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Integrating CO2 Storage with Geothermal Resources for Dispatchable Renewable Electricity
Available online at www.sciencedirect.com
ScienceDirect Energy Procedia 63 (2014) 7619 – 7630
GHGT-12
Integrating CO2 Storage with Geothermal Resources for Dispatchable Renewable Electricity Thomas A. Buschecka, Jeffrey M. Bielickib,c, Mingjie Chena, Yunwei Suna, Yue Haoa, Thomas A. Edmundsa, Martin O. Saard,e, and Jimmy B. Randolphd a Lawrence Livermore National Laboratory, Livermore, CA 94550, USA Department of Civil, Environmental, & Geodetic Engineering, cJohn Glenn School of Public Affairs, The Ohio State University, Columbus, OH 43210, USA d Department of Earth Sciences, University of Minnesota, Minneapolis, MN 55444, USA e Geothermal Energy and Geofluids Group, Department of Earth Sciences, ETH-Zürich, Zürich, CH
b
Abstract We present an approach that uses the huge fluid and thermal storage capacity of the subsurface, together with geologic CO2 storage, to harvest, store, and dispatch energy from subsurface (geothermal) and surface (solar, nuclear, fossil) thermal resources, as well as energy from electrical grids. Captured CO2 is injected into saline aquifers to store pressure, generate artesian flow of brine, and provide an additional working fluid for efficient heat extraction and power conversion. Concentric rings of injection and production wells are used to create a hydraulic divide to store pressure, CO2, and thermal energy. Such storage can take excess power from the grid and excess/waste thermal energy, and dispatch that energy when it is demanded, enabling increased penetration of variable renewables. Stored CO2 functions as a cushion gas to provide enormous pressure-storage capacity and displaces large quantities of brine, which can be desalinated and/or treated for a variety of beneficial uses. Geothermal power and energy-storage applications may generate enough revenues to justify CO2 capture costs. © 2014 2013The TheAuthors. Authors. Published by Elsevier Ltd. is an open access article under the CC BY-NC-ND license © Published by Elsevier Ltd. This (http://creativecommons.org/licenses/by-nc-nd/3.0/). Selection and peer-review under responsibility of GHGT. Peer-review under responsibility of the Organizing Committee of GHGT-12 Keywords: Geothermal energy; bulk energy storage; thermal energy storage; parasitic load; geologic CO2 storage; CO2 utilization; brine utilization
1. Introduction Climate change mitigation requires a range of measures to reduce atmospheric CO2 emissions—the most important being increased reliance on electricity generated from renewable and low-carbon energy resources, and reduced CO2 intensity of fossil energy use. Renewable energy technologies must be matched with bulk and thermal energy storage in order to reach their full potential, but there are presently no energy storage technologies that are economically feasible and widely deployable. Only the subsurface, with its vast volumes and high pressures, has the capacity to "firm" renewables with carbon-neutral (or carbon-negative) storage. *Corresponding author. Tel: +1-925-423-9390; fax: +1-925-423-0153 E-mail address: [email protected]
1876-6102 © 2014 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/3.0/). Peer-review under responsibility of the Organizing Committee of GHGT-12 doi:10.1016/j.egypro.2014.11.796
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Geologic CO2 storage (GCS) is a promising means of reducing CO2 intensity of fossil energy use, but the high cost of capturing CO2 requires valuable uses for CO2 to justify those costs. Our approach is unique: initial "charging" of the system requires permanently isolating large volumes of captured CO2 and thus creates a market for its disposal. Once charged, our system can take power from, and deliver power to, electricity grids with the opposite timing of current solar and wind energy technologies, mitigating issues associated with high penetration of these variable energy sources, including the possibility of curtailments to wind power deliveries during periods of high winds and low loads. Our approach involves multi-fluid geothermal energy systems [1,2,3,4,5], and their extension, which includes thermal energy storage, resulting in multi-fluid geo-energy systems [6], in which CO2 and/or N2 are injected into permeable sedimentary formations. This injection stores pressure, generates artesian flow of formation brine, and provides a cushion gas and supplemental working fluids for efficient fluid recirculation, heat extraction, and power conversion, as well as providing the option for bulk energy storage (BES) and thermal energy storage (TES). Here, we present geothermal energy, BES and TES applications that use CO2 as the supplemental working fluid/cushion gas. 1.1. CO2 Plume Geothermal (CPG) The use of supercritical CO2 as a working fluid in geothermal systems was first proposed for Engineered Geothermal Systems (EGS) in low-permeability, hot crystalline basement rocks [7,8]. For exploitation, CO2 EGS requires hydrofracturing or hydro-shearing tight formations to develop sufficient permeability for fluid recirculation [4]. Supercritical CO2 has multiple advantages compared to brine, including: x low kinematic viscosity, compared to brine, allowing for effective heat advection despite its relatively low heat capacity x high thermal expansibility, compared to brine, generating a much stronger thermosiphon effect through the injection well, the reservoir, and the production well These and other advantages of CO2 over brine can reduce or eliminate the need for pumps to drive recirculation of the underground working fluid through the reservoir [9,10,11]. CO2 Plume Geothermal (CPG) differs from employing CO2 EGS [7,8] because CPG extracts heat from sedimentary or stratigraphic reservoirs that have naturally high permeability and are much larger than the artificially generated EGS reservoirs [12,13,14,15,16,17]. Because sedimentary reservoirs are much larger than hydrothermal upflows, they have lower, more predictable, drilling risk than typically associated with geothermal reservoirs in hydrothermal upflows. Further, these large reservoirs can hold large amounts of CO2 that can take up the heat that is widely distributed throughout the reservoir resulting in a significant energy source, despite the relatively low temperatures (~100oC) of such fairly shallow (~3 km deep) reservoirs. Such stratigraphic reservoirs are common throughout the world [18] as they exist, for example, below approximately half of North America [19,20,21]. These reservoirs are also the target of GCS efforts [22] to reduce global climate change [23]. Coupling CPG with a GCS project creates a CO2 capture utilization and storage (CCUS) opportunity that can defray the cost of GCS by using CO2 as a resource to generate electricity. 1.2. Multi-Fluid Geothermal Energy and Hybrid Multi-Fluid Geo-Energy Systems The multi-fluid geothermal energy system approach [1,2,3,4] builds upon the CPG approach [1516] by taking advantage of the fact that CO2 injection creates reservoir overpressure and displaces formation brine that can be produced under artesian conditions. In addition to injecting CO2, this approach includes the option of injecting N2 separated from air into permeable formations (Fig. 1a) to augment and store pressure (bulk energy) and provide efficient working fluids, while adding operational flexibility [24]. Our approach shares some of the attributes of pumped storage hydro and its subsurface equivalent, underground pumped hydro storage [3]. An expansion of this approach, called multi-fluid geo-energy systems [6], can store and dispatch thermal energy generated by surface thermal resources, such as concentrating solar power (CSP) and base-load power plants (Fig. 1b). This expanded approach can be used to levelize the delivery of CSP and mitigate the variability of wind and solar power. Similar to a hybrid nuclear-renewable energy approach proposed by Forsberg [25], our approach may allow low-carbon, base-load power (e.g., nuclear) to operate at full thermal capacity, with excess thermal energy stored during periods of overgeneration being available as dispatchable power during periods of high demand. This storage can provide loadfollowing and peaking capacity and may allow utilities to retire less efficient, carbon-intensive power plants.
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Fig. 1. (a) Vertical cross section of a multi-fluid geothermal energy system [5,6] using only a subsurface geothermal energy resource, showing multiple rings of horizontal injection and production wells. Cooled brine and cushion gas exit the power plant to be injected into a permeable formation. The option exists for heat exchangers in the power plant to transfer heat from hot brine to supercritical CO2/N2 prior to sending those fluids through a Brayton Cycle turbine to boost power conversion efficiency. Pressurized cushion gas and brine inside the hydraulic divide provide bulk energy storage (BES). The outer ring of production wells function as a pressure sink, creating a hydraulic trough that laterally constrains overpressure (stippled shaded area). (b) Similar to (a) except that instead of cold brine, hot brine (heated by a surface thermal energy resource) is injected [6]. Pressurized cushion gas and brine provide BES and enable large-capacity, long-duration (seasonal) thermal energy storage. Hybrid multi-fluid geo-energy systems do not require a high-grade geothermal heat source. In this study, the only cushion gas we considered was CO 2. Although shown here with horizontal wells, this approach can also be deployed with vertical wells.
