CN112041539A

CN112041539A - Simultaneous fracturing process

Info

Publication number: CN112041539A
Application number: CN201980020308.3A
Authority: CN
Inventors: 迈克尔·克莱内克
Original assignee: Crestone Resources
Current assignee: Crestone Resources
Priority date: 2018-02-09
Filing date: 2019-02-08
Publication date: 2020-12-04
Also published as: MX2020008338A; US20190249527A1; CA3090690A1; AU2019216755A1; WO2019157336A1

Abstract

A method for extracting natural resources may include forming a fracture network in a target formation by simultaneously pressurizing the target formation on opposite sides with hydraulic fracturing fluid through different wells, thereby forming a fracture series from each of the different wells having effective fracture lengths that overlap one another.

Description

Simultaneous fracturing process

Cross-referencing

The present application claims priority from U.S. patent application No. 15/893,363 entitled "SIMULTANEOUS FRACTURING PROCESS (SIMULTANEOUSs FRACTURING PROCESS)" filed on 2019, 2, 9, which is incorporated herein by reference in its entirety.

Background

Hydraulic fracturing is a technique for fracturing subterranean formations using pressurized fluids. The process involves injecting fluid into the wellbore under high pressure to fracture the rock of the subterranean formation. The liquid spreads throughout the fracture. When the liquid is removed, the fracture will remain open as sand or other types of proppants suspended in the fracturing fluid remain in the fracture and prevent the fracture from closing. The fracture opening makes it easier to obtain natural resources, such as natural gas and liquid oil, and to enable these natural resources to flow more easily within the subterranean formation to the wellbore for production.

A hydraulic fracturing method is disclosed in U.S. patent No. 4,724,905 to Duane c.uhri et al. In this reference, the hydraulic fracturing method involves a process of sequentially hydraulically fracturing a hydrocarbon fluid-containing formation. Inducing fractures in the formation by hydraulic fracturing through a wellbore. Thereafter, while the formation is maintained pressurized by the first induced fracture operation, a second hydraulic fracturing operation is conducted via another wellbore substantially within the pressurized formation region of the first fracturing operation, which results in formation of a fracture trajectory that opposes the far field in situ stress. This second hydraulic fracture will tend to bend away from the first hydraulic fracture and have the potential to intersect a fracture containing natural hydrocarbon fluids in the formation.

A hydraulic fracturing method is disclosed in U.S. patent No. 4,830,106 to Duane c.uhri et al. The hydraulic fracturing method relates to a process and apparatus for simultaneously hydraulically fracturing a hydrocarbon-bearing fluid formation. Inducing fractures in the formation by simultaneously hydraulically fracturing at least two wellbores. While the formation remains pressurized, curved fractures propagate from each wellbore, forming fracture trajectories that oppose the far-field in-situ stress. By applying hydraulic pressure to both wellbores simultaneously, at least one curved fracture trajectory will be caused to propagate from each wellbore and cause the at least one curved fracture trajectory to intersect the natural hydrocarbon fracture as opposed to the far-field in-situ stress. Each of these references is incorporated by reference herein in its entirety for its teachings.

Disclosure of Invention

In one embodiment, a method for extracting natural resources comprises: a fracture network is formed in the target formation by simultaneously pressurizing the target formation on opposite sides with hydraulic fracturing fluids through different wells, thereby forming a fracture series from each of the different wells having effective fracture lengths that overlap one another.

The effective fracture length may be 300 feet or less from each of the wells.

The effective fracture length may be 200 feet or less from each of the wells.

The different wells may be spaced apart from each other by a distance of less than 600 feet.

The different wells may be spaced apart from each other by a distance of less than 400 feet.

Each of the different wells may be horizontal wells.

The target formation may contain known hydrocarbon deposits.

The target formation may be located in an oil shale formation.

The natural resource may be a liquid hydrocarbon.

The target formation may be between different wells.

In some embodiments, a method for extracting natural resources comprises: forming a first fracture series from the first wellbore section by pressurizing the target formation with a first hydraulic fracturing fluid from the first wellbore section, wherein the first fracture series comprises a first effective fracture length protruding into the target formation; and simultaneously forming a second fracture series by pressurizing the target formation with a second hydraulic fracturing fluid of a second wellbore section spaced a distance from the first wellbore section and the target formation being positioned between the first wellbore section and the second wellbore section, wherein the first fracture series includes a second effective fracture length protruding into the target formation and overlapping the first effective fracture length.

At least one of the first effective fracture length and the second effective fracture length may be 300 feet or less.

At least one of the first effective fracture length and the second effective fracture length may be 200 feet or less.

The first wellbore section may be spaced apart from the second wellbore section by a distance of less than 600 feet.

The first wellbore section may be spaced apart from the second wellbore section by a distance of less than 400 feet.

Each of the first and second sections of the wellbore may be a horizontal wellbore section.

The target formation may contain known hydrocarbon deposits.

The target formation may be located in an oil shale formation.

The natural resource may be a liquid hydrocarbon.

In one embodiment, a method for extracting natural resources comprises: forming a first fracture series from the first horizontal wellbore section by pressurizing the target formation with a first hydraulic fracturing fluid from the first horizontal wellbore section, wherein the first fracture series comprises a first fracture length protruding into the target formation; and simultaneously forming a second fracture series by pressurizing the target formation with a second hydraulic fracturing fluid of a second horizontal wellbore section spaced less than 800 feet from the first horizontal wellbore section and spaced apart from the first horizontal wellbore section and the target formation is positioned between the first horizontal wellbore section and the second horizontal wellbore section, wherein the first fracture series comprises a second fracture length protruding into the target formation.

The second horizontal wellbore section may be spaced apart from the first horizontal wellbore section by a distance of less than 400 feet.

Drawings

Fig. 1 depicts an example of simultaneous fracturing of a target formation from a first wellbore and a second wellbore, in accordance with aspects of the present disclosure.

Fig. 2 depicts a cross-sectional view of an example of a first wellbore and a second wellbore located in a subterranean formation, according to aspects of the present disclosure.

Fig. 3 depicts a cutaway view of an example of simultaneously hydraulically fracturing a target formation with a first shaft and a second shaft, according to aspects of the present disclosure.

Fig. 4 depicts a top cut view of an example of a subterranean formation after fracturing in a vertical well, according to aspects of the present disclosure.

Fig. 5 depicts a top cross-sectional view of an example of a fractured subsurface formation in a horizontal well, according to aspects of the present disclosure.

Fig. 6 depicts an example of hydraulically fracturing a target formation according to aspects of the present disclosure.

Fig. 7 depicts an example of hydraulically fracturing a target formation with a first well and a second well, in accordance with aspects of the present disclosure.

Detailed Description

For the purposes of this disclosure, the term "aligned" refers to being parallel, substantially parallel, or forming an angle of less than 35.0 degrees. For purposes of this disclosure, the term "lateral" refers to perpendicular, substantially perpendicular, or an angle formed between 55.0 degrees and 125.0 degrees. Additionally, for the purposes of this disclosure, the term "length" refers to the longest dimension of an object. Additionally, for the purposes of this disclosure, the term "width" refers to the dimension from one side of the object to the other side of the object. Typically, the width of the object is transverse to the length of the object. For purposes of this disclosure, "effective fracture length" generally refers only to the portion of the fracture corresponding to having a cumulative gas flow rate from the formation to the wellbore of 90.0%.

For purposes of this disclosure, the term "horizontal wellbore section" generally refers to a wellbore having a wellbore section aligned with a rock layer containing natural resources to be extracted. Generally, the horizontal section is an end section of the wellbore and may