WO2024076730A1 - Geothermal well diversion - Google Patents

Abstract

Techniques for controlling tortuosity of fluid flow through a subterranean formation include introducing a diversion fluid into a wellbore, introducing a first fluid into the wellbore, collecting a second fluid from the wellbore or a second wellbore, and recovering heat from the second fluid. Techniques for increasing the likelihood that a fluid will absorb heat as it flows through rock fractures include introducing a first fluid into a first wellbore, introducing a particulate fluid into the first wellbore, collecting a second fluid from a second wellbore, and recovering heat from the second fluid. Techniques for recovering heat from a subterranean formation include observing a first parameter of a first fluid introduced into a first wellbore, observing a second parameter of a second fluid collected from a second wellbore, recovering heat from the second fluid, and introducing a diversion fluid into the first wellbore.

Description

GEOTHERMAL WELL DIVERSION

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to United States Patent Provisional Application No. 63/378,612, filed October 6, 2022, entitled, “Intentional Diversion for Geothermal Wells,” which is incorporated by reference in its entirety.

BACKGROUND

[0002] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind.

[0003] Hot Dry Rock (HDR) reservoirs represent a high potential for geothermal energy resources as these resources are present worldwide in multiple basins. As opposed to traditional hydrothermal energy systems, HDR reservoirs lack the natural flow of hot water that can feed a geothermal power plant and they require continuous injection of fluid, usually water. The fluid is usually pumped through multiple injector wells and absorbs heat as it travels in the reservoir toward the producer wells, where the energy, which is a function of temperature and flow rate, is converted to power through a geothermal/hydrothermal plant. In the process, the injection of cold water at high pressure tends to generate new or to open existing natural fractures in the reservoir. Often, the practice is to drill a well, stimulate it with hydrofracking or proppant fracturing and monitor where the fractures are going through microseismic measurements. Once the stimulated region is identified, the injection is temporarily stopped, and the producer well is drilled through the identified region. Such workflow ensures that later when the injection of cold water is resumed and water is propagating to previously identified network of fractures it further propagate into the producer well. On its way through the fracture network toward the producer well, water gets heated by the geothermal energy of the reservoir.

[0004] One challenge faced by HDR reservoir exploitation is called short circuit, which occurs when the flow of water from injector to producer well is limited to a short number of paths (or even a very single path). As a result, the water cannot absorb enough heat before being produced, affecting the efficiency of the geothermal/hydrothermal plant. It is thus necessary to ensure multiple flow paths into the reservoir to improve the heat sweep efficiency. That is, if the connectivity between injectors and producers is too high, the fluid does not have time to capture enough heat and the wells are described as short-circuited.

SUMMARY

[0005] A summary of certain embodiments described herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.

[0006] Embodiments herein relate to a system, apparatus, composition, and method for controlling the tortuosity of fluid flow through a subterranean formation traversed by at least two wellbores including introducing a diversion fluid comprising a diversion agent into a first wellbore, introducing a first fluid into a first wellbore, collecting a second fluid from a second wellbore, and recovering heat from the second fluid. The diverting agent may degrade and may comprise particulate, fiber, or a combination thereof. The diverting agent may remain in solid phase for at least 10 hours at 250°F. The diversion fluid and the first fluid may include a viscosifying agent. The subterranean formation includes sedimentary, igneous, metamorphic rock, or a combination thereof. Collecting the second fluid comprises measuring the temperature, pressure, or both of the second fluid and the measurements are used to control the introducing a diversion fluid. A system, apparatus, composition, and method for increasing the likelihood that a fluid will absorb heat as it flows through rock fractures between two wellbores traversing a subterranean formation.