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Concentric rings of horizontal injection and production wells are arranged to create a hydraulic divide to store pressure, CO2, N2, and thermal energy (Figs. 1a and 1b). This storage offers the ability to take excess power from the grid along with excess/waste thermal energy, and to dispatch that energy when it is demanded. The system is pressurized and/or heated when power supply exceeds demand and depressurized when demand exceeds supply. Supercritical CO2 and N2 function as cushion gases to provide enormous pressure-storage capacity—similar to compressed air energy storage—and as working fluids for highly efficient power conversion in Brayton Cycle turbines. The injection of CO2 and N2 frees up large quantities of make-up brine, which can reduce the use of fresh water for power generation. Time-shifting the parasitic loads associated with pressurizing and injecting brine and N2 provides bulk energy storage over days to months. While similar to pumped hydroelectric storage, the round-trip efficiency is higher because it is accomplished by timeshifting a parasitic load that is already required for fluid recirculation. Further, continuous modulation of the parasitic loads can provide ancillary grid services (e.g., load-following). Our approach is designed to provide large-capacity, longduration thermal energy storage to address diurnal and seasonal variability of supply and demand on electricity grids. 1.3. Deployment Options Our approach is designed for locations where a permeable geologic formation (typically sedimentary rock) is overlain by a caprock that is impermeable enough to constrain the vertical migration of buoyant, pressurized CO2 and/or N2. Ideally, the permeable formation would also be underlain by an impermeable formation (bedrock) to help store pressure. Such geologic conditions exist over much of the contiguous United States [26]. Areas with a sufficient geothermal gradient are required where geothermal energy is the only thermal energy resource, but hybrid applications that combine subsurface and surface thermal energy resources can reduce the need for subsurface heat. One option for a hybrid, multi-fluid, geo-energy system could involve a nuclear power plant with a pressurized water reactor. These systems recirculate 300oC pressurized water. At night during minimum power demand, this water could be put through a heat exchanger to heat brine that is injected and stored in a subsurface reservoir (Fig. 1b). Such a configuration is similar to a high-grade geothermal resource, with the added advantage of being shallower than a typical geothermal reservoir. Further, hybrid operations that switch between power-delivery and thermal-energy-storage modes provide an economic justification for the plant to operate at full thermal capacity. Stored thermal energy can be used for peaking capacity or pre-heating high-temperature, CSP tower systems. Note that this hybrid example is also applicable to CSP parabolic-trough systems that recirculate pressurized water in the 300oC range [27]. 2. Modeling Approach We conduct reservoir analyses with the Nonisothermal Unsaturated Flow and Transport (NUFT) numerical simulator, which simulates multi-phase heat and mass flow and reactive transport in porous media [28,29]. NUFT has been used extensively in GCS reservoir studies [30,31,32,33,34] and for multi-fluid geothermal systems [1,2,3,4,35,36]. The values of pore and water compressibility are 4.5×10-10 Pa-1 and 3.5×10-10 Pa-1, respectively. Water density is determined by the ASME steam tables [37]. The two-phase flow of supercritical CO2 and water is simulated with the density and compressibility of supercritical CO2 determined by the correlation of Span and Wagner [38] and CO2 dynamic viscosity is given by the correlation of Fenghour et al. [39]. A generic system (Fig. 2) is modeled over the course of 30 years, consisting of a 125-m-thick reservoir with a permeability of 100 mD, bounded by low-permeability (caprock and bedrock) seal units each with a permeability of 0.001 mD. Hydrologic properties are similar to previous GCS [30,31,34,40,41,42] and multi-fluid geothermal studies [1,2,3,4,24,35,36,43]. Because conditions are assumed to be laterally homogeneous, we use a radially-symmetric (RZ) model. A geothermal gradient of 37.5oC/km and reservoir bottom depths of 3, 4, and 5 km are considered. The initial temperatures at the bottom of the reservoir are 127.0, 164.5, and 202.0oC for the three depths, respectively, assuming a mean annual surface temperature of 14.5oC. Using an RZ model allows for fine mesh refinement, particularly around the injectors and producers to better model fluid pressure gradients close to the wells.
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Fig. 2. Multi-ring, horizontal-well configuration used in the multi-fluid geothermal energy system cases presented in this paper. All wells are located at the bottom of the permeable reservoir formation. Due to buoyancy, supercritical CO2 migrates to the top of the permeable reservoir to form a cushion gas cap that increases the pressure-storage capacity of the system. Together with the impermeable caprock and bedrock, the hydraulic divide forms a “container” to store CO2 and pressure, which enables bulk energy storage. The hydraulic trough is, effectively, at the base of the “spillway” of this energy storage system. For the multi-fluid geo-energy system cases of thermal energy storage, the radial distance to the outer ring of brine producers (Ring 4) is 2.75 km.
In this study, we use NUFT to model pure supercritical CO2 injection. We use the reservoir model results to determine brine-based, Organic Rankine Cycle (ORC) binary-power generation, using the GETEM code [44]. Geothermal energy is extracted from produced CO2 at the surface using a direct-cycle power system, in which the produced CO2 is itself sent through a turbine rather than a binary-cycle power system. For CO2 as a working fluid, direct-power systems offer much greater energy conversion efficiency than binary systems [11,12] because the supercritical fluids generate a substantial usable pressure difference between the hot production wellhead and the cold injection wellhead (across the turbine), whereas Joule-Thompson cooling reduces produced fluid temperature. For this study, we consider initial CO2 injection rates ranging from 15 to 240 kg/sec. For all cases, the maximum CO2 injection rate is specified to be no greater than twice the initial rate. For most cases, the CO2 injection rate gradually increases to the maximum rate, which allows produced CO2 to be recirculated and to extract more heat from the reservoir. All produced CO2 is reinjected into the second ring of horizontal wells and all produced brine is reinjected into the third ring of horizontal wells (Fig. 2). Power is generated from produced CO2 in a direct system and from brine in an indirect (i.e., binary ORC) system. It is assumed that the exit temperature of the brine from the binary-cycle power plant is cooled so that it enters the reservoir at a temperature of 65oC. After the CO2 has passed through the direct-cycle turbine, the CO2 is assumed to have cooled to such a temperature at the injection well head that after compression in the injection well, the temperature of the CO2 entering the reservoir at depth is 25oC. The CO2 that is delivered from the fossil-energy system source is also assumed to enter the reservoir at 25oC. For the multifluid geo-energy system cases of thermal energy storage (TES), the brine is heated by a surface thermal resource (e.g., nuclear or CSP plant) so that it enters the reservoir at a temperature of 300oC. For the TES cases, the brine reinjection rates are the same as those for the corresponding multi-fluid geothermal energy system case. For the TES cases it was necessary to decrease the spacing between the ring of brine injectors and the outer producer ring from 2 km to only 250 m (Fig. 2) to reduce the time required for the heated brine to reach the outer ring of brine producers. 3. Results The results of this study are presented in four parts. In Section 3.1, we assume constant heat withdrawal rate from the reservoir and synchronous parasitic loading of the power required to pump brine to drive fluid recirculation (which is typical for geothermal power systems), when analyzing the dependence of power generation on CO2 injection rate and geothermal resource depth/temperature. In Section 3.2, we briefly consider how time shifting the parasitic load of brine pumping can achieve diurnal bulk energy storage (BES). In Section 3.3, we briefly consider how a multi-fluid geothermal system can be utilized to achieve diurnal thermal energy storage (TES). In Section 3.4, we examine geologic CO2 storage capacity and the value of CO2 to electric power generation and energy storage.
