WO2019010059A1 - Systèmes et procédés d'énergie géothermique renouvelable multi-fluide - Google Patents

Systèmes et procédés d'énergie géothermique renouvelable multi-fluide Download PDF

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Publication number
WO2019010059A1
WO2019010059A1 PCT/US2018/040026 US2018040026W WO2019010059A1 WO 2019010059 A1 WO2019010059 A1 WO 2019010059A1 US 2018040026 W US2018040026 W US 2018040026W WO 2019010059 A1 WO2019010059 A1 WO 2019010059A1
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Prior art keywords
brine
working fluid
compressed
fluid
hot
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PCT/US2018/040026
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English (en)
Inventor
Thomas A. Buscheck
Original Assignee
Lawrence Livermore National Security, Llc
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Priority claimed from US15/642,045 external-priority patent/US10995972B2/en
Application filed by Lawrence Livermore National Security, Llc filed Critical Lawrence Livermore National Security, Llc
Publication of WO2019010059A1 publication Critical patent/WO2019010059A1/fr

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K25/00—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for
    • F01K25/08—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for using special vapours
    • F01K25/10—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for using special vapours the vapours being cold, e.g. ammonia, carbon dioxide, ether
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K3/00—Plants characterised by the use of steam or heat accumulators, or intermediate steam heaters, therein
    • F01K3/12—Plants characterised by the use of steam or heat accumulators, or intermediate steam heaters, therein having two or more accumulators
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F24T10/20—Geothermal collectors using underground water as working fluid; using working fluid injected directly into the ground, e.g. using injection wells and recovery wells
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F24T10/30—Geothermal collectors using underground reservoirs for accumulating working fluids or intermediate fluids
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K25/00—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for
    • F01K25/08—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for using special vapours
    • F01K25/10—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for using special vapours the vapours being cold, e.g. ammonia, carbon dioxide, ether
    • F01K25/103—Carbon dioxide
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K7/00—Steam engine plants characterised by the use of specific types of engine; Plants or engines characterised by their use of special steam systems, cycles or processes; Control means specially adapted for such systems, cycles or processes; Use of withdrawn or exhaust steam for feed-water heating
    • F01K7/16—Steam engine plants characterised by the use of specific types of engine; Plants or engines characterised by their use of special steam systems, cycles or processes; Control means specially adapted for such systems, cycles or processes; Use of withdrawn or exhaust steam for feed-water heating the engines being only of turbine type
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E10/00—Energy generation through renewable energy sources
    • Y02E10/10—Geothermal energy

Definitions

  • the present disclosure relates to multi-fluid, renewable geo-energy systems and methods, and more particularly to multi-fluid, geothermal and geo-energy systems and methods that employ one or more concentric rings of working fluid injection wells that at least partially circumscribe one or more production wells, and which employ a ring of brine production wells that at least partially circumscribe the working fluid injection wells, and which employ supplemental working fluids, in addition to native brine, and related methods to enhance the production of brine and supplemental fluid in a manner to increase the overall efficiency of a geothermal energy system, as well as systems and methods for synergistically harvesting, storing and dispatching renewable energy sources in renewable geo-energy systems to provide large-scale, diurnal-to- seasonal storage of both thermal and bulk energy and electrical-grid stabilizing, power- generation capacity.
  • Wind and solar are renewable energy sources with enormous resource potential.
  • energy sources are difficult to predict and are temporally variable, both diurnally and seasonally.
  • TES thermal energy storage
  • BES bulk energy storage
  • wind and solar energy technologies will require back-up, load-following, and peaking power sources, which often emit a significant quantity of CO2.
  • the temporal nature of the major renewable power sources primarily wind and solar, and in some instances, hydro
  • I0W-CO2 power sources e.g., nuclear power plants.
  • the present disclosure relates to a geo-energy production system for extracting thermal energy from a reservoir formation, and storing thermal waste heat or excess heat in a storage zone of the reservoir formation.
  • the system may comprise at least one compressed fluid injection well in communication with the storage zone for injecting an unheated, compressed working fluid into the storage zone, and at least one fluid injection well in communication with the storage zone for injecting a heated working fluid laden with thermal waste heat into the storage zone.
  • the storage zone may be located below a caprock layer of the reservoir formation and above a zone of native brine within the reservoir formation.
  • the storage zone may further be at least partially circumscribed by a hot brine storage zone of the reservoir formation.
  • the unheated, compressed working fluid further assists with a withdrawal of pressurized brine residing below and/or to the side of the storage zone.
  • At least one compressed fluid energy storage production well may be in communication with the storage zone for removing the unheated, compressed working fluid from the storage zone for use in power production.
  • the present disclosure relates to a method for geothermal energy storage using a geothermal reservoir formation, the geothermal reservoir formation including a storage reservoir of brine located below a caprock layer.
  • the method may comprise performing a thermal recharge operation by which brine is heated and pressurized, and then injected through a hot brine/cold-supplemental working fluid injection well extending into the storage reservoir.
  • the heated and pressurized brine increases a temperature of the storage reservoir to cause it to act as a high-grade geothermal resource.
  • An unheated supplemental working fluid recharge operation may be performed during which a supplemental working fluid is compressed and then injected through the hot brine/cold-supplemental working fluid injection well into the storage reservoir.