[0007] Embodiments herein relate to a system, apparatus, composition, and method for recovering heat from a subterranean formation traversed by at least two wellbores, including observing a first parameter of a first fluid introduced into a first wellbore, observing a second parameter of a second fluid collected from a second wellbore, recovering heat from the second fluid, and introducing a diversion fluid comprising a diverting agent into the first wellbore. Observing the first and second fluids includes measuring the temperature, pressure, volumetric flow, chemical composition, or a combination thereof of the second fluid. Some instances may observe the heat recovered from the second fluid. [0008] Embodiments herein relate to a system, apparatus, composition, and method for controlling the tortuosity of fluid flow through a subterranean formation traversed by a wellbore.

[0009] Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

[0010] Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings, in which:

[0011] Figure 1 is a sectional view of a formation with particulate and fibers;

[0012] Figure 2 is a sectional view of multiple wellbores traversing a subterranean formation with a fracture network of fluid flow paths;

[0013] Figure 3 is a sectional view of a formation with particulate and fibers;

[0014] Figure 4 is a sectional view of a formation with particulate and fibers; and

[0015] Figure 5 is a series of 5(a), 5(b), and 5(c) sectional views of multiple wellbores traversing a subterranean formation.

DETAILED DESCRIPTION

[0016] One or more specific embodiments of the present disclosure will be described below. These described embodiments are only examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0017] When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.

[0018] Controlling the tortuous flow of fluid across the rock surfaces of HDR is desirable for effective geothermal well management. In some cases, stimulation of the reservoir (hydraulic fracturing) and introduction of diversion fluids are required to enable controlled connectivity between injectors and producers to facilitate a complex fracture network. Embodiments herein rely on intentional multiphase fluid diversion technologies to enable the generation of a complex fracture network within a geothermal system. Embodiments herein are different from historical hydraulic fracturing systems because there may not be particulate including proppant or other solid particulates in the fracture and the diversion can be generated by bridging particulates followed by fibers, a mixture of bridging particulates and fibers, or only fibers.

[0019] Some embodiments herein relate to a method of generating multiple flow paths in a subterranean formation by pumping a fluid in the reservoir, pumping a step of bridging particulates or other solid particles that will bridge in the main flow paths, pumping fibers which will accumulate on top of the bridge, reduce permeability and significantly slow down flow across the bridge, and by pumping subsequent fluid which is directed towards secondary flow paths inside the reservoir. Some embodiments benefit from a method of pumping a fluid into a subterranean formation to create a fracture and to carry some particulate to the tip of the fracture so the particulate bridges deep into the formation. The particulate is then followed by fibers which reduce permeability of the particulate bridge at the tip of the fracture (see Figure 1), followed by pumping more particulate in the fracture. Figure 1 is a schematic view of pumping particulate 610 into a formation followed by pumping fibers 620 into the formation. That is, embodiments herein relate to a method of diverting the flow inside a reservoir by the use of material (fibers or bridging particulates and fibers, Figure 2) so that the material is first transported into the main flow path or fracture and accumulates and plugs this main fracture somewhere along the path. Hence, the material diverts the subsequent flow towards secondary flow paths, improving heat sweep efficiency in the reservoir. Figure 2 provides a sectional view of a formation, power plant, injector, and producer wells.

[0020] Figure 5 also provides a series of bird’s eye sectional views of a formation with multiple wellbores; it shows the operation of geothermal injectors and producer. Figure 5(a) shows all heat recovery areas are cooled down equally. Figure 5(b) shows geothermal injectors and producer configuration with excessive fluid flow in certain regions (shown in white) making them much cooler than surrounding rock. This leads to poor heat recovery. This condition can be identified by monitoring fluid temperature in the producer. Figure 5(c) shows degradable or non-degradable diverter materials are placed in these cooled regions to reduce flow, thus allowing them to heat up again to a desirable operating temperature. Diverter materials can be injected from either the producer or the injector well. The frequency, volume, and the rate of degradation and blocking ability of the diverter material is optimized based on the specific properties of each heat recovery zone.

[0021] Monitoring the fluid as it flows from the second wellbore to the energy recovery system may inform overall system management. Some embodiments may benefit from distributed heat sensors across the subterranean formation. Some embodiments control for heat sweep efficiency.