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3.1. Power Generation with Synchronous Parasitic Loading at a Constant Heat Withdrawal Rate As discussed in detail in other studies [2,3,4,11,12], net power (Fig. 3b) is influenced by several factors: (1) thermal decline (Fig. 3d), (2) parasitic load, which is dominated by brine pumping (Fig. 3c) and how that is influenced by reservoir overpressure (Fig. 3e), and the influence of (3) geothermal resource depth and temperature. The first two factors can be controlled by reservoir management, including the spacing between the injectors and producers and the initial CO2 injection rate. Wider spacing between the injectors and producers delays thermal decline; however, it also increases the overpressure at the injectors required to drive brine to the producers. For our system we found that 2-km spacing between the ring of brine injectors and the outer ring of brine producers (Rings 3 and 4 in Fig. 2) was a reasonable compromise between delaying thermal breakthrough, while limiting overpressure. Gross power (Fig. 3a) strongly increases with geothermal resource depth/temperature. It also increases with CO2 injection rate because CO2 displaces and drives brine towards the inner ring of producers (Ring 2 in Fig. 2), which frees up make-up brine for reinjection in the third ring of wells. Injection of CO2 also creates a large “topographic high” in pressure, allowing overpressured brine to be injected in the third ring of wells uphill from the downhill outer ring of brine producers (Fig. 2). The magnitude of this topographic high increases with CO2 injection rate; hence, brine production at the outer producer ring increases with CO2 injection rate. Gross power increases with initial CO2 injection rate for initial CO2 injection rates < 120 kg/sec and levels out for CO2 injection rates > 120 kg/sec. This change in slope is caused by CO2 breakthrough at the inner ring of producers, with the additional CO2 being entirely produced and recirculated, rather than being added to net storage (Fig. 3g) and causing any further increase in overpressure (Fig. 3e). The contribution of power generated by CO2 production to total gross power is relatively small (Fig. 3h) in general. The contribution of CO2 to gross power increases with CO2 injection rate. For the cases considered in this study, the primary benefit of CO2 injection is to drive efficient production of formation brine for brine-based power generation. 3.2. Diurnal Bulk Energy Storage (BES) For BES, we categorize geothermal energy system operations into two time periods. 1. Recharge period: when the parasitic load of brine pumping (the major parasitic load) is entirely imposed. During this period, the heat withdrawal rate from the reservoir can also be reduced to achieve negative net power generation, which corresponds to taking (storing) energy from the electricity grid. 2. Discharge period: when only the minor parasitic loads (e.g., injecting the recirculating CO2) are imposed. During this period, net power is nearly equal to gross power and energy that was stored during the recharge period is returned to the electricity grid. The net power ratio is defined to be net power during the discharge period, divided by constant (or average) net power that would occur with synchronous parasitic loading and constant heat withdrawal rate. We consider a diurnal BES cycle consisting of a 6-hour recharge period and an 18-hour discharge period. Two specific cases are included: (1) BES case A, which time-shifts brine parasitic loading for a 6/18-hour recharge/discharge cycle and (2) BES case B, which is almost the same as case A, but reduces heat withdrawal rate by 50% during recharge (Fig. 4). In all but one case (Fig. 4c); BES case A yields a negative net power during recharge, corresponding to taking (storing) energy from the grid. When variable heat withdrawal is added, all six cases yield negative net power during recharge. For the 3-km deep reservoir, the net power ratio is 2.0 and 2.3 for BES cases A and B, respectively (Fig. 4a); thus, the power available to the grid during high demand can double as a result of diurnal BES. The added benefit of multi-fluid BES can enhance the financial viability of what may otherwise be considered a marginal geothermal resource, while simultaneously promoting implementation of other, intermittently available, renewable energy sources, such as wind and solar. 3.3. Diurnal Thermal Energy Storage (TES) Before examining the details of diurnal TES (Fig. 5), we consider how injecting pre-heated brine affects geothermal resource utilization in general (Fig. 3). As found elsewhere [4], injecting pre-heated brine reduces fluid viscosity around the injection well, which reduces the overpressure required to inject brine. This reduces the parasitic load of brine pumping, which, in turn, increases net power (Fig. 3b). Reducing the spacing between the brine injectors and producers by a factor of eight (from 2 km to 250 m) also has a major effect on reducing overpressure (Fig. 3e) and parasitic load (Fig. 3c).
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Fig. 3. Geothermal system performance for 30 years of operation is plotted for three reservoir depths as a function of initial CO2 injection rate, including (a) average gross power, (b) average net power, (c) average parasitic load, (d) production temperature of the outer brine producers at 30 years, (e) peak overpressure at the brine injectors, (f) average unit value of net stored CO2, (g) net CO2 storage, and (h) percentage of gross power generated by CO2 production. Also plotted is the equivalent geothermal system performance for thermal energy storage (TES) at a reservoir depth of 3 km. The unit value of CO2 is based on power sales at $100/MWh.
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Fig. 4. An example of diurnal bulk energy storage (BES) is shown by plotting the time series of net power over a 48-hour period that occurs 10 years into production for an initial CO2 injection rate of 120 kg/sec (where the maximum CO2 injection rate is constrained to be 240 kg/sec) and for reservoir depths of (a) 3 km, (b) 4 km, and (c) 5 km. Time series are plotted for three cases: (1) no BES, with synchronous parasitic loading of brine pumping and constant heat withdrawal rate; (2) BES case A, which time-shifts the brine parasitic load to a 6-hour recharge period every 24 hours; and (3) BES case B, which reduces heat withdrawal by 50% and time-shifts the brine parasitic pumping load during a 6-hour period every 24 hours. The BES benefit of time-shifting the parasitic load is relatively greater for shallow geothermal resources because parasitic load is relatively greater than it is for deeper geothermal resources.
Fig. 5. An example of diurnal thermal energy storage (TES) is shown by plotting the time series of net power delivered to the electricity grid (net power delivery rate) and the equivalent storage rate over a 48-hour period that occurs (a) 5 years into production and (b) 10 years into production for an initial CO2 injection rate of 120 kg/sec (where the maximum CO2 injection rate is constrained to be 240 kg/sec) and for reservoir depth of 3 km. The equivalent storage rate is the net power that could have been delivered to the grid if the associated thermal energy were not injected and stored in the reservoir. The round-trip efficiency is 89.3% 5 years into production, increasing to 96.4% at 10 years. In contrast to most geothermal power systems, the efficiency of TES systems improves with time.
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Injecting brine pre-heated by a surface thermal resource to 300oC into a relatively shallow (3 km deep) reservoir greatly increases the utilization of that geothermal resource. For an initial CO2 injection rate of 120 kg/sec, the net power averaged over 30 years is increased nearly tenfold from 54.8 MWe to 515.3 MWe (Fig. 3b). Because the radius of the outer ring of producers has been reduced from 4.5 km to just 2.75 km, the number of wells required for the TES case will be much less than for the corresponding geothermal energy case. This reduces the circumference of the outer ring of brine production by nearly 40%. Hence, a smaller well infrastructure could support a much larger production rate, with a substantial increase in the leveraging of wells costs. For this preliminary study of TES, we assume the same brine reinjection rates as for the corresponding geothermal energy case. Consequently, the overpressure at the brine injectors required to maintain that brine production rate is quite small. For an initial CO2 injection rate of 120 kg/sec, peak overpressure is 14.4 MPa at the brine producers for the geothermal case, while it is only 1.7 MPa for the corresponding TES case (Fig. 3e), nearly a tenfold reduction. Accordingly, the average parasitic load (Fig. 3c) is reduced by a factor of 40 (from 46.8% to only 1.2%). It should thus be possible to increase brine production rate by increasing the overpressure at the brine injectors without it being a concern for induced seismicity [45]. This could substantially increase the average net power for the TES case above that shown in Fig. 3b. While Fig. 3 shows the potential for TES averaged over a 30-year production period, there are many specific TES scenarios that could be implemented for this general case. We consider a simple diurnal TES case where heat withdrawal is held constant (with net power fluctuating only slightly), while pre-heated brine is periodically injected during a 12-hour recharge period every 24-hours (Fig. 5). Five years into production, the average net power is 679.8 MWe; the parasitic load for fluid recirculation is 1.5%; and the brine production temperature is 270.2oC, resulting in a round-trip efficiency of 89.3%. Generating an average net power of 679.8 MWe requires injecting 300 oC brine at an equivalent storage rate of 1522.5 MWe during the 12-hour recharge period (Fig. 5a). The equivalent storage rate is defined to be the net power that could have been directly delivered to the electricity grid if the associated thermal energy were not injected and stored in the reservoir. Ten years into production, the average net power is 619.3 MWe; the parasitic load for fluid recirculation is 1.1%; and the brine production temperature is 290.0oC, resulting in a round-trip efficiency of 96.4%. To generate an average net power of 619.3 MWe, the equivalent storage rate is 1284.4 MWe (Fig. 5b). Because the parasitic load of brine pumping is only imposed during the recharge period, the net power to the grid fluctuates slightly (2 to 3%). At 5 years, the net power delivered to the grid is 669.2 MWe during the 12-hour recharge period and is 690.3 MWe during the 12-hour discharge period (Fig. 5a). At 10 years, the net power delivered to the grid periodically fluctuates between 612.6 and 625.9 MWe (Fig. 3b). Because CO2 is continuously injected at a constant rate, the very small parasitic load of injecting CO2 is imposed continuously. With the heat withdrawal rate being held constant, the geothermal power plant can continuously run at full capacity, all while the TES system accommodates a periodic surface thermal resource, such as concentrating solar power. TES could also be integrated with a base-load thermal power plant (e.g., nuclear), allowing it to switch between power-delivery and thermal-energy-storage modes. This TES system could also be run with a variable heat withdrawal rate that could further accommodate mismatches between supply and demand on electricity grids at a range of timescales (minutes to hours, to perhaps weeks or longer). 3.4. Geologic CO2 Storage and the Value of CO2 to Power Generation and Energy Storage As discussed earlier, net CO2 storage increases with initial CO2 injection rate (Fig. 3g), up to an initial CO2 injection rate of 120 kg/sec. Above that rate, CO2 breakthrough at the inner producers results in all of the additional CO2 being produced and recirculated, rather than adding to net CO 2 storage. Net CO2 storage increases with reservoir depth/temperature (Fig. 3g) because the viscosity of brine decreases more quickly with increasing temperature than does the viscosity of CO2. Hence, with increasing temperature, breakthrough of CO2 at the inner producers is increasingly delayed, resulting in greater net storage of CO2. The TES case is able to store more CO2 due to the very small overpressure at the ring of brine reinjectors. With the much smaller overpressure, the hydraulic divide is not able to fully contain the CO2 plume, which is able to break through the divide and laterally spread. This situation could be controlled by monitoring the outward migration of the CO2 plume, and reducing the CO2 injection rate so as to mitigate this outward migration. Because gross power (Fig. 3a) and net power (Fig. 3b) are not increased for initial CO2 injection rates > 120 kg/sec, it may not be economically justifiable to inject CO2 at such a high rate.