  • An energy discharge operation may be performed in which at least one of heated supplemental working fluid or a mixture of heated supplemental working fluid and brine is withdrawn through a hot brine/hot supplemental working fluid production well and fed into a fluid separator, an output of the fluid separator producing at least one of hot brine or hot supplemental working fluid.
  • Figure 1 is a high level plan view of one embodiment of a system in accordance with the present disclosure in which a plurality of rings of wells are used for forming a geothermal energy recovery and energy storage system;
  • Figure 2 is a high level side view of one example of how the wells shown in Figure 1 may be configured at different depths, and also how horizontal wells within a given ring may also be configured at different depths to tailor the system to the specific reservoir formation at which the system is being employed;
  • Figure 3 is a high level plan view of a single-fluid geothermal/STES or CTES reservoir system, where STE stands for solar thermal energy storage and CTES stands for chilled thermal energy storage;
  • Figure 4 is a high level side view of a single-fluid geothermal/STES or CTES reservoir system
  • Figure 5 is a high level flowchart illustrating a plurality of operations that may be implemented using the systems shown in Figures 1 -4;
  • Figure 6 illustrates another embodiment of the present disclosure which uses a portion of the reservoir formation itself to form a waste heat energy storage reservoir
  • Figure 7 illustrates a high level diagram of another embodiment of the present disclosure in which only two wells are needed for geothermal energy storage and production, those being a hot brine/cold-supplemental working fluid injection well and a hot brine/supplemental working fluid production well, and also illustrates a first or "thermal recharge stage" of operation;
  • Figure 8 shows the system of Figure 7 but with fluid flows indicated which occur during a supplemental fluid recharge stage of operation
  • Figure 9 shows the system of Figure 7 but with fluid flows indicated which occur during an energy discharge stage of operation.
  • the present disclosure involves a geo-energy system 10 that may be used as (1 ) a geothermal energy system to recover geothermal energy, (2) a thermal energy storage system to store and dispatch thermal energy, using above-ground sources such as solar thermal energy, or (3) a "hybrid" system that combines geothermal energy recovery with thermal energy storage.
  • the system 10 is located within a geothermal reservoir formation 1 1 . If used for thermal energy storage, such as solar thermal energy storage, the system 10 may be located in a subsurface reservoir formation 1 1 that is not considered to be a geothermal resource.
  • the system 10 may make use of both native brine and a supplemental working fluid to extract geothermal energy.
  • the supplemental working fluids may include supercritical CO2 and supercritical N2. However, it is especially effectively deployed when N2 is included as one of the constituents. Particular advantages of using N2 are that it can be separated from air at low cost, compared to that of captured CO2. Nitrogen is also non- corrosive and will not react with the reservoir formation 1 1 . The addition of N2 can improve the economics of C02-enabled geothermal energy production and mitigate operational issues associated with CO2. If a two-stage, nitrogen-enriched combustion process is used; the resulting flue gas can have low enough concentrations of oxidants to be a suitable, low-cost source of N2 and CO2. The systems and methods of the present disclosure can also utilize conventional flue gas to extract geothermal energy and methane from deep, unmineable coal seams.
  • the system 10 may be deployed with four rings of production and injection wells, which significantly enhances overall efficiency of the system 10.
  • the system 10 is deployed in a permeable geothermal reservoir formation 1 1 that is bounded above and below by an impermeable caprock and impermeable bedrock.
  • the impermeable caprock is important because it confines the vertical migration of the buoyant supplemental fluids (N2 and CO2).
  • the impermeable caprock and bedrock are important to system 10 because they help conserve pressure.
  • An inner ring 12 consists of a plurality of production wells 12a for extracting native brine from the reservoir formation 1 1 .
  • a second ring 14 consists of a plurality of supplemental working fluid injection wells 14a for injecting a supplemental working fluid into the reservoir formation 1 1 . More specifically, the second ring 14 of supplemental working fluid injection wells 14a may be used for injecting N2 and/or CO2 into the reservoir formation 1 1 .
  • a third ring 16 may consist of a plurality of brine re-injection wells 16a for re-injecting extracted native brine back into the reservoir formation 1 1 .
  • a fourth ring 18 of brine production wells 18a may be used to recover portions of the native brine reinjected via the third ring of re-injection wells 16a and to relieve overpressure in areas adjacent to the reservoir formation 1 1 .
  • the inner ring 12 of production wells 12a and the outer ring 18 of brine production wells 18a may be completed at various depths to provide better control of fluid and energy recovery for improved sweep efficiency, which reduces thermal drawdown and increases power generation and its sustainability.
  • the rings of injection wells 14a and 16a may also be completed at multiple depths, as will be described in greater detail herein, to provide better control of fluid and energy recovery. It will be appreciated that a greater or lesser plurality of wells may be included in each of the rings 12-18 than what is shown in Figure 1 .
  • the wells 12a-18a are shown in Figure 1 as being arranged generally concentrically, this is not absolutely critical to efficient operation of the system 10.
  • the individual wells of the fourth ring of wells 18a are preferably arranged to at least partially circumscribe the third (re- injection) wells 16a, which are in turn preferably arranged to at least partially circumscribe the second (injection) wells 14a, which are in turn preferably arranged to at least partially circumscribe the production wells 12a.
