted the following technical issues that have impacted these projects:
1) insufficient site characterization; 2) geochemical issues such as scaling, corrosion, clay swelling, and
potential contamination of neighboring aquifers; 3) thermal breakthrough between hot and cold wells; and
4) geomechanical issues, such as induced seismicity, uplift and/or subsidence. Here, we highlight some of
the main issues that occurred at these different HT-ATES sites, focusing on how they have impacted system
performance.
Insufficient site characterization
Thorough site characterization is critical to provide the information needed to properly assess and predict
the performance of a geological thermal energy storage system. Geologic reservoirs are not homogeneous
features, and the presence and distribution of heterogeneities will impact the reservoir storage and flow
properties. Having a low permeability seal at the top of the reservoir is another critical consideration.
Knowledge of the thermal conductivity of the reservoir and sealing formations is also important to constrain
thermal modeling, as is whether or not the aquifer has significant lateral flow, which might sweep stored
heat away from the production well.
An HT-ATES system has been in operation at Wageningen since 2012 (Bakema and Drijver, 2019;
Bakema et al., 2019; Kallesøe and Vangkilde-Pedersen, 2019). This system, which stores heat provided by
solar collectors, is hosted by the Oosterhout Formation at a depth of 220-290 m, and consists of a well
doublet about 60 m apart (Bakema et al., 2019; Kallesøe and Vangkilde-Pedersen, 2019). The amounts of
stored and recovered heat from this system are much lower than the original design parameters. This poor
performance is in part attributed to a failure to identify the large vertical variations in reservoir permeability,
as flow tests determined that 90% of the flow was occurring in the upper 27 m of the aquifer (Kallesøe and
Vangkilde-Pedersen, 2019), resulting in reduced (more than 50% lower than expected) well flow rates and
a lower reservoir storage capacity than predicted at the start of the project.
Geochemical Issues
Corrosion. The HT-ATES system in Neubrandenburg was developed from a pre-existing geothermal
heating system that was commissioned in 1989, with four wells drilled to depths of 1,150 to 1,250 m (Zenke
et al., 2000; Seibt and Kellner, 2003; Kabus, 2003; Kabus et al., 2005; Seibt and Kabus, 2006; Seibt and
Wolfgramm, 2008; Seibt et al., 2010). This original system was used to supply a district heating system,
and was supplemented with a gas and steam turbine cogeneration plant (Seibt and Kabus, 2006; Kabus et
al., 2009). The geothermal wells produced water with temperatures of ~50-55°C and flow rates of up to 100
m3/h. However, corrosion of pipes from exposure to oxygenated geothermal brines resulted in decreased
injectivity, leading to the closure of the system in 1998. Two of the existing wells were deepened and
recompleted to form a doublet, and configured with a heat exchanger for a smaller district heating system.
The new HT-ATES system operated from 2005 to 2019, when the public utility moved to an artificial storage
tank to balance short-term differences in supply and demand (Fleuchaus et al., 2020). Operational issues
related to microbially mediated corrosion impacted the submersible pump in the cold well and resulted in
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significant downtime during four different years (Kabus et al., 2009; Lerm et al., 2013; Westphal et al.,
2016).
Scaling and Clay Swelling. One of the initial concerns for the now-defunct Utrecht HT-ATES system was
the potential for calcium carbonate scaling in the heat exchanger. One solution to this problem is reducing the
dissolved Ca concentration through Ca-Na exchangers. A potential drawback of this approach is potential
clay swelling in the aquifer and associated pore space clogging (Willemsen, 1992). Modeling conducted by
Willemsen (1992) evaluated the potential for clay swelling by calculating the sodium adsorption ratio, with
results indicating that only a portion of the heated water should undergo ion exchange treatment. The cation
exchange system had some operational issues that resulted in major well clogging issues (either from clay
swelling or calcite precipitation), resulting in a flow reduction of 85% in the first two years of operation of
the hot well, ultimately leading to its failure (Drijver, 2011). At the Wageningen site, the use of improper
drilling fluids might have led to clay swelling and resulting in formation damage, also decreasing system
performance (Kallesøe and Vangkilde-Pedersen, 2019).