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The unit value of CO2 (Fig. 3f) is based on power sales at $100/MWh and net CO2 storage over a 30-year project life. Unit CO2 value increases with reservoir depth/temperature. It also increases with decreasing initial CO 2 injection rate. For initial CO2 injection rates > 120 kg/sec, the net CO2 value is insensitive to CO2 injection rate for the geothermal energy cases. For initial CO2 injection rates < 165 kg/sec, the TES case generates a higher net CO2 value than any of the geothermal energy cases. As noted earlier, because net power is not increased for initial CO 2 injection rates > 120 kg/sec, it may not be economically justifiable to inject CO2 at such a high rate. The TES case with an initial CO2 injection rate of 120 kg/sec appears to be an attractive option because it generates a unit CO2 value of $100/MT, while storing 134.4 MT of CO2 (an average of 4.5 MT/yr) and enabling increased penetration of variable renewable energy sources, without curtailments to low-carbon base-load power. 3.5. Future Work This study provides first-order insights into the potential viability of multi-fluid geothermal energy systems and hybrid multi-fluid geo-energy systems for a relatively simple generic, layered reservoir system with a single homogeneous, isotropic value of reservoir permeability and a single value of reservoir thickness. Future work should address the influence of permeability heterogeneity and anisotropy, including reservoir compartmentalization, constrained by data from specific geologic settings. Future work should also address the economics of power generation, ancillary services, as well as diurnal and seasonal BES and TES. Such work should consider actual electric-grid supply/demand histories, examining how parasitic loads can be modulated, and fluid and heat withdrawal rates varied, in response to grid imbalances for a range of timescales (seconds to weeks or longer). This work should include assessments of capital and operating costs in determining the overall economic viability of the multi-fluid geothermal and hybrid multi-fluid geo-energy systems to providing dispatchable power and energy storage. Future work should also consider how TES might be deployed in depleted geothermal or hydrocarbon reservoirs, as well as in saline aquifers amenable to GCS that fall outside of the realm of typical geothermal resources. 4. Conclusions We present an approach that synergistically combines geologic CO2 storage with geothermal resources and surface (solar, nuclear, fossil) thermal resources to enable efficient dispatchable renewable electricity. Injected CO 2 can function as an efficient working fluid for heat extraction and power conversion; it also functions as a cushion gas, enabling large pressure-storage capacity. By using an efficient arrangement of concentric rings of wells, it is possible to manage the injection of CO2, the reinjection of produced brine, and the production of working fluids (CO2 and brine) to store pressure (bulk energy) and generate artesian flow of brine. The option exists for brine to be heated prior to reinjection, using surface thermal resources (e.g., concentrating solar power) to provide subsurface thermal energy storage. Such storage can take excess power from the grid and excess/waste thermal energy, and dispatch that energy when it is demanded, enabling increased penetration of variable renewables. During periods of low demand, our bulk energy storage approach can take electricity from the grid to power the parasitic load for brine pumping, which increases the power available to the grid during periods of high demand. The added benefit of bulk energy storage can enhance the financial viability of geothermal resources, including those that may otherwise be economically marginal, while it promotes implementation of other, intermittently available, renewable energy sources, such as wind and solar, which are in need of efficient, large-scale energy storage. Our thermal energy storage approach can increase the value and utilization of geothermal resources, by increasing net power, which results from increasing gross power, while decreasing the parasitic load associated with fluid recirculation. In contrast to geothermal power systems limited by thermal decline, the efficiency of this thermal energy storage approach improves with time. As an example of diurnal thermal energy storage, we find that round-trip efficiency improves from 89.3% after 5 years of operation to 96.4% after 10 years. Our thermal energy storage approach may also be useful in other geologic settings that are amenable to geologic CO2 storage but that are not typically considered geothermal resources, such as depleted oil and gas reservoirs. Finally, the revenues generated by geothermal power and energy-storage applications may justify CO2 capture costs, increasing the likelihood of deployment of geologic CO2 storage in CO2 capture, utilization, and storage (CCUS) systems.
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Acknowledgements This study was funded by the U.S. Department of Energy (DOE) Geothermal Technologies Office (GTO) under grant number DE-FOA-0000336, managed by Greg Stillman, Elisabet Metcalfe, and Lauren Boyd, and a U.S. National Science Foundation (NSF) Sustainable Energy Pathways (SEP) program 1230691. Martin O. Saar also thanks the George and Orpha Gibson endowment for its generous support of the Hydrogeology and Geofluids Research Group in the Department of Earth Sciences, College of Science and Engineering, University of Minnesota. This work was performed under the auspices of the USDOE by Lawrence Livermore National Laboratory (LLNL) under DOE contract DE-AC52-07NA27344. Disclaimer Drs. Randolph and Saar have a significant financial and business interest, in TerraCOH, Inc., a company that may commercially benefit from the results of this research. The University of Minnesota has the right to receive royalty income under the terms of a license agreement with TerraCOH, Inc. These relationships have been reviewed and managed by the University of Minnesota in accordance with its conflict of interest policies. References [1] Buscheck TA, Chen M, Hao Y, Bielicki JM, Randolph JB, Sun Y, Choi H. Multi-fluid geothermal energy production and storage in stratigraphic reservoirs, Proceedings for the Geothermal Resources Council 37th Annual Meeting; 2013. Las Vegas, NV. [2] Buscheck TA, Bielicki JM, Randolph JB, Chen M, Hao Y, Edmunds TA, Adams B, Sun Y. Multi-fluid geothermal energy systems in stratigraphic reservoirs: Using brine, N2, and CO2 for dispatchable renewable power generation and bulk energy storage, Proceedings of the 39th Workshop on Geothermal Reservoir Engineering; 2014. Stanford University, Palo Alto, CA. [3] Buscheck TA, Bielicki JM, Chen M, Sun Y, Hao Y, Edmunds TA, Saar, MO, Randolph JB. Multi-fluid sedimentary geothermal energy systems for dispatchable renewable electricity, Proceedings for the World Geothermal Congress; 2015. 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[21] NREL: Geothermal power generation: Current and planned nameplate capacity (MW) by state, Retrieved from National Renewable Energy Laboratory (NREL); 2014. http://www.nrel.gov/gis/geothermal.html. [22] Global CCS Institute. The Global Status of CCS 2013: Summary Report; 2013. [23] IPCC: IPCC special report on carbon dioxide capture and storage. Prepared by working group III of the Intergovernmental Panel on Climate Change (IPCC). (Metz B, Davidson O, de Coninck HC, Loos M, and Meyer LA, Eds.); 2005. Cambridge University Press: New York. [24] Edmunds TA, Sotorrio P, Bielicki JM, Buscheck TA. Geothermal power for integration of intermittent generation, Proceedings for the Geothermal Resources Council 38th Annual Meeting; 2014. Las Vegas NV. [25] Forsberg C. Hybrid systems to address seasonal mismatches between electricity production and demand in nuclear renewable electrical grids, Energy Policy; 2013. 62, p. 333-341. [26] NETL. The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition (Atlas IV), U.S. DOE National Energy Technology Laboratory, Office of Fossil Energy; 2012. [27] Tian Y, Zhao CY. A review of solar collectors and thermal energy storage in solar thermal applications, Applied Energy; 2013. 104, p. 538-553. [28] Nitao JJ. Reference manual for the NUFT flow and transport code, version 3.0; 1998. Lawrence Livermore National Laboratory, UCRLMA-130651-REV-1, Livermore, CA. [29] Hao Y, Sun Y, Nitao JJ. Overview of NUFT: A versatile numerical model for simulating flow and reactive transport in porous media, Chapter 9 in Groundwater Reactive Transport Models; 2012, p. 213-240. [30] Buscheck TA, Sun Y, Hao Y, Wolery TJ, Bourcier WL, Tompson AFB, Jones ED, Friedmann SJ, Aines RD. Combining brine extraction, desalination, and residual-brine reinjection with CO2 storage in saline formations: Implications for pressure management, capacity, and risk mitigation. Energy Procedia; 2011. 4, p. 4283-4290. [31] Buscheck TA, Sun Y, Chen M, Hao Y, Wolery TJ, Bourcier WL, Court B, Celia MA, Friedmann SJ, Aines RD. Active CO2 reservoir management for carbon storage: Analysis of operational strategies to relieve pressure buildup and improve injectivity. International Journal of Greenhouse Gas Control; 2012. 6, p. 230-245. [32] Sun Y, Tong C, Trainor-Guitton WJ, Lu C, Mansoor K, Carroll SA. Global sampling for integrating physics-specific subsystems and quantifying uncertainties of CO2 geological sequestration. International Journal of Greenhouse Gas Control; 2013. 12, p. 108-123. [33] Trainor-Guitton WJ, Ramirez A, Yang X, Mansoor K, Sun Y, Carroll SA. Value of information methodology for assessing the ability of electrical resistivity to detect CO2/brine leakage into a shallow aquifer. International Journal of Greenhouse Gas Control; 2013. 