  • the multi-ring approach of the system 10 can take advantage of the fact that horizontal well drilling technology allows for precise directional control of the well orientation; hence it is realistic to create precisely curved injection and production intervals.
  • Another important reason for using a plurality of rings 12-18 is to conserve the pressure energy from the injection process and to minimize the loss of the supplemental working fluid.
  • the four-ring configuration (or variations of that configuration) creates a hydraulic divide, which is a distinct region of overpressure as shown in Figure 2.
  • the four rings 12-18 facilitate a range of pressure management strategies to spread out reservoir overpressure and thereby limit its magnitude, to thus significantly reduce or eliminate the possibility of induced seism icity and leakage of the supplemental working fluid.
  • the hydraulic divide ( Figure 2) that is created by the four- ring configuration of the system 10 shown in Figure 1 also allows the production wells 12a and 18a to be segregated into two groups, with the inner ring 12 of wells 12a transitioning from brine to supplemental working fluid production, and the outer ring of wells 18a only producing brine. Segregation of the production wells 12a and 18a in this fashion can help simplify well-field operations.
  • a high level side view illustrates that the wells within one or more of the rings 12-18 may be located at different depths in the reservoir formation 1 1 . More specifically, the brine re-injection wells 16a may be located at different depths relative to the caprock and bedrock that confine the reservoir formation 1 1 from above and below.
  • the benefits of the hydraulic divide are that it conserves pressure and supplemental working fluid and segregates the production wells into those that transition from brine to supplemental working fluid production and those that only produce brine.
  • Another important benefit of this configuration is that the large volume of the reservoir formation inside the hydraulic divide can be used to store large quantities of energy. Accordingly, the hydraulic divide is analogous to how a dam functions in storing energy for hydroelectricity generation.
  • a plurality of production wells 12a and 12b are also included for initially extracting native brine and eventually extracting the supplemental working fluid from a gas cap 1 1 a overlying the native brine within the reservoir formation 1 1 .
  • Wells 12b are used for extracting supplementing working fluid (N2 and/or CO2) from the gas cap 1 1 a.
  • the gas cap gradually expands vertically downward with time, driving native brine to production wells 12a, using a process called gravity-drainage double-displacement.
  • a significant benefit of CO2 or N2 injection is that it generates excess brine for re-injection through displacement; however, there is an additional, more subtle, and more profound benefit of this injection process. That benefit is in altering the pressure distribution within the reservoir. It has been determined that only a relatively small amount of CO2 or N2 is needed to create a "topographic high” in pressure (hydraulic divide in Figure 1 ), providing the opportunity to inject pressurized brine in the third ring of brine re-injection wells (16a) that sit on top of the hydraulic divide "uphill” from the "downhill” outer brine production wells (18a).
  • the supplemental fluid used to generate the topographic high in pressure distribution does not need to be CO2 or N2; rather, it may be make-up brine extracted from a separate reservoir.
  • the supplemental fluid may be make-up water from a separate source.
  • the make-up water may be effluent from a wastewater treatment plant.
  • Make-up brine can be excess brine that is replaced by supplemental-fluid (CO2 and/or N2) injection in a multi- fluid geothermal reservoir or it can be brine extracted for the purpose of pressure management in a geological CO2 storage (GCS) operation.
  • Make-up brine can also be the effluent from a reverse osmosis (RO) desalination plant.
  • RO reverse osmosis
  • the first family of embodiments of this disclosure replaces CO2 and/or N2 with brine or water as the supplemental fluid that is injected for the purpose of pressure augmentation.
  • this approach may be implemented with a concentric multi-ring system 200 ( Figure 3) similar to that of Figure 1 .
  • the system 200 of Figure 3 makes use of preferably at least three concentric well rings: (1 ) an inner ring 212 of brine production wells 212a, (2) a middle ring 216 of brine reinjection wells 216a, and (3) an outer ring 218 of brine production wells 218a.
  • brine reinjected in the middle ring 216 of wells 216a is "uphill" from the “downhill” inner and outer brine production wells 212a and 218a.
  • This pressure augmentation process can be thought of as the subsurface equivalent of "pumped- storage” hydroelectricity.
  • Subsurface pumped storage can drive large brine production rates while generating highly dispatchable power. Furthermore, this can be accomplished without requiring submersible pumps to lift brine up through the production wells 212a and 218a. Large centralized pumps located on the surface are expected to be even more efficient than submersible pumps. Surface-based pumps will not be exposed to harsh conditions that often occur in brine production wells and would not require the maintenance that can disrupt brine production and power output of geothermal energy systems.
  • Pumped storage is expected to be particularly valuable in hydrostatic reservoirs where temperatures are too hot (> 200°C) for submersible pumps to survive and operate. Where horizontal wells are used, pumped storage may drive flow rates much greater than the capacity of submersible pumps (typically 80 to 120 kg/sec), which would increase leveraging of well costs.
  • This family of embodiments is significant because it enables heat to be extracted from a geothermal resource without the added complexity associated with introducing a working fluid with significantly different thermophysical properties and chemistry from those of native brine, such as would be the case with supercritical CO2.