• Pumping cold water at high rates in the reservoir through an injector well;

• Monitoring process efficiency by measuring the energy recovered by the producer well (fluid flow rate and heat); and/or

• Pumping a pill of a multiphase, multiple particle size and shape diverter into the formation to develop multiple flow paths and enhance heat sweep efficiency based on the results of the monitoring and when needed generally.

[0022] Further, in some embodiments, a heat sweep efficiency monitoring method may be established at the producing well measuring total the energy brought to surface (for instance through monitoring flow rate and heat). When the energy becomes too low due to short-circuit or cooldown in the reservoir, a new pill of diverting material can be pumped to increase flow-path complexity in the reservoir and increase heat sweep efficiency. Some embodiments may benefit from controlling the temperature of the water as it is added to the initial wellbore. [0023] Additional embodiments herein relate to increasing heat sweep efficiency in a subterranean formation by monitoring the energy recovered from a geothermal producer well and when the energy is below a threshold predetermined by the geothermal facility:

• Pump a step of bridging particulates in the injector well where the step of bridging particulates will bridge in the main flow paths.

• Pump a step of fibers which will accumulate on top of the bridge, reduce permeability and prevent flow across the bridge.

• Pumping subsequent fluid which is directed towards secondary flow paths inside the reservoir; and monitor the efficiency of diversion by measuring the energy recovered from the geothermal well.

[0024] As water is injected in the formation at high rates, it may follow a preferential path toward the producer well in slash lines which is less efficient in terms of heat sweep efficiency. Once the diverter is injected, it plugs the original flow path in solid bold lines and forces the fluid through more complex flow paths. Further, the arrival temperature, pressure, or both of the fluids at the producer well can be monitored. The information from monitoring, the measuring observations are used to control introducing a diversion fluid by changing flow, pressure, temperature, or composition of the introduced fluid. If it is below the desired temperature, it would mean that there is a short circuit and a diverter pill may need to be injected. Alternatively, a tracer can be injected and its concentration monitored at the producer. A diverter pill may be needed, if the travel time for the tracer is less than desired. In some embodiments, the degradation products of the diverter or the embedded tracers within the diverter can be monitored at the producer and if it drops below a certain value, additional diverters need to be injected.

[0025] In some embodiments, the concentration of fiber degradation products such as lactic acid (a product of PLA degradation) can be measured in a produced water. In some embodiments, basic tests need to be performed to make sure degraded PLA or other degradation products don’t deposit in the producer well while being transported to the surface or don’t interact with the equipment for water transport and the gas turbine on the surface that generates the electrical power.

[0026] The diverting materials may be pumped simultaneously and uniformly in some embodiments. In embodiments where a first bridging material and a second bridging material are introduced simultaneously into a fracture, they may intermingle with the formation of a bridge. This is shown in Figure 3, reference numeral 620. In such embodiments, a first bridging agent and a plurality of fibers suspended in a carrier fluid are pumped into a far field region, being placed near the outer border (perimeter) of the growing fracture. The bridging fibers and the fibers intermingle with the formation of a plug. As noted above, the bridging particles may have a size big enough to bridge next to the fracture tip. In one or more embodiments, the bridging particles may have a multimodal distribution.

[0027] In some embodiments fibers degrade in a way that may be tailored based on the rock heat transfer properties, such as rock temperature, rock thermal conductivity and fracture network geometry that defines the configuration of a heat sweep. In some embodiments, the subterranean formation comprises sedimentary, igneous, metamorphic rock or a combination thereof. Bridging particle size and concentration may be chosen based on the fracture geometry (mostly fracture width). In some embodiments, bridging particle size must be larger than a fracture half-width at a concentration above 1 lb per gallon of fluid added.