18, p103-113. [34] Buscheck TA, White JA, Chen M, Sun Y, Hao Y, Aines RD, Bourcier WL, Bielicki JM. Pre-injection brine production for managing pressure in compartmentalized CO2 storage reservoirs, Proceedings for the International Conference on Greenhouse Gas Technologies (GHGT-12); 2014. Austin, TX. [35] Buscheck TA, Elliot TR, Celia MA, Chen M, Sun Y, Hao Y, Lu C, Wolery TJ, Aines RD. Integrated geothermal-CO2 reservoir systems: Reducing carbon intensity through sustainable energy production and secure CO2 storage, Energy Procedia 37; 2013. P. 6587-6594. [36] Buscheck T A , Chen M , Lu C, Sun Y, Hao Y, Celia MA, Elliot TR, Choi H, Bielicki JM. Analysis of operational strategies for utilizing CO2 for geothermal energy production, Proceedings of the 38th Workshop on Geothermal Reservoir Engineering; 2013. Stanford University, Palo Alto, CA. [37] ASME. ASME Steam Tables Compact Edition, ASME; 200. Three Park Avenue, New York, NY, USA. [38] Span R, Wagner W. A new equation of state for carbon dioxide covering the fluid region from the triple-point temperature to 1100K at pressures up to 800 MPa. Journal of Physical and Chemical Reference Data; 1996. 25, p. 1509-1596. [39] Fenghour A, Wakeham WA, Vesovic V. The viscosity of carbon dioxide. Journal of Physical Chemical Reference Data; 1998. 27 (1), p. 31-44. [40] Birkholzer JT, Zhou Q, Tsang C-F. Large-scale impact of CO2 storage in deep saline aquifers: A sensitivity study on pressure response in stratified systems. International Journal of Greenhouse Gas Control; 2009. 3, p. 181-194. [41] Birkholzer JT and Zhou Q. Basin-scale hydrogeologic impacts of CO2 storage: Capacity and regulatory implications. International Journal of Greenhouse Gas Control; 2009. 3, p. 745-756. [42] Zhou Q, Birkholzer JT, Tsang C-F, Rutqvist J. A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations. International Journal of Greenhouse Gas Control; 2008. 2, p. 626-639. 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ScienceDirect Energy Procedia 63 (2014) 7619 – 7630
GHGT-12
Integrating CO2 Storage with Geothermal Resources for Dispatchable Renewable Electricity Thomas A. Buschecka, Jeffrey M. Bielickib,c, Mingjie Chena, Yunwei Suna, Yue Haoa, Thomas A. Edmundsa, Martin O. Saard,e, and Jimmy B. Randolphd a Lawrence Livermore National Laboratory, Livermore, CA 94550, USA Department of Civil, Environmental, & Geodetic Engineering, cJohn Glenn School of Public Affairs, The Ohio State University, Columbus, OH 43210, USA d Department of Earth Sciences, University of Minnesota, Minneapolis, MN 55444, USA e Geothermal Energy and Geofluids Group, Department of Earth Sciences, ETH-Zürich, Zürich, CH
b
Abstract We present an approach that uses the huge fluid and thermal storage capacity of the subsurface, together with geologic CO2 storage, to harvest, store, and dispatch energy from subsurface (geothermal) and surface (solar, nuclear, fossil) thermal resources, as well as energy from electrical grids. Captured CO2 is injected into saline aquifers to store pressure, generate artesian flow of brine, and provide an additional working fluid for efficient heat extraction and power conversion. Concentric rings of injection and production wells are used to create a hydraulic divide to store pressure, CO2, and thermal energy. Such storage can take excess power from the grid and excess/waste thermal energy, and dispatch that energy when it is demanded, enabling increased penetration of variable renewables. Stored CO2 functions as a cushion gas to provide enormous pressure-storage capacity and displaces large quantities of brine, which can be desalinated and/or treated for a variety of beneficial uses. Geothermal power and energy-storage applications may generate enough revenues to justify CO2 capture costs. © 2014 2013The TheAuthors. Authors. Published by Elsevier Ltd. is an open access article under the CC BY-NC-ND license © Published by Elsevier Ltd. This (http://creativecommons.org/licenses/by-nc-nd/3.0/). Selection and peer-review under responsibility of GHGT. Peer-review under responsibility of the Organizing Committee of GHGT-12 Keywords: Geothermal energy; bulk energy storage; thermal energy storage; parasitic load; geologic CO2 storage; CO2 utilization; brine utilization
1. Introduction Climate change mitigation requires a range of measures to reduce atmospheric CO2 emissions—the most important being increased reliance on electricity generated from renewable and low-carbon energy resources, and reduced CO2 intensity of fossil energy use. Renewable energy technologies must be matched with bulk and thermal energy storage in order to reach their full potential, but there are presently no energy storage technologies that are economically feasible and widely deployable. Only the subsurface, with its vast volumes and high pressures, has the capacity to "firm" renewables with carbon-neutral (or carbon-negative) storage. *Corresponding author. Tel: +1-925-423-9390; fax: +1-925-423-0153 E-mail address: [email protected]
1876-6102 © 2014 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/3.0/). Peer-review under responsibility of the Organizing Committee of GHGT-12 doi:10.1016/j.egypro.2014.11.796
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Geologic CO2 storage (GCS) is a promising means of reducing CO2 intensity of fossil energy use, but the high cost of capturing CO2 requires valuable uses for CO2 to justify those costs. Our approach is unique: initial "charging" of the system requires permanently isolating large volumes of captured CO2 and thus creates a market for its disposal. Once charged, our system can take power from, and deliver power to, electricity grids with the opposite timing of current solar and wind energy technologies, mitigating issues associated with high penetration of these variable energy sources, including the possibility of curtailments to wind power deliveries during periods of high winds and low loads. Our approach involves multi-fluid geothermal energy systems [1,2,3,4,5], and their extension, which includes thermal energy storage, resulting in multi-fluid geo-energy systems [6], in which CO2 and/or N2 are injected into permeable sedimentary formations. This injection stores pressure, generates artesian flow of formation brine, and provides a cushion gas and supplemental working fluids for efficient fluid recirculation, heat extraction, and power conversion, as well as providing the option for bulk energy storage (BES) and thermal energy storage (TES). Here, we present geothermal energy, BES and TES applications that use CO2 as the supplemental working fluid/cushion gas. 1.1. CO2 Plume Geothermal (CPG) The use of supercritical CO2 as a working fluid in geothermal systems was first proposed for Engineered Geothermal Systems (EGS) in low-permeability, hot crystalline basement rocks [7,8]. For exploitation, CO2 EGS requires hydrofracturing or hydro-shearing tight formations to develop sufficient permeability for fluid recirculation [4]. Supercritical CO2 has multiple advantages compared to brine, including: x low kinematic viscosity, compared to brine, allowing for effective heat advection despite its relatively low heat capacity x high thermal expansibility, compared to brine, generating a much stronger thermosiphon effect through the injection well, the reservoir, and the production well These and other advantages of CO2 over brine can reduce or eliminate the need for pumps to drive recirculation of the underground working fluid through the reservoir [9,10,11]. CO2 Plume Geothermal (CPG) differs from employing CO2 EGS [7,8] because CPG extracts heat from sedimentary or stratigraphic reservoirs that have naturally high permeability and are much larger than the artificially generated EGS reservoirs [12,13,14,15,16,17]. Because sedimentary reservoirs are much larger than hydrothermal upflows, they have lower, more predictable, drilling risk than typically associated with geothermal reservoirs in hydrothermal upflows. Further, these large reservoirs can hold large amounts of CO2 that can take up the heat that is widely distributed throughout the reservoir resulting in a significant energy source, despite the relatively low temperatures (~100oC) of such fairly shallow (~3 km deep) reservoirs. Such stratigraphic reservoirs are common throughout the world [18] as they exist, for example, below approximately half of North America [19,20,21]. These reservoirs are also the target of GCS efforts [22] to reduce global climate change [23]. Coupling CPG with a GCS project creates a CO2 capture utilization and storage (CCUS) opportunity that can defray the cost of GCS by using CO2 as a resource to generate electricity. 1.2. Multi-Fluid Geothermal Energy and Hybrid Multi-Fluid Geo-Energy Systems The multi-fluid geothermal energy system approach [1,2,3,4] builds upon the CPG approach [1516] by taking advantage of the fact that CO2 injection creates reservoir overpressure and displaces formation brine that can be produced under artesian conditions. In addition to injecting CO2, this approach includes the option of injecting N2 separated from air into permeable formations (Fig. 1a) to augment and store pressure (bulk energy) and provide efficient working fluids, while adding operational flexibility [24]. Our approach shares some of the attributes of pumped storage hydro and its subsurface equivalent, underground pumped hydro storage [3]. An expansion of this approach, called multi-fluid geo-energy systems [6], can store and dispatch thermal energy generated by surface thermal resources, such as concentrating solar power (CSP) and base-load power plants (Fig. 1b). This expanded approach can be used to levelize the delivery of CSP and mitigate the variability of wind and solar power. Similar to a hybrid nuclear-renewable energy approach proposed by Forsberg [25], our approach may allow low-carbon, base-load power (e.g., nuclear) to operate at full thermal capacity, with excess thermal energy stored during periods of overgeneration being available as dispatchable power during periods of high demand. This storage can provide loadfollowing and peaking capacity and may allow utilities to retire less efficient, carbon-intensive power plants.