  • this approach allows a geothermal system to rely on existing geothermal technology and methods, when such technology and methods are used in connection with the energy-efficient, concentric-ring well configuration shown in Figure 3, and the possible use of horizontal wells.
  • Another family of embodiments of the present disclosure enables subsurface pressure storage, which in turn enables bulk energy storage (BES) and a grid-stabilizing power generation capability, such as load following.
  • BES bulk energy storage
  • a load-following power generation capability is becoming increasingly necessary with increasing penetration of intermittent renewables on power grids.
  • a significant fraction of gross power output is consumed with the parasitic load required to lift the brine up through the production wells 212a, which is typically achieved with submersible electrical pumps.
  • Some additional parasitic load typically also results because of the overpressure required to overcome frictional losses in the brine re-injection wells 216a.
  • the majority of the overall parasitic load is that associated with brine pumping, i.e., over pressurizing brine for re-injection into the brine re-injection wells (216a in Figures 3 and 4).
  • the second largest parasitic load is that associated with separating N2 from air and compressing N2 for injection into supplemental fluid injection wells (214a in Figures 1 and 2).
  • the parasitic load of brine pumping and/or N2 separation and pumping can be time-shifted to coincide with periods when power supply exceeds power demand, such as what may occur when there is an excess supply of intermittent renewable power on the electrical power grid.
  • parasitic-load time-shifting can be accomplished by temporarily storing brine in a surface reservoir (operation 202 in Figures 1 and 3), which is best done when power demand exceeds power supply on electricity grids. It should be noted that time-shifting the parasitic load of N2 separation and pumping does not require the temporary storage of N2 because N2 can be readily separated from air. Time-shifting both of these parasitic loads allows the net power output to be close to gross power output during the time that the parasitic loads are not imposed, which is useful when power demand exceeds supply. Time-shifting the parasitic load of brine pressurization and injection to periods when power supply exceeds demand on electricity grids can be accomplished using a wide range of operational combinations (Figure 5).
  • operation 205 is to produce brine (operation 205 in Figures 1 , 3, and 5) from a typically shallow reservoir and immediately pressurizing and reinjecting it into a separate (typically deeper and hotter reservoir) reservoir.
  • operation 205 allows brine that has been pre-heated in the shallower reservoir to be injected into (and to improve heat recovery from) the deeper reservoir. This will be discussed further in connection with operation 205 in Figure 5.
  • Parasitic-load time-shifting can provide the capacity to soak up excess power from electrical power grids during periods of over-generation. This can be very valuable where the penetration of photovoltaic (PV) power into grids is becoming high, such as in California. For example, from about 1 1AM in the morning to about 2PM in the afternoon, during the spring and fall when the air conditioning load is light and PV power supply is high, parasitic-load time-shifting may be used to soak up excess power from the electrical power grid. Where the penetration of wind power is high, parasitic-load time-shifting could soak up excess power at night (e.g., during a 3-to-4-hour window) when wind speeds are often high and power demand is low. Thus, as just one example, time-shifting the parasitic loads of brine pumping and of N2 separation and pumping could be scheduled in a diurnal fashion, during roughly two 3-to-4-hour windows: one occurring at midday and the other at night.
  • PV photovoltaic
  • Grid-stabilizing power generation capacity such as load following and peaking power, is needed to compensate for constantly fluctuating imbalances between supply and demand on electrical power grids.
  • the systems of the present disclosure can accomplish this important function in at least two fundamental ways: (1 ) adjusting gross power output and (2) adjusting net power output by time-shifting the parasitic load.
  • the second approach can be fine-tuned by modulating how much of the parasitic load of brine pumping (and/or N2 pumping) is imposed at any given time.
  • Organic Rankine cycle (ORC) power turbines and/or direct CO2/N2 power turbines could be allowed to spin at full capacity, while adjusting the parasitic loads of brine and/or N2 pumping to modulate the net power output of the geothermal plant, which could provide a very rapid and precise response to grid imbalances. In this fashion, the high capital investment in the power turbines could be fully and continuously utilized. BES and load following capacity could be achieved by oversizing the brine-pumping and N2-pumping capacities so that a large fraction of the brine-pumping and/or N2-pumping parasitic loads could be scheduled when it is most advantageous.
  • the systems and methods disclosed herein can operate to adjust the gross output from the power turbines, which is accomplished by adjusting the rate of heat withdrawal from the geothermal reservoir; however, this may be the second option because it does not allow the most expensive components of the power system to continuously run at full capacity. Because brine production is driven by stored pressure, the systems and methods of the present disclosure can rapidly and precisely adjust the rate of heat withdrawal from the reservoir and gross power output for load following and peaking power.
  • the third family of embodiments of the present disclosure involves thermal augmentation of brine at the ground surface utilizing solar thermal energy (STE) and/or waste heat to further improve upon the year-round dispatchability of one or more renewable energy sources.
  • STE solar thermal energy
  • the availability of solar thermal energy (STE) varies in a highly seasonal and diurnal fashion, placing heavy demands on back-up and load- following power sources (which in turn often emit substantial quantities of CO2).
  • the embodiments of the present disclosure enable the storage of STE in a subsurface reservoir, whether or not that reservoir has temperatures hot enough to be considered an economically viable geothermal resource.