[0028] Degradable material is effective in some embodiments because once the reservoir reheats, one may want to resume injection in that flow path. Some embodiments may optimize the timing of degradation to match the reheating time for the reservoir. This would simplify surface operation as one would inject water continuously and periodically inject degradable diverters on a set schedule. The degradation timing will be engineered to ensure the fluids flow to the right part of the reservoir every time.

[0029] Any degradable or dissolvable material (bridging particles or fibers or both) must degrade slowly enough to provide sufficient bridging during its placement. Time scale for placement, for heating to specific temperature might be obtained based on a fracturing simulation as well as based on the real-time temperature measurements performed by bottomhole gauges or by monitoring of the water heat content in a producer well. Some embodiments may benefit from various modelling packages that exist to model heat transfer and temperature evolution in the reservoir as well as inside the fracture network generally.

[0030] After a bridge of particulates and fibers has been formed, it may undergo complex evolution in terms of degradation. Degradation typically is a strong function of temperature inside the fracture. Temperature inside the fracture is defined by an equilibrium between the heat inflow (from the geothermal heat of reservoir) and heat outflow (carried by circulating water). In some embodiments, the actual degradation of diversion material can be modelled in advance and can be used to design the treatment and to select bridging material or fiber or both. In some embodiments, a plug made of solid degradable particulates such as fibers keeps mechanical strength and diverts efficiently until about 50 percent of the starting material by mass is degraded. Some embodiments may be informed by how the degradation or dissolution data for any degradable material used (be it bridging particles of fibers) can be experimentally obtained in the laboratory for the material used for diversion.

[0031] Figures 1 and 3 provide schematic views of a formation with particulate and fibers for comparison. Figure 1 depicts the uniform placement of two diverting materials into a fracture 600, where a first and a second plurality of bridging materials are introduced sequentially. In such embodiments, a first diverting material transport that includes a first bridging material 610 is placed uniformly on the outer perimeter of a fracture 600. The first bridging material 610 may bridge near the fracture tip with the formation of a plug. In such embodiments, the first bridging material may be a large particle. The size of the bridging material may be 100 mesh or 40/70, or 30/50 or 20/40 or 16/30 or 16/20. Fibers may be added to first bridging material 610 (such as a proppant) for better transport but are not required. The second bridging material 620 (such as for example cellulose fibers dispersed in a carrier fluid) may be transported towards the fracture tip and may accumulate on the surface of the bridge formed by the first bridging material 610, with the formation of a low permeability plug which has high resistance to the fluid flow. As fluid can no longer flow into fracture, the fracture extension is restricted. Such embodiments may include more stages of diversion if desired (not shown). In embodiments when the first bridging material is sand and the second bridging material is a plurality of fibers, the fibers may be introduced in an amount of 5-100 percent by weight less than the amount of sand.

[0032] Practically speaking, degradable material is only one of the options for particles contemplated herein such as fibers and particle. Another option is non-degradable material. In reality at temperature above 350°F every material may degrade or dissolve in some way or form, but it might be a slow process. Degradable materials that degrade slowly over time, days, weeks, months, or several months) may have additional benefits though due to strong dependence of degradation rate on the water temperature. Some embodiments may have material that remains in solid phase for 10 hours at 250°F. After the treatment end and the injection started it will happen naturally that diverters at flowpaths with the highest rate of flow (such as when water will not have time to heat too much) would degrade slower than the diverters at flowpaths with low rate. Thus, in some embodiments, the system is self-adjusting and favors flowpaths that enable good heat extraction by circulating water.

[0033] In some embodiments, the fibers and bridging particulates are made of non-dissolvable and non-degradable material. In some embodiments, the fibers are made of dissolvable or degradable material, where dissolution or degradation occurs slowly over multiple days or weeks at reservoir temperature. Sometimes, fiber degradation or dissolution rates are faster with temperature.