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Fig. 1. (a) Vertical cross section of a multi-fluid geothermal energy system [5,6] using only a subsurface geothermal energy resource, showing multiple rings of horizontal injection and production wells. Cooled brine and cushion gas exit the power plant to be injected into a permeable formation. The option exists for heat exchangers in the power plant to transfer heat from hot brine to supercritical CO2/N2 prior to sending those fluids through a Brayton Cycle turbine to boost power conversion efficiency. Pressurized cushion gas and brine inside the hydraulic divide provide bulk energy storage (BES). The outer ring of production wells function as a pressure sink, creating a hydraulic trough that laterally constrains overpressure (stippled shaded area). (b) Similar to (a) except that instead of cold brine, hot brine (heated by a surface thermal energy resource) is injected [6]. Pressurized cushion gas and brine provide BES and enable large-capacity, long-duration (seasonal) thermal energy storage. Hybrid multi-fluid geo-energy systems do not require a high-grade geothermal heat source. In this study, the only cushion gas we considered was CO 2. Although shown here with horizontal wells, this approach can also be deployed with vertical wells.
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Concentric rings of horizontal injection and production wells are arranged to create a hydraulic divide to store pressure, CO2, N2, and thermal energy (Figs. 1a and 1b). This storage offers the ability to take excess power from the grid along with excess/waste thermal energy, and to dispatch that energy when it is demanded. The system is pressurized and/or heated when power supply exceeds demand and depressurized when demand exceeds supply. Supercritical CO2 and N2 function as cushion gases to provide enormous pressure-storage capacity—similar to compressed air energy storage—and as working fluids for highly efficient power conversion in Brayton Cycle turbines. The injection of CO2 and N2 frees up large quantities of make-up brine, which can reduce the use of fresh water for power generation. Time-shifting the parasitic loads associated with pressurizing and injecting brine and N2 provides bulk energy storage over days to months. While similar to pumped hydroelectric storage, the round-trip efficiency is higher because it is accomplished by timeshifting a parasitic load that is already required for fluid recirculation. Further, continuous modulation of the parasitic loads can provide ancillary grid services (e.g., load-following). Our approach is designed to provide large-capacity, longduration thermal energy storage to address diurnal and seasonal variability of supply and demand on electricity grids. 1.3. Deployment Options Our approach is designed for locations where a permeable geologic formation (typically sedimentary rock) is overlain by a caprock that is impermeable enough to constrain the vertical migration of buoyant, pressurized CO2 and/or N2. Ideally, the permeable formation would also be underlain by an impermeable formation (bedrock) to help store pressure. Such geologic conditions exist over much of the contiguous United States [26]. Areas with a sufficient geothermal gradient are required where geothermal energy is the only thermal energy resource, but hybrid applications that combine subsurface and surface thermal energy resources can reduce the need for subsurface heat. One option for a hybrid, multi-fluid, geo-energy system could involve a nuclear power plant with a pressurized water reactor. These systems recirculate 300oC pressurized water. At night during minimum power demand, this water could be put through a heat exchanger to heat brine that is injected and stored in a subsurface reservoir (Fig. 1b). Such a configuration is similar to a high-grade geothermal resource, with the added advantage of being shallower than a typical geothermal reservoir. Further, hybrid operations that switch between power-delivery and thermal-energy-storage modes provide an economic justification for the plant to operate at full thermal capacity. Stored thermal energy can be used for peaking capacity or pre-heating high-temperature, CSP tower systems. Note that this hybrid example is also applicable to CSP parabolic-trough systems that recirculate pressurized water in the 300oC range [27]. 2. Modeling Approach We conduct reservoir analyses with the Nonisothermal Unsaturated Flow and Transport (NUFT) numerical simulator, which simulates multi-phase heat and mass flow and reactive transport in porous media [28,29]. NUFT has been used extensively in GCS reservoir studies [30,31,32,33,34] and for multi-fluid geothermal systems [1,2,3,4,35,36]. The values of pore and water compressibility are 4.5×10-10 Pa-1 and 3.5×10-10 Pa-1, respectively. Water density is determined by the ASME steam tables [37]. The two-phase flow of supercritical CO2 and water is simulated with the density and compressibility of supercritical CO2 determined by the correlation of Span and Wagner [38] and CO2 dynamic viscosity is given by the correlation of Fenghour et al. [39]. A generic system (Fig. 2) is modeled over the course of 30 years, consisting of a 125-m-thick reservoir with a permeability of 100 mD, bounded by low-permeability (caprock and bedrock) seal units each with a permeability of 0.001 mD. Hydrologic properties are similar to previous GCS [30,31,34,40,41,42] and multi-fluid geothermal studies [1,2,3,4,24,35,36,43]. Because conditions are assumed to be laterally homogeneous, we use a radially-symmetric (RZ) model. A geothermal gradient of 37.5oC/km and reservoir bottom depths of 3, 4, and 5 km are considered. The initial temperatures at the bottom of the reservoir are 127.0, 164.5, and 202.0oC for the three depths, respectively, assuming a mean annual surface temperature of 14.5oC. Using an RZ model allows for fine mesh refinement, particularly around the injectors and producers to better model fluid pressure gradients close to the wells.
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Fig. 2. Multi-ring, horizontal-well configuration used in the multi-fluid geothermal energy system cases presented in this paper. All wells are located at the bottom of the permeable reservoir formation. Due to buoyancy, supercritical CO2 migrates to the top of the permeable reservoir to form a cushion gas cap that increases the pressure-storage capacity of the system. Together with the impermeable caprock and bedrock, the hydraulic divide forms a “container” to store CO2 and pressure, which enables bulk energy storage. The hydraulic trough is, effectively, at the base of the “spillway” of this energy storage system. For the multi-fluid geo-energy system cases of thermal energy storage, the radial distance to the outer ring of brine producers (Ring 4) is 2.75 km.