  • the presently disclosed embodiments also enable using STE and/or waste heat to augment reservoir temperatures and thereby enhance the economic viability of a geothermal resource (203 in Figures 1 , 3, and 5). Even if a relatively low-temperature heat source is used, such as waste heat, thermal augmentation of brine prior to reinjection can reduce the rate of thermal drawdown for a geothermal reservoir system. Thermal augmentation can also be selectively applied to brine that is injected into known "thief zones", which are zones of high permeability where injected fluids preferentially flow. Because the residence time of injected fluid is less in thief zones, there can be insufficient time for the injected fluid to be heated by the reservoir prior to arriving at the production wells.
  • Brine heating can be heated in a steady fashion, as may apply to the use of waste heat. Brine may be heated in a cyclic fashion, as would apply to the diurnal and seasonal availability of STE. Temporary storage of brine in surface reservoirs (operation 202 in Figures 1 , 3, and 5) allows the brine to be available for thermal augmentation when STE or waste/excess heat is available. Brine heating can be conducted in a multi-stage fashion, by pre-heating brine with waste heat, followed by cyclic heating with STE.
  • the systems and methods of the present disclosure can utilize reservoirs with marginal or even sub-marginal resource temperatures for diurnal and seasonal storage of STE, thereby further enabling BES and load-following power generation.
  • this approach can be scheduled to take excess power from the grid and store electricity and STE when supplies of photovoltaic (PV) power and concentrating solar power (CSP) are greatest.
  • PV photovoltaic
  • CSP concentrating solar power
  • the fourth family of embodiments enables multi-fluid geothermal/STES reservoirs (such as system 10 in Figure 1 ) to be integrated with single-fluid (brine-only) geothermal/STES reservoir (system 200 in Figure 3).
  • This approach enables brine to be pre-heated in a relatively shallow reservoir with moderate temperatures prior to being injected into a hotter and deeper reservoir.
  • Series looping of brine through two integrated (shallow and deep) reservoirs may be a more efficient power-conversion process than parallel looping of brine in two independent (shallow and deep) reservoirs.
  • This approach also uses CO2 as a working fluid where it is more advantageous (shallower reservoirs with lower temperatures), while using brine as a working fluid where it is more advantageous, such as with deeper/hotter reservoirs.
  • This embodiment family can be combined with other embodiment families (e.g., parasitic-load time-shifting) to increase BES capacity.
  • Another advantageous combination is to pre-heat CO2/N2 produced from a shallow multi-fluid geothermal reservoir with brine produced from a deeper/hotter reservoir, prior to sending the CO2/N2 through a direct turbine, as discussed below.
  • Multi-Fluid Power Conversion Brine-to-C02/N2 Heat Transfer in Surface-Located Heat Exchangers
  • a fifth family of embodiments that may be implemented using the teachings of the present disclosure involves transferring heat from produced brine to produced CO2/N2 mixtures in a surface-located heat exchanger (201 of Figures 1 , 3, and 5), thereby taking advantage of the greater power-conversion efficiency of direct CO2/N2 turbines compared to ORC binary-cycle power plants.
  • This approach is significant because it can generate more power per unit heat extracted from the geothermal reservoir than would be possible for a single-fluid (brine-only) power-conversion process.
  • the Joule-Thomson effect causes CO2 to cool as it loses pressures flowing up the production well and expands.
  • N2 will reduce the pressure loss up the borehole, resulting in greater wellhead pressure, which could increase power generated from produced CO2. Because brine loses little temperature as it flows up the brine production well, when it originates from the same reservoir pressure and temperature conditions as did the CO2/N2, it will always be hotter than produced CO2/N2. Therefore, there will always be the opportunity for produced CO2/N2 to be pre-heated by produced brine in a surface heat exchanger prior to it being sent through a direct CO2/N2 turbine. An operational goal would be to balance the respective brine and CO2/N2 production rates so that most of the potentially available heat in the produced brine could be utilized to pre-heat the CO2/N2 prior to CO2/N2 being sent through the direct turbine.
  • a flowchart 300 which shows operational combinations of the embodiments of this disclosure that (1 ) harvest, (2) store, in the form of thermal energy and bulk energy (pressure), and (3) dispatch renewable energy, in response to real-time and projected requirements of electricity grids.
  • Operations 201 , 202, 203, and 210 are executed above ground (surface-located).
  • Systems 10 and 200 and Operations 204, 205, 206, 207, 208, and 209 are executed in the subsurface.
  • Operation 201 converts thermal energy to electricity.
  • Operation 210 extracts chilled thermal energy for cooling purposes, such as with a power plant to boost its efficiency.
  • Operation 202 temporarily stores produced brine in surface-located reservoirs to allow scheduling the parasitic load of pressurization and injection when power supply exceeds demand.
  • Operation 203 harvests and injects/stores thermal energy from above-ground sources (solar, waste heat, and chilled energy) when it is most advantageous to do so.
  • Operation 206 checks whether a subsurface operation is either multi-fluid (System 10) or single-fluid (System 200);
  • Operation 209 checks whether it is run as either a geothermal, geothermal/STES, or CTES reservoir.
  • Operation 205 checks whether the produced brine is totally or partially sent to separate reservoirs or is either totally or partially sent to power turbines and heat exchangers to generate electricity.