[0034] A first bridging agent may be selected from the group of inert non-deformable bridging materials and the second bridging material may be selected from the group of naturally derived fibers such as cellulose fibers. The mechanism of restricting the growth of a fracture height and/or length when the two bridging materials, 610 and 620 are pumped sequentially into a far field region of a fracture 600 is depicted in Figure 1. Figure 1 shows the formation of the plug formed by the first bridging material 610 (such as bridging particles) on top of which the second bridging material 620 (such as fibers) accumulate with the formation of a low permeability plug 640. The bridging particles 610 may provide effective bridging due to the large size of the particles, while the second bridging material may provide the formation of a layer with very low permeability to provide overall high resistance to the fluid flow, thus enabling effective far field diversion.

[0035] It is also envisioned that the first bridging material 610 may be intermingled with a first plurality of fibers 620 with the formation of a plug 650 as seen in Figure 3. In such embodiments, the second bridging material 660 (such as a second plurality of fibers) may accumulate on the surface of the plug 650 formed by the first bridging material 610 and the first plurality of fibers 620 with the formation of a low permeability plug. In such embodiments, the first plurality of fibers 620 may be selected from the group of organic polymers. As noted above, the first bridging material 610 may have a size large enough to bridge the far field region. It is also envisioned that the first bridging material 610 may have a monomodal and/or multimodal distribution. In such embodiments, the first 620 and the second plurality of fibers 660 may be the same, having the same length and diameter, or may be different.

[0036] Diverter pills help restrict fracture tip growth. A diverter pill can consist of particle (bridging material) followed by fibers for permeability reduction. The pill can also consist of a mix of fibers and particle followed by fibers or of fibers.

[0037] Fiber chemical identity as well as shape, size, and concentration can be tailored based on the temperature profile in the expected place of their downhole accumulation (at the front of bridge formed by bridging particles). Fiber length can be in the range from 0.1 mm to 50 mm, with the aspect ratio (length to width) in the range from 2 to 10,000. The concentration of the fibers pumped in a stage of an operation may be varied within the limits of 0.1 - 1000 ppt. Further, the fiber material may be any polymeric fiber, such as cellulose fibers. The amount of the fibers pumped during a stage may be varied within the range of 10 - 30 000 lb. The first and the second stage of the fracturing operation may be pumped sequentially, one after another, or may be spaced with clean fluid or with a particle laden stage. A stage may be pumped at the beginning of the cycle, during the cycle or after the cycle.

[0038] Similarly, the bridging particles may have geometrical considerations. The bridging particles may have a bimodal distribution, as represented in Figure 4. Figure 4 provides a schematic view of a multiple particle size distribution in a formation.

[0039] Figure 4 represents a mechanism for bridging a far field region when a plurality of fibers 910 is intermingled with a bridging material that has a bimodal distribution (such as large and small bridging particles, 920 and 930, respectively). In such embodiments, the bridging materials may be pumped early in the particulate portion of the treatment. As these materials are transported through the fracture towards the narrower fracture widths, the larger particles will begin to bridge and the smaller particles will begin to pack off along with the fiber in a manner similar to filtration by a system of bridged particles. Fibers with small length may efficiently plug the pore space in the pack and may provide low permeability for the pack, thus enabling stop of fracture tip propagation. Further, fibers 910 may transport the large and the small bridging particles 920, and respectively 930, towards the fracture tip with the formation of a low permeability plug 950. The fibers may also act as bridging and permeability reducing fibers.