Thermal Breakthrough
One of the challenges of designing a HT-ATES system is that the original operational parameters that are
used to develop the system might change due to operational constraints. One example is the Koppert-
Cress horticultural complex in the Netherlands, whose growth has led to changing thermal needs. This
system is now operated as a diurnal, weekly, and seasonal thermal energy storage system, as it is used
to balance both short-term and long-term energy storage requirements. Heating needs currently outweigh
cooling requirements for the overall system so the cold storage portion of the system has grown faster than
the warm storage. The operators plan to address this imbalance by recovering and storing additional ambient
heat (Bloemendal et al., 2019; 2020).
The Hooge Burch healthcare facility in Zwammerdam operated an HT-ATES system from 1998-2003.
A combined heat power plant (CHP) provided heat to the system, where 13°C groundwater was heated to
90°C. The HT-ATES system consisted of a well doublet separated by 67 m that utilized a sandstone aquifer
(Bakema and Drijver, 2019; Bakema et al., 2019; Kallesøe and Vangkilde-Pedersen, 2019). After 4 years
of operation, modeling constrained by detailed field monitoring data indicated that the hot well fluids had
migrated right next to the cold well.
Examples of Past Enhanced Oil Recovery Water and Steam Flood Issues
The oil and gas industry has extensive experience with injecting hot water into subsurface reservoirs as part
of enhanced oil recovery operations. The following is just a small representation of this history, providing
some observations that have been obtained through many years of conducting these operations around the
world.
Geochemical Issues
Injection of hot water and steam has been observed to result in various types of scale formation. Injection
of steam can result in the formation of a high pH hot water component that exits at the bottom of the
well, dissolves large amounts of silica, and when it cools and becomes more neutral, silica will precipitate
(Bowman et al., 2000). In some cases, this is actually viewed as desirable, as it provides sand control and
still retains some permeability, but this phenomenon becomes problematic when impermeable metal silicate
scale forms, such as was observed in the Wilmington (California) high pressure, high temperature steam
flood. Moghadasi et al. (2004) noted that prolonged injection of seawater for pressure support at the Siri
field led to gypsum scale formation that caused a 75% reduction in injectivity over 6 years. They did a series
of experiments in a packed column filled with sand or glass beads, heated to 50-80°C, and flowing different
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sulfate and carbonate brine solutions to evaluate scale formation. They observed more rapid decreases in
permeability with higher flow rates, increased temperatures, and higher solution concentrations.
Another issue that can occur with injecting brines into oilfield formations is swelling clays. Zhou et
al. (1995) noted that the hydration of interlayer cations and the formation of diffuse double layers would
result in clay swelling and a subsequent reduction in permeability. This effect will be more prominent in
sandstones with smectite and mixed-layer clays.
Ye et al. (2023) studied the effects of water flooding in a carbonate oilfield in the Middle East. The
injected water had high salinity and elevated H2S contents, leading to severe problems with both corrosion
and scaling. Their review of this field indicated that temperature, salinity (due to chloride), sulfide content,
and the presence of sulfate-reducing bacteria were the main factors leading to corrosion and scaling. Based
on laboratory experiments, higher temperature and sulfide contents result in increased overall corrosion and
scaling, while increased salinity might cause localized corrosion to occur. The presence of sulfate-reducing
bacteria leads to iron sulfide formation and corrosion of carbon steel. Four years of field testing indicates that
the addition of corrosion inhibitors to the injected water and removing sulfur from the water have resulted
in an 80% reduction in corrosion leakage at the field.
Geomechanical Issues
Similar geomechanical concerns are obtainable in EOR applications. However, additional effects such as
casing shear, reduced well integrity, and caprock failure have been observed in previous steam injection
projects (Shafiei & Dusseault, 2013). Casing shear occurs when the differential horizontal shear stress
across the formation-caprock interface increases and becomes high enough to overcome the casing material
strength, causing a shear slip in the wellbore (Dusseault et al., 2001). This happens during rapid convection
of thermal energy from the wellbore to the surrounding formation relative to the slow conduction of heat
in the caprock. Another consequence of this is caprock failure. This can occur if the injection pressure
in the reservoir is higher than the horizontal compressive stress within the caprock; thereby, creating
vertical fractures that extend from the caprock towards other overlying formations (Carlson, 2012; Shafiei
& Dusseault, 2013). This was suspected as the primary cause of caprock failure in Joslyn Creek SAGD
Thermal Operation in Canada (Carlson, 2012). Cement sheath integrity could be compromised after multiple
cyclic steam injection/production sequences. This could be more severe in cases where wells that were
not originally purposed for high temperature applications are repurposed for steam floods. Taoutaou et al.