  • operation 204 checks whether the injection of CO2 and/or N2 injection is steady and/or cyclic.
  • Operation 207 checks whether make-up water from a separate source is injected into either multi-fluid or single-fluid reservoirs.
  • Operation 208 checks whether make-up brine from a separate source is injected into either multi-fluid or single-fluid reservoirs.
  • CTES reservoir is being used, then a check may be made at operation 209 to determine if the reservoir is a CTES reservoir, and if so, operation 210 may be performed to extract the CTE.
  • CTES Chilled Thermal Energy Storage
  • the sixth family of embodiments enables diurnal and seasonal chilled thermal energy storage (CTES), using the single-fluid, concentric-ring well design ( Figures 3 and 4) and the first family of embodiments of this disclosure.
  • Seasonal CTES can utilize the cold of winter or some other source of CTE, such as from liquid N2 generated by an air separation unit (ASU). It can be done by chilling produced brine when it is most advantageous.
  • a possible brine source is that extracted from a geological CO2 storage (GCS) operation for the purpose of pressure management.
  • GCS geological CO2 storage
  • CTES reservoir resources are nearly the antithesis of those for typical geothermal resources. Ideal CTES resources are those with cool temperatures; hence, great depths are not required to attain economically viable temperatures. Because CTE is being replenished on an annual basis, CTES reservoirs can be much smaller than the reservoirs required for sedimentary-basin, geothermal- energy systems. Rather than being a possible hindrance, reservoir compartmentalization can be an asset that is more conducive to subsurface storage of pumped hydro energy. Thus, CTES reservoir systems will have much wider geographic resource potential than sedimentary-basin geothermal-energy systems. This approach can be integrated into a base-load fossil energy plant to improve the economic viability of capturing and storing CO2. This approach can also be integrated into renewable geo-energy systems to enhance BES, STE storage, and load-following power-generation capacities.
  • the first added family of additional embodiments adds the option of using air as a supplemental working fluid.
  • the second added family of embodiments also Figure 6) specifically calls out the use of the waste heat of gas (CO2, N2, or air) compression as a source of thermal energy to be stored by heating and pressurizing native brine.
  • the third added family of embodiments ( Figures 7-9) uses a simpler well configuration than the concentric ring well configuration. The simpler configuration uses an injector/producer well pair that can be deployed incrementally in a modular fashion, thereby enabling the progression from a pilot project to a full-scale commercial operation.
  • the fourth added family of embodiments involves the option of deploying multi-fluid geo-energy systems and methods in settings that may include an open cavern, such as may occur in a salt dome.
  • FIG. 6 previously discussed embodiments have involved the use of either CO2 or N2 as a supplemental working fluid to create overpressure within a storage reservoir formation, and to extract thermal energy from the storage reservoir formation.
  • An additional embodiment may involve the use of air, as shown with system 300 in Figure 6. It will be appreciated that air is similar to N2 in its thermophysical properties. Because it is stored under supercritical conditions, air performs in a similar manner to N2. The use of air also enables the option of using expanders to generate electricity, as is done with conventional compressed air energy storage (CAES).
  • CAES compressed air energy storage
  • the system 300 of Figure 6 also provides the option of using waste heat or excess thermal energy from above ground sources, and more particularly using the waste heat of gas compression, which can include the waste heat associated with the compression of CO2, N2, or air.
  • the system 300 takes advantage of the fact that the earth essentially forms an exceedingly large, ready-made storage device or reservoir; therefore, it has sufficient storage capacity to store all of the waste heat of gas compression at a lower cost than above-ground or shallow subsurface storage components, due to the high fabrication costs of such existing storage components.
  • the multi-fluid geothermal energy production system 300 of Figure 6 may also be thought of as an "Earth Battery", as it uses the storage of waste heat associated with supercritical CO2, N2, or pressurized air to enable utility-scale energy storage needed for increased use of variable renewable energy and low-carbon baseload power.
  • the use of the Earth to function as a storage medium addresses the major deployment barriers to CO2 capture, utilization, and storage (CCUS) by managing overpressure and creating a viable business case for CO2 storage.
  • the Earth Battery formed using the system 300, together with overpressure driven by CO2, N2, or pressurized air storage, enables the system 300 to harvest, store and dispatch energy from subsurface (geothermal) sources and also from surface-located thermal sources (e.g., solar, fossil, nuclear, or waste heat of gas compression), as well as from excess energy from electric grids.
  • subsurface geothermal
  • surface-located thermal sources e.g., solar, fossil, nuclear, or waste heat of gas compression
  • excess energy from electric grids e.g., solar, fossil, nuclear, or waste heat of gas compression
  • Stored, unheated CO2, N2, or air plays three key roles: (1 ) as a supplemental fluid that creates pressure needed to efficiently recirculate working fluids that store and recover energy, (2) as a working fluid for efficient, low-water-intensity electricity conversion, and (3) as a shock absorber to allow diurnal and seasonal recharge/discharge cycles with minimal pressure oscillations, thereby providing enormous pressure-storage capacity, with reduced risk of induced seism icity or leakage of stored CO2, N2, or air.
  • a portion of the brine produced from the reservoir can be diverted to generate water.