[0040] In some embodiments, plugging fibers are generated in-situ from the precipitation of polymers triggered downhole or at the wellhead. Some embodiments may benefit from pumping particles having at least 2 different sizes and fibers to plug the fracture in a specific region of the formation therefore controlling fracture growth. Some embodiments may use shrinkable material with a plurality of particulate, where the mixture creates a plug of at least one fracture in regions far from the wellbore, in regions in the fracture crevasses. Some embodiments may benefit from using a mix of particulate and degradable fibers where the degradable materials form a plug in at least one perforation, fracture, or wellbore and where the fibers eventually, at least partially, degrade so the plug disappears. [0041] Bridging particulates and fibers are mixed at the surface and pumped downhole as a part of the treatment. When bridging particulates are made of material with specific gravity above 1.1 (sand, ceramic particulate, etc...), a viscosity agent may be used to enable tailored material placement. A viscosity agent may be linear or cross-linked guar-based gel, viscoelastic surfactant based fluid, xanthan, polyacrylamide friction reducers of various types, etc. Similarly, the viscosity requirements (in terms of cP) are similar to a fluid at a lower temperature range, however at high temperature it is harder to achieve comparable levels of viscosity. For some embodiments, the recipe to achieve high viscosity that would be stable at high temperature is higher loading of polymers, using of high-temperature cross-linker, and using fibers for controlled particulate transport.

[0042] During treatment, fracture growth may be monitored closely by microseismic monitoring, in part, to characterize or confirm the formation of new channels in the formation. In some embodiments, it is done on a regular basis to inform the position of new wells, its position is based purely on the results of said microseismic monitoring. Fiber optics may provide another method for monitoring.

[0043] Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the claims.

Claims

CLAIMS We claim:

1. A method for controlling the tortuosity of fluid flow through a subterranean formation traversed by at least two wellbores, comprising: introducing a diversion fluid comprising a diversion agent into a first wellbore; introducing a first fluid into a first wellbore; collecting a second fluid from a second wellbore; and recovering heat from the second fluid.

2. The method of claim 1, wherein the diversion agent degrades.

3. The method of claim 2, wherein the diversion agent comprises particulate, fiber, or a combination thereof.

4. The method of claim 2, wherein the diversion agent remains in solid phase for at least 10 hours at 250°F.

5. The method of claim 1, wherein the subterranean formation comprises sedimentary, igneous, metamorphic rock or a combination thereof.

6. The method of claim 1, wherein the collecting the second fluid comprises measuring the temperature, pressure, or both of the second fluid.

7. The method of claim 6, wherein the measuring observations are used to control the introducing a diversion fluid, introducing the first fluid, or both.

8. A method for increasing the likelihood that a fluid will absorb heat as it flows through rock fractures between two wellbores traversing a subterranean formation, comprising: introducing a first fluid into a first wellbore; introducing a particulate fluid comprising particulate into the first wellbore; collecting a second fluid from a second wellbore; and recovering heat from the second fluid.

9. The method of claim 8, further comprising introducing a fiber fluid comprising fiber into the first wellbore.

10. The method of claim 9, wherein the fiber and particulate fluids are introduced at the same time.

11. The method of claim 8, wherein the particulate remains in solid phase for at least ten hours at 250 °F.

12. The method of claim 8, wherein the particulate fluid further comprises a viscosifying agent.

13. A method for recovering heat from a subterranean formation traversed by at least two wellbores, comprising: observing a first parameter of a first fluid introduced into a first wellbore; observing a second parameter of a second fluid collected from a second wellbore; recovering heat from the second fluid; and introducing a diversion fluid comprising a diversion agent into the first wellbore.

14. The method of claim 13, wherein the diversion agent degrades.

15. The method of claim 13, wherein the diversion agent comprises particulate, fiber, or a combination thereof.

16. The method of claim 14, wherein the diversion agent remains in solid phase for at least 10 hours at 250 °F.

17. The method of claim 13, wherein the observing the second fluid comprises measuring the temperature, pressure, volumetric flow, chemical composition, or a combination thereof of the second fluid.

18. The method of claim 13, wherein the observing the first fluid comprises measuring the temperature, pressure, volumetric flow, chemical composition, or a combination thereof.

19. The method of claim 13, further comprising observing the heat recovered from the second fluid.

20. A method for controlling the tortuosity of fluid flow through a subterranean formation traversed by a wellbore, comprising: introducing a diversion fluid comprising a diversion agent into the wellbore; introducing a first fluid into the wellbore; collecting a second fluid into the wellbore; and recovering heat from the second fluid.