(2010) reported this as part of their field evaluation of steam cyclic steam flooding in the Oudeh field in
Syria. They found that sheath integrity loss results from an overall increase in the Young Modulus (due to
an increase in the effective stress) of the cement (Taoutaou et al., 2010).
Mitigation Approaches
There have been a number of mitigation methods that have been numerically modeled, tested in the
laboratory, and validated through field operations. Below is a brief summary of some of these examples.
Site Characterization
Many of the HT-ATES projects conducted extensive site characterization, including review of prior
geological and hydrological studies of the area, drilling of characterization boreholes and conducting
hydrologic testing of potential storage formations, and developing 3D geohydrological models. The
Middenmeer HT-ATES site is located by one of the largest greenhouse complexes in the Netherlands. Two
candidate reservoirs were evaluated through test drilling in 2019: an aquifer in the Maassluis Formation, and
a deeper aquifer in the Oosterhout Formation. Higher flow rates found in the upper reservoir, combined with
significant levels of methane detected in the lower reservoir, led to the selection of the Maassluis Formation
aquifer for the HT-ATES system. A new HT-ATES system is being considered for the TU Delft campus, and
two candidate formations are being evaluated (Bloemendal et al., 2021). The shallower Maassluis Formation
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would cost less to access, but this aquifer is already being utilized for ATES systems in the area, so the
impact on these existing neighboring systems needs to be considered. The deeper Ommelanden Formation
does not have competing uses, but the presence of carbonates might lead to scaling, and this formation is
lacking in information about the reservoir permeability. Bloemendal et al. (2021) did thermo-hydrologic
(TH) modeling to evaluate the effects of density-driven flow on the thermal plume within the HT-ATES.
Geochemical Issues
Many of the HT-ATES projects were successful in controlling corrosion by ensuring that returning fluids
were not oxygenated. This often involved using nitrogen as headspace gas in the wells, such as was
employed in the Berlin (Sanner et al., 2005; Wolfgramm et al., 2011) and Neubrandenburg HT-ATES
systems.
Most of the HT-ATES systems had geochemical, temperature, and hydrologic monitoring systems, and
resulting measurements were used to calibrate geochemical models used to evaluate the potential for scaling
and corrosion (e.g., Sanner et al., 2005; Wolfgramm and Seibt, 2006; Würdemann et al., 2014). The Rostock
HT-ATES system has a series of seven monitoring wells with more than 50 temperature sensors to detect
any thermal and geochemical changes (Schmidt et al., 2000; Bartels et al., 2003; Schmidt and Müller-
Steinhagen, 2004). The Neubrandenburg system had a bypass system installed to monitor fluid chemistry,
physical fluid parameters, pH, redox potential, and conductivity (Würdemann et al., 2014). Monitoring
wells were also installed at Utrecht (Bakema and Drijver, 2019).
Addition of HCl to the Hooge Burch Zwammerdam was successfully used to control carbonate scaling,
and was used based on field pH measurements and carbonate saturation calculations (Drijver, 2011). As
mentioned earlier, the attempts to use an ion exchange to modify the injection water chemistry was not
successful at Utrecht.
A design concept was developed by the BMW group to evaluate the viability of a proposed HT-ATES
system near Munich, Germany, that would be completed in the Malm carbonate aquifer. Field push-pull tests
and detailed thermal and geochemical modeling studies were conducted to assess how the Malm reservoir
would perform. These studies indicated a lower-than-expected thermal recovery from the system, and also
indicated a strong likelihood for carbonate scale formation. While injection of CO2 potentially could be
used to mitigate carbonate scale precipitation, the modeling results suggested that increasing amounts of
CO2 would be needed over time and would also lead to degradation of the HT-ATES performance (Ueckert
and Baumann, 2019; Ueckert et al., 2020). These negative results led to the abandonment of the project.