In this study, we use NUFT to model pure supercritical CO2 injection. We use the reservoir model results to determine brine-based, Organic Rankine Cycle (ORC) binary-power generation, using the GETEM code [44]. Geothermal energy is extracted from produced CO2 at the surface using a direct-cycle power system, in which the produced CO2 is itself sent through a turbine rather than a binary-cycle power system. For CO2 as a working fluid, direct-power systems offer much greater energy conversion efficiency than binary systems [11,12] because the supercritical fluids generate a substantial usable pressure difference between the hot production wellhead and the cold injection wellhead (across the turbine), whereas Joule-Thompson cooling reduces produced fluid temperature. For this study, we consider initial CO2 injection rates ranging from 15 to 240 kg/sec. For all cases, the maximum CO2 injection rate is specified to be no greater than twice the initial rate. For most cases, the CO2 injection rate gradually increases to the maximum rate, which allows produced CO2 to be recirculated and to extract more heat from the reservoir. All produced CO2 is reinjected into the second ring of horizontal wells and all produced brine is reinjected into the third ring of horizontal wells (Fig. 2). Power is generated from produced CO2 in a direct system and from brine in an indirect (i.e., binary ORC) system. It is assumed that the exit temperature of the brine from the binary-cycle power plant is cooled so that it enters the reservoir at a temperature of 65oC. After the CO2 has passed through the direct-cycle turbine, the CO2 is assumed to have cooled to such a temperature at the injection well head that after compression in the injection well, the temperature of the CO2 entering the reservoir at depth is 25oC. The CO2 that is delivered from the fossil-energy system source is also assumed to enter the reservoir at 25oC. For the multifluid geo-energy system cases of thermal energy storage (TES), the brine is heated by a surface thermal resource (e.g., nuclear or CSP plant) so that it enters the reservoir at a temperature of 300oC. For the TES cases, the brine reinjection rates are the same as those for the corresponding multi-fluid geothermal energy system case. For the TES cases it was necessary to decrease the spacing between the ring of brine injectors and the outer producer ring from 2 km to only 250 m (Fig. 2) to reduce the time required for the heated brine to reach the outer ring of brine producers. 3. Results The results of this study are presented in four parts. In Section 3.1, we assume constant heat withdrawal rate from the reservoir and synchronous parasitic loading of the power required to pump brine to drive fluid recirculation (which is typical for geothermal power systems), when analyzing the dependence of power generation on CO2 injection rate and geothermal resource depth/temperature. In Section 3.2, we briefly consider how time shifting the parasitic load of brine pumping can achieve diurnal bulk energy storage (BES). In Section 3.3, we briefly consider how a multi-fluid geothermal system can be utilized to achieve diurnal thermal energy storage (TES). In Section 3.4, we examine geologic CO2 storage capacity and the value of CO2 to electric power generation and energy storage.
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3.1. Power Generation with Synchronous Parasitic Loading at a Constant Heat Withdrawal Rate As discussed in detail in other studies [2,3,4,11,12], net power (Fig. 3b) is influenced by several factors: (1) thermal decline (Fig. 3d), (2) parasitic load, which is dominated by brine pumping (Fig. 3c) and how that is influenced by reservoir overpressure (Fig. 3e), and the influence of (3) geothermal resource depth and temperature. The first two factors can be controlled by reservoir management, including the spacing between the injectors and producers and the initial CO2 injection rate. Wider spacing between the injectors and producers delays thermal decline; however, it also increases the overpressure at the injectors required to drive brine to the producers. For our system we found that 2-km spacing between the ring of brine injectors and the outer ring of brine producers (Rings 3 and 4 in Fig. 2) was a reasonable compromise between delaying thermal breakthrough, while limiting overpressure. Gross power (Fig. 3a) strongly increases with geothermal resource depth/temperature. It also increases with CO2 injection rate because CO2 displaces and drives brine towards the inner ring of producers (Ring 2 in Fig. 2), which frees up make-up brine for reinjection in the third ring of wells. Injection of CO2 also creates a large “topographic high” in pressure, allowing overpressured brine to be injected in the third ring of wells uphill from the downhill outer ring of brine producers (Fig. 2). The magnitude of this topographic high increases with CO2 injection rate; hence, brine production at the outer producer ring increases with CO2 injection rate. Gross power increases with initial CO2 injection rate for initial CO2 injection rates < 120 kg/sec and levels out for CO2 injection rates > 120 kg/sec. This change in slope is caused by CO2 breakthrough at the inner ring of producers, with the additional CO2 being entirely produced and recirculated, rather than being added to net storage (Fig. 3g) and causing any further increase in overpressure (Fig. 3e). The contribution of power generated by CO2 production to total gross power is relatively small (Fig. 3h) in general. The contribution of CO2 to gross power increases with CO2 injection rate. For the cases considered in this study, the primary benefit of CO2 injection is to drive efficient production of formation brine for brine-based power generation. 3.2. Diurnal Bulk Energy Storage (BES) For BES, we categorize geothermal energy system operations into two time periods. 1. Recharge period: when the parasitic load of brine pumping (the major parasitic load) is entirely imposed. During this period, the heat withdrawal rate from the reservoir can also be reduced to achieve negative net power generation, which corresponds to taking (storing) energy from the electricity grid. 2. Discharge period: when only the minor parasitic loads (e.g., injecting the recirculating CO2) are imposed. During this period, net power is nearly equal to gross power and energy that was stored during the recharge period is returned to the electricity grid. The net power ratio is defined to be net power during the discharge period, divided by constant (or average) net power that would occur with synchronous parasitic loading and constant heat withdrawal rate. We consider a diurnal BES cycle consisting of a 6-hour recharge period and an 18-hour discharge period. Two specific cases are included: (1) BES case A, which time-shifts brine parasitic loading for a 6/18-hour recharge/discharge cycle and (2) BES case B, which is almost the same as case A, but reduces heat withdrawal rate by 50% during recharge (Fig. 4). In all but one case (Fig. 4c); BES case A yields a negative net power during recharge, corresponding to taking (storing) energy from the grid. When variable heat withdrawal is added, all six cases yield negative net power during recharge. For the 3-km deep reservoir, the net power ratio is 2.0 and 2.3 for BES cases A and B, respectively (Fig. 4a); thus, the power available to the grid during high demand can double as a result of diurnal BES. The added benefit of multi-fluid BES can enhance the financial viability of what may otherwise be considered a marginal geothermal resource, while simultaneously promoting implementation of other, intermittently available, renewable energy sources, such as wind and solar. 3.3. Diurnal Thermal Energy Storage (TES) Before examining the details of diurnal TES (Fig. 5), we consider how injecting pre-heated brine affects geothermal resource utilization in general (Fig. 3). As found elsewhere [4], injecting pre-heated brine reduces fluid viscosity around the injection well, which reduces the overpressure required to inject brine. This reduces the parasitic load of brine pumping, which, in turn, increases net power (Fig. 3b). Reducing the spacing between the brine injectors and producers by a factor of eight (from 2 km to 250 m) also has a major effect on reducing overpressure (Fig. 3e) and parasitic load (Fig. 3c).
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Fig. 3. Geothermal system performance for 30 years of operation is plotted for three reservoir depths as a function of initial CO2 injection rate, including (a) average gross power, (b) average net power, (c) average parasitic load, (d) production temperature of the outer brine producers at 30 years, (e) peak overpressure at the brine injectors, (f) average unit value of net stored CO2, (g) net CO2 storage, and (h) percentage of gross power generated by CO2 production. Also plotted is the equivalent geothermal system performance for thermal energy storage (TES) at a reservoir depth of 3 km. The unit value of CO2 is based on power sales at $100/MWh.
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Fig. 4. An example of diurnal bulk energy storage (BES) is shown by plotting the time series of net power over a 48-hour period that occurs 10 years into production for an initial CO2 injection rate of 120 kg/sec (where the maximum CO2 injection rate is constrained to be 240 kg/sec) and for reservoir depths of (a) 3 km, (b) 4 km, and (c) 5 km. Time series are plotted for three cases: (1) no BES, with synchronous parasitic loading of brine pumping and constant heat withdrawal rate; (2) BES case A, which time-shifts the brine parasitic load to a 6-hour recharge period every 24 hours; and (3) BES case B, which reduces heat withdrawal by 50% and time-shifts the brine parasitic pumping load during a 6-hour period every 24 hours. The BES benefit of time-shifting the parasitic load is relatively greater for shallow geothermal resources because parasitic load is relatively greater than it is for deeper geothermal resources.
Fig. 5. An example of diurnal thermal energy storage (TES) is shown by plotting the time series of net power delivered to the electricity grid (net power delivery rate) and the equivalent storage rate over a 48-hour period that occurs (a) 5 years into production and (b) 10 years into production for an initial CO2 injection rate of 120 kg/sec (where the maximum CO2 injection rate is constrained to be 240 kg/sec) and for reservoir depth of 3 km. The equivalent storage rate is the net power that could have been delivered to the grid if the associated thermal energy were not injected and stored in the reservoir. The round-trip efficiency is 89.3% 5 years into production, increasing to 96.4% at 10 years. In contrast to most geothermal power systems, the efficiency of TES systems improves with time.
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Injecting brine pre-heated by a surface thermal resource to 300oC into a relatively shallow (3 km deep) reservoir greatly increases the utilization of that geothermal resource. For an initial CO2 injection rate of 120 kg/sec, the net power averaged over 30 years is increased nearly tenfold from 54.8 MWe to 515.3 MWe (Fig. 3b). Because the radius of the outer ring of producers has been reduced from 4.5 km to just 2.75 km, the number of wells required for the TES case will be much less than for the corresponding geothermal energy case. This reduces the circumference of the outer ring of brine production by nearly 40%. Hence, a smaller well infrastructure could support a much larger production rate, with a substantial increase in the leveraging of wells costs. For this preliminary study of TES, we assume the same brine reinjection rates as for the corresponding geothermal energy case. Consequently, the overpressure at the brine injectors required to maintain that brine production rate is quite small. For an initial CO2 injection rate of 120 kg/sec, peak overpressure is 14.4 MPa at the brine producers for the geothermal case, while it is only 1.7 MPa for the corresponding TES case (Fig. 3e), nearly a tenfold reduction. Accordingly, the average parasitic load (Fig. 3c) is reduced by a factor of 40 (from 46.8% to only 1.2%). It should thus be possible to increase brine production rate by increasing the overpressure at the brine injectors without it being a concern for induced seismicity [45]. This could substantially increase the average net power for the TES case above that shown in Fig. 3b. While Fig. 3 shows the potential for TES averaged over a 30-year production period, there are many specific TES scenarios that could be implemented for this general case. We consider a simple diurnal TES case where heat withdrawal is held constant (with net power fluctuating only slightly), while pre-heated brine is periodically injected during a 12-hour recharge period every 24-hours (Fig. 5). Five years into production, the average net power is 679.8 MWe; the parasitic load for fluid recirculation is 1.5%; and the brine production temperature is 270.2oC, resulting in a round-trip efficiency of 89.3%. Generating an average net power of 679.8 MWe requires injecting 300 oC brine at an equivalent storage rate of 1522.5 MWe during the 12-hour recharge period (Fig. 5a). The equivalent storage rate is defined to be the net power that could have been directly delivered to the electricity grid if the associated thermal energy were not injected and stored in the reservoir. Ten years into production, the average net power is 619.3 MWe; the parasitic load for fluid recirculation is 1.1%; and the brine production temperature is 290.0oC, resulting in a round-trip efficiency of 96.4%. To generate an average net power of 619.3 MWe, the equivalent storage rate is 1284.4 MWe (Fig. 5b). Because the parasitic load of brine pumping is only imposed during the recharge period, the net power to the grid fluctuates slightly (2 to 3%). At 5 years, the net power delivered to the grid is 669.2 MWe during the 12-hour recharge period and is 690.3 MWe during the 12-hour discharge period (Fig. 5a). At 10 years, the net power delivered to the grid periodically fluctuates between 612.6 and 625.9 MWe (Fig. 3b). Because CO2 is continuously injected at a constant rate, the very small parasitic load of injecting CO2 is imposed continuously. With the heat withdrawal rate being held constant, the geothermal power plant can continuously run at full capacity, all while the TES system accommodates a periodic surface thermal resource, such as concentrating solar power. TES could also be integrated with a base-load thermal power plant (e.g., nuclear), allowing it to switch between power-delivery and thermal-energy-storage modes. This TES system could also be run with a variable heat withdrawal rate that could further accommodate mismatches between supply and demand on electricity grids at a range of timescales (minutes to hours, to perhaps weeks or longer). 3.4. Geologic CO2 Storage and the Value of CO2 to Power Generation and Energy Storage As discussed earlier, net CO2 storage increases with initial CO2 injection rate (Fig. 3g), up to an initial CO2 injection rate of 120 kg/sec. Above that rate, CO2 breakthrough at the inner producers results in all of the additional CO2 being produced and recirculated, rather than adding to net CO 2 storage. Net CO2 storage increases with reservoir depth/temperature (Fig. 3g) because the viscosity of brine decreases more quickly with increasing temperature than does the viscosity of CO2. Hence, with increasing temperature, breakthrough of CO2 at the inner producers is increasingly delayed, resulting in greater net storage of CO2. The TES case is able to store more CO2 due to the very small overpressure at the ring of brine reinjectors. With the much smaller overpressure, the hydraulic divide is not able to fully contain the CO2 plume, which is able to break through the divide and laterally spread. This situation could be controlled by monitoring the outward migration of the CO2 plume, and reducing the CO2 injection rate so as to mitigate this outward migration. Because gross power (Fig. 3a) and net power (Fig. 3b) are not increased for initial CO2 injection rates > 120 kg/sec, it may not be economically justifiable to inject CO2 at such a high rate.
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The unit value of CO2 (Fig. 3f) is based on power sales at $100/MWh and net CO2 storage over a 30-year project life. Unit CO2 value increases with reservoir depth/temperature. It also increases with decreasing initial CO 2 injection rate. For initial CO2 injection rates > 120 kg/sec, the net CO2 value is insensitive to CO2 injection rate for the geothermal energy cases. For initial CO2 injection rates < 165 kg/sec, the TES case generates a higher net CO2 value than any of the geothermal energy cases. As noted earlier, because net power is not increased for initial CO 2 injection rates > 120 kg/sec, it may not be economically justifiable to inject CO2 at such a high rate. The TES case with an initial CO2 injection rate of 120 kg/sec appears to be an attractive option because it generates a unit CO2 value of $100/MT, while storing 134.4 MT of CO2 (an average of 4.5 MT/yr) and enabling increased penetration of variable renewable energy sources, without curtailments to low-carbon base-load power. 3.5. Future Work This study provides first-order insights into the potential viability of multi-fluid geothermal energy systems and hybrid multi-fluid geo-energy systems for a relatively simple generic, layered reservoir system with a single homogeneous, isotropic value of reservoir permeability and a single value of reservoir thickness. Future work should address the influence of permeability heterogeneity and anisotropy, including reservoir compartmentalization, constrained by data from specific geologic settings. Future work should also address the economics of power generation, ancillary services, as well as diurnal and seasonal BES and TES. Such work should consider actual electric-grid supply/demand histories, examining how parasitic loads can be modulated, and fluid and heat withdrawal rates varied, in response to grid imbalances for a range of timescales (seconds to weeks or longer). This work should include assessments of capital and operating costs in determining the overall economic viability of the multi-fluid geothermal and hybrid multi-fluid geo-energy systems to providing dispatchable power and energy storage. Future work should also consider how TES might be deployed in depleted geothermal or hydrocarbon reservoirs, as well as in saline aquifers amenable to GCS that fall outside of the realm of typical geothermal resources. 4. Conclusions We present an approach that synergistically combines geologic CO2 storage with geothermal resources and surface (solar, nuclear, fossil) thermal resources to enable efficient dispatchable renewable electricity. Injected CO 2 can function as an efficient working fluid for heat extraction and power conversion; it also functions as a cushion gas, enabling large pressure-storage capacity. By using an efficient arrangement of concentric rings of wells, it is possible to manage the injection of CO2, the reinjection of produced brine, and the production of working fluids (CO2 and brine) to store pressure (bulk energy) and generate artesian flow of brine. The option exists for brine to be heated prior to reinjection, using surface thermal resources (e.g., concentrating solar power) to provide subsurface thermal energy storage. Such storage can take excess power from the grid and excess/waste thermal energy, and dispatch that energy when it is demanded, enabling increased penetration of variable renewables. During periods of low demand, our bulk energy storage approach can take electricity from the grid to power the parasitic load for brine pumping, which increases the power available to the grid during periods of high demand. The added benefit of bulk energy storage can enhance the financial viability of geothermal resources, including those that may otherwise be economically marginal, while it promotes implementation of other, intermittently available, renewable energy sources, such as wind and solar, which are in need of efficient, large-scale energy storage. Our thermal energy storage approach can increase the value and utilization of geothermal resources, by increasing net power, which results from increasing gross power, while decreasing the parasitic load associated with fluid recirculation. In contrast to geothermal power systems limited by thermal decline, the efficiency of this thermal energy storage approach improves with time. As an example of diurnal thermal energy storage, we find that round-trip efficiency improves from 89.3% after 5 years of operation to 96.4% after 10 years. Our thermal energy storage approach may also be useful in other geologic settings that are amenable to geologic CO2 storage but that are not typically considered geothermal resources, such as depleted oil and gas reservoirs. Finally, the revenues generated by geothermal power and energy-storage applications may justify CO2 capture costs, increasing the likelihood of deployment of geologic CO2 storage in CO2 capture, utilization, and storage (CCUS) systems.
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Acknowledgements This study was funded by the U.S. Department of Energy (DOE) Geothermal Technologies Office (GTO) under grant number DE-FOA-0000336, managed by Greg Stillman, Elisabet Metcalfe, and Lauren Boyd, and a U.S. National Science Foundation (NSF) Sustainable Energy Pathways (SEP) program 1230691. Martin O. Saar also thanks the George and Orpha Gibson endowment for its generous support of the Hydrogeology and Geofluids Research Group in the Department of Earth Sciences, College of Science and Engineering, University of Minnesota. This work was performed under the auspices of the USDOE by Lawrence Livermore National Laboratory (LLNL) under DOE contract DE-AC52-07NA27344. Disclaimer Drs. Randolph and Saar have a significant financial and business interest, in TerraCOH, Inc., a company that may commercially benefit from the results of this research. The University of Minnesota has the right to receive royalty income under the terms of a license agreement with TerraCOH, Inc. 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