  • the system 300 of Figure 6 also takes advantage of the fact that concentric rings of injection and production wells are used to create a hydraulic divide to store pressure, CO2, N2/air, and thermal energy. Such storage can take excess power from the utility power grid and excess thermal energy, and dispatch that energy when it is demanded.
  • the system 300 may be pressurized and/or heated when power supply exceeds demand and depressurized when demand exceeds supply.
  • the Earth Battery implemented by the system 300 is especially well designed for locations where a permeable geologic formation is overlain by an impermeable formation that constrains migration of buoyant CO2, N2/air, and heated brine.
  • the Earth Battery implemented by the system 300 can be deployed in mature oil and gas fields, sometimes called brown fields.
  • the Earth Battery formed by the system 300 can also be deployed in green fields in saline aquifers where reservoir operations have not yet occurred.
  • the Earth Battery formed by the system 300 can also be deployed in locations where an open cavern exists or where an open cavern can be created, such as in salt domes. Such geologic conditions exist over nearly half of the contiguous United States.
  • the system 300 shown in Figure 6 uses an airstream 302 which may be fed through a low pressure (LP) compressor 304, a high pressure (HP) compressor 306, and into a pair of heat exchangers 308 and 310 to cool the compressed air.
  • the two compressors 304 and 306 may also be viewed as forming a compressor section, and more particularly a two stage compressor section.
  • a cold brine holding tank or reservoir 312a fed from a brine pressurized cool brine production well 312 may be used to supply cool brine to the heat exchangers 308 and 310.
  • cool brine it is meant brine that may typically range in temperature from about 100-250 degrees F, versus the “hot brine” described herein, which typically may range in temperature from about 300-600 degrees F.
  • a pump 314 may be used to pump the brine after it passes through the heat exchangers 308 and 310, and has become heated, into hot brine injection wells 316 where the heated brine resides in a hot brine storage zone 315. Cooled compressed air exiting the second heat exchanger 310 may then be fed back into one or more compressed air energy storage (CAES) wells 317.
  • CAES compressed air energy storage
  • the system 300 of Figure 6 may also include a power production section 318.
  • the HP expander 330 receives heated compressed air (which has been heated by the geothermal reservoir formation) from a compressed air storage zone 322 within a reservoir formation 324.
  • the heated compressed air is withdrawn up through one or more compressed air energy storage (CAES) production wells 326 and routed into a third heat exchanger 328.
  • the third heat exchanger 328 further heats the compressed air to higher temperature (e.g., preferably between about 350F - 600F) before outputting the heated high pressure air into a first high pressure (HP) expander 330 to help drive a power producing element (e.g. turbine).
  • higher temperature e.g., preferably between about 350F - 600F
  • the air exiting the HP expander 330 may be used to feed a fourth heat exchanger 332 where the airflow is further heated.
  • the airflow leaving the fourth heat exchanger 332 may be fed into a low pressure (LP) expander 334 to help drive a power producing implement (e.g. turbine).
  • a cooled airflow 336 is then exhausted from the LP expander 334.
  • Both of the heat exchangers 328 and 332 may be fed with hot brine 338a from one or more hot brine production wells 338 for the purpose of heating the compressed airflows flowing through the heat exchangers 328 and 332.
  • the hot brine 342 and 344 which has been cooled after exiting each of the heat exchangers 328 and 332, may be directed back into the cold brine holding tank or reservoir 312a.
  • the HP expander 330 and the LP expander 334 cooperatively help to drive a turbine or other power producing implement to produce electric power.
  • a significant advantage of the system 300 is that the compressed air storage zone 322 forms a storage region within the reservoir formation 324 for waste heat from compressed CO2, N2 or air. This eliminates the need for surface mounted storage tanks or shallow, below-ground storage tanks or equipment. Because the Earth is an excellent thermal insulator with high heat capacity, and because the Earth is naturally warm at the depths where the compressed air storage zone 322 is formed, it eliminates the need to fabricate thermal insulation. Because the Earth heats up around storage zone 322, and because very large quantities of heat are stored within storage zone 322, thermal losses are small, resulting in the recovery of a large fraction of the stored thermal energy.
  • System 400 in accordance with another embodiment of the present disclosure is illustrated which forms a well configuration which may be implemented with as few as two wells: an injection well 402 and a production well 404, with the possibility of an additional (i.e., optional) well 406 to extract native brine. If the source of brine is from a separate reservoir operation, this third well will not be required.
  • System 400 may involve three stages: a "thermal recharge stage”; a “supplemental fluid recharge stage”; and an "energy discharge stage”.
  • hot brine withdrawn from a geothermal storage reservoir 408 through the brine production well 406 is heated from either an above-ground heating source 410 (e.g., a solar thermal farm), or from a deeper reservoir, which is at a higher temperature than the storage reservoir, and then pressurized and injected as pressurized, hot brine 412 through the supplemental fluid injection well 402 into the storage reservoir 408. Heat from the hot brine 412 increases the temperature of the storage reservoir 408, making it behave like a high-grade geothermal resource.
  • an above-ground heating source 410 e.g., a solar thermal farm
  • a deeper reservoir which is at a higher temperature than the storage reservoir
  • the supplemental fluid (CO2, N2, or air) recharge stage will be described.
  • CO2 can originate from either an anthropogenic source (e.g., coal-fired power plant) or a natural geologic source.