Corrosion-resistant materials were also employed at some sites. For the Berlin HT-ATES system, the
piping is made of glass-fiber-reinforced resins (Sanner et al., 2005), and glass-fiber-reinforced epoxy casing
was used for the wells at Hooge Burch Zwammerdam and Utrecht (Bakema et al., 2019). Chen et al. (2017)
noted that corrosion and scaling frequently occurred in metal casing used for enhanced oil recovery water
injection operations, and tested the effectiveness of nonmetallic composite (ceramic-lined) tubing, which
resulted in much less degradation of the tubing.
One main concern for HT-RTES systems is that the retrograde solubility of carbonate and sulfate minerals
will result in the precipitation of these minerals upon heating, which could lead to the scaling of wells, heat
exchangers, and reduced permeability and porosity within the reservoir. Spycher et al. (2021) examined
the scaling potential for brines from four potential formations (Mt. Simon, Weber, St. Peter, and Lower
Tuscaloosa) within three different sedimentary basins in the US. While all brines were quite saline (total
dissolved solids between 25,000 to 150,00 mg/L), the scaling potential was not just a function of the TDS,
but instead depended on the chemical composition of the brine as well as the magnitude of the temperature
change that will occur from native state to HT-ATES. The formation brine with the highest TDS, from the
Lower Tuscaloosa, actually had the least potential for scaling to occur with heating (Fig. 2).
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Fig. 2—Brine compositions depicted in Stiff plots (upper row), computed changes in pH
(middle row) and amounts of mineral precipitation (in grams per initial cubic meter of brine)
(bottom row) upon heating deep brines from their formation temperatures (Spycher et al, 2021).
Similar types of geochemical modeling to evaluate the potential for scaling have been conducted for
the HT-ATES pilot study sites in Karlsruhe, Germany (Banks et al. 2020; Nitschke et al., 2023) and Bern,
Switzerland (Diaz-Maurin and Saaltink, 2021).
Finally, chemical inhibitors are commonly used to prevent mineral phases from forming scale in
geothermal wells and surface equipment (e.g., Gallup, 1989: Siega et al., 2005; De Pereira, 2014; Zotzmann
et al., 2018). Acid treatments are also frequently applied to geothermal wells to remove scale and reduce
skin effects. Similar types of applications would be feasible for a HT-ATES system prone to these issues.
Geochemical modeling is also commonly utilized to evaluate scale formation associated with EOR
operations (e.g., Vetter and Phillips, 1970; Mackay and Graham, 2003; Lu et al., 2016; Shajari and Rashidi,
2017). These models evaluate the scaling potential of water being injected into the oil reservoir, studying
its potential at the wellhead, within the wellbore, and in the near wellbore region of the reservoir. A variety
of different modeling codes, thermodynamic databases, and models linking scale deposition to changes in
permeability and porosity (such as Kozeny-Carman), have been used to assess the impacts of scaling on
reservoir performance.
Al-Ibrahim et al. (2022) conducted a series of laboratory core flood experiments at 250°F (121°C) to
assess the impact of using high salinity brines for EOR operations in both carbonate and clastic reservoirs.
The presence of iron in the formation water in the cores led to precipitation of iron oxides and sulfides,
depending on the core saturation fluid composition. The formation of iron oxides was halted by adding
an oxygen scavenger (sodium erythorbate) to the system. However, iron carbonate still precipitated in the
core samples, leading to significant permeability reduction. Treating the injection water with potassium
permanganate together with the oxygen scavenger under near-neutral pH conditions resulted in preventing
any significant scale formation from occurring in the cores.
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Thermal Breakthrough
Many of the HT-ATES projects conducted initial extensive TH and thermo-hydrologic-chemical (THC)
modeling to assess the performance of the designed system and evaluate if the planned locations of the
monitoring and hot and cold wells were appropriate (e.g., Schmidt et al., 2000; Dijkstra et al., 2020;
Bloemendal et al., 2021).
Geomechanical Issues
There are several types of geomechanical concerns relating to HT-ATES systems. The injection of heat into
the subsurface will in increase the thermal stress and might also cause uplift due to thermal expansion. Vidal
et al. (2022) performed coupled thermo-hydrologic-mechanical (THM) modeling of the HEATSTORE Bern
pilot site to evaluate the potential for surface uplift. The proposed HT-ATES site would store heat in a series
of confined sandstone aquifers between 200 to 500 m in depth. The initial simulations predicted vertical
displacements up to 5 cm at the surface above the central well. Sonnenthal et al. (2021) developed similar
types of THM models to evaluate an RTES system that was envisioned for the Portland Basin, Oregon,
USA. The conceptual model for this system consisted of an injection and a production well about 500 m
apart with access to the RTES, located 393 m below the surface. After 50 years of simulated operation,
the production wells experienced about 8.5 mm of subsidence, and the injection well had about 2 mm of
uplift. The model indicated that horizontal stress changes were significant (~0.5 MPa) at least 500 m from
the wells, and were large enough to potentially "trigger" seismicity on active faults, if they were within this
distance. Thus, detailed structural mapping combined with THM modeling might be required to properly
evaluate seismic hazards related to HT-RTES operations.
For EOR systems, cyclic thermal injection also causes a wider variation in the Young Modulus and
Poisson ratio at higher temperatures compared to low temperature applications, creating several micro annuli
that laterally extend from the casing-cement boundary towards the surrounding formation. One solution to
this issue is to increase the silica content (up to 35-40% by weight) in the cement slurry (Taoutaou et al.,
2010). Other solutions involve the use of high strength and thermal stable materials as cement additives
(Cai et al., 2022).
Conclusions
The use of geologic reservoirs to store high temperature waters is a promising technology option for
large-volume, medium to long time duration energy storage. Because of the uncertainties associated with
subsurface reservoirs, there remain risks associated with these systems. Previous HT-ATES projects and
experience with enhanced oil recovery water and steam floods provide important lessons that can be applied
to reduce these risks. There are a number of key learnings that can be gleaned from these prior studies.
These include:
1. Detailed site characterization is important to inform geologic and hydrologic models. These
observations are important to ensure that the reservoir has sufficient permeability and porosity to have
good performance characteristics. It is also essential to ascertain that the reservoir seal is adequate to
prevent the loss of heat and fluids. Mapping of structures and determination of the state of stress will
be important to evaluate the potential for induced seismicity. Knowledge of the mineralogy and fluid
chemistry is critical to inform geochemical models to evaluate scaling and corrosion potential.
2. The site characterization information can then inform the creation of detailed 3D TH, THC, and THM
models that can be used to predict system performance and optimize system design. Such models
should be updated as new information on the system becomes available.
3. Many causes for poor performance are related to scaling, corrosion, and clay swelling. It is important
to identify these potential problems early, and to either avoid them by selecting another site or develop
appropriate mitigation measures. The use of chemical inhibitors and use of noncorrosive materials
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SPE-215750-MS 9
in well construction might be needed. Acid treatments can be used to dissolve scale and improve
permeability in some cases. One common issue is the need to avoid introducing oxygenated waters
into reducing environments; the use of nitrogen as a headspace gas can help avoid such issues.
4. Designing and developing a comprehensive monitoring system provides real-time feedback of the
performance of the system, allowing for mitigation measures to be identified and implemented quickly
if needed. Such a system can also help detect early signs of thermal breakthrough between hot and
cold wells, and allow for systems operations to be adjusted accordingly.
This is intended to be an initial review of past experiences, and there are more studies from EOR
operations not described here that would provide additional information and guidance.
Acknowledgments
This material was based upon work supported by the U.S. Department of Energy, Office of Energy
Efficiency and Renewable Energy (EERE), Geothermal Technologies Office, under Contract Number DE-
AC02-05CH11231 with Lawrence Berkeley National Laboratory, Contract Number DE-AC07-05ID14517
with Idaho National Laboratory, and Contract No. DE-AC36-08GO28308 with the National Renewable
Energy Laboratory. The views expressed herein do not necessarily represent the views of the DOE or the
U.S. Government.
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