  • N2 can originate from an air separation unit (ASU), while air can readily be supplied from the ambient atmosphere.
  • Cold (i.e., unheated) supplemental fluid 414 from a supplemental fluid source 416 is compressed and injected into the storage reservoir 408.
  • the supplemental fluid recharge stage may occur simultaneously with the thermal recharge stage, if hot brine 412 and supplemental fluid 414 are injected into different horizons (i.e., depth intervals) along the injection well.
  • hot brine 412 and cold (i.e., unheated) supplemental fluid 414 injection occurs in an alternating manner to allow continuous CO2 injection, which may be needed to accommodate continuous CO2 supply.
  • CO2 may be injected into a first well pair "A”, while hot brine is being injected into well pair "B”.
  • hot brine would be injected into well pair "A”, while CO2 is being injected into well pair "B”.
  • the energy discharge stage may involve feeding hot supplemental fluid 418, or a mixture of hot supplemental fluid (such as CO2 as shown in Figure 9) and brine 420, into a fluid separator 422.
  • a fluid separator 422 If the supplemental fluid is CO2 or N2, it can be sent to an electric power producing system 424a such as a Brayton cycle turbine or, if the supplemental fluid is air, it can be sent into one or more expanders (such as shown in Figure 6).
  • the supplemental fluid is CO2, N2, or air, it can be sent to one or a series of heat exchangers 424b before being fed into the power producing system 424a, where it is heated by the hot brine 420.
  • Cold brine 426 may be sent to a cold brine holding tank or staging pond 428.
  • Cold N2 or air 430 can be discharged to the ambient atmosphere.
  • Cold CO2 or N2 432 can be routed into temporary, above-ground storage 434 or may be immediately pressurized and injected into the storage reservoir 408.
  • the deployment may even be in geologic settings that may include combinations of open caverns and porous sedimentary rock, or even in settings that are entirely comprised of an open cavern.

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Abstract

L'invention concerne un système et un procédé de production d'énergie géothermique pour extraire de l'énergie thermique d'une formation de réservoir et pour stocker la chaleur perdue thermique et/ou la chaleur excédentaire dans une zone de stockage de la formation de réservoir. Le système peut comprendre au moins un puits d'injection de fluide comprimé en communication avec la zone de stockage pour injecter un fluide de travail comprimé non chauffé dans la zone de stockage. Le système peut également avoir au moins un puits d'injection de fluide en communication avec la zone de stockage pour injecter un fluide de travail chargé de chaleur perdue thermique ou de chaleur excédentaire, dans la zone de stockage, la zone de stockage étant située au-dessous d'une couche de roche couverture de la formation de réservoir et au-dessus d'une zone de saumure native à l'intérieur de la formation de réservoir. La zone de stockage est au moins partiellement circonscrite par une zone de stockage de saumure chaude de la formation de réservoir. Le fluide de travail comprimé aide en outre à un retrait de saumure sous pression se trouvant sous et/ou sur les côtés de la zone de stockage. Au moins un puits de production de stockage d'énergie de CO2, N2, ou d'air comprimé est utilisé, qui est en communication avec la zone de stockage pour éliminer le fluide de travail comprimé de la zone de stockage pour une utilisation dans la production d'énergie.
PCT/US2018/040026 2017-07-05 2018-06-28 Systèmes et procédés d'énergie géothermique renouvelable multi-fluide WO2019010059A1 (fr)

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Citations (5)

* Cited by examiner, † Cited by third party
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JP2008248837A (ja) * 2007-03-30 2008-10-16 Central Res Inst Of Electric Power Ind 地熱発電方法並びにシステム
US20120038174A1 (en) * 2010-08-13 2012-02-16 Board Of Regents, The University Of Texas System Storing Carbon Dioxide and Producing Methane and Geothermal Energy from Deep Saline Aquifers
US20130062890A1 (en) * 2009-03-13 2013-03-14 Regents Of The University Of Minnesota Carbon dioxide-based geothermal energy generation systems and methods related thereto
US20150369521A1 (en) * 2014-06-20 2015-12-24 Lawrence Livermore National Security, Llc Multi-Fluid Renewable Geo-Energy Systems And Methods
KR101683714B1 (ko) * 2015-09-22 2016-12-07 현대건설 주식회사 초임계 이산화탄소 랭킨 사이클을 이용한 지열 발전 시스템

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* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
JP2008248837A (ja) * 2007-03-30 2008-10-16 Central Res Inst Of Electric Power Ind 地熱発電方法並びにシステム
US20130062890A1 (en) * 2009-03-13 2013-03-14 Regents Of The University Of Minnesota Carbon dioxide-based geothermal energy generation systems and methods related thereto
US20120038174A1 (en) * 2010-08-13 2012-02-16 Board Of Regents, The University Of Texas System Storing Carbon Dioxide and Producing Methane and Geothermal Energy from Deep Saline Aquifers
US20150369521A1 (en) * 2014-06-20 2015-12-24 Lawrence Livermore National Security, Llc Multi-Fluid Renewable Geo-Energy Systems And Methods
KR101683714B1 (ko) * 2015-09-22 2016-12-07 현대건설 주식회사 초임계 이산화탄소 랭킨 사이클을 이용한 지열 발전 시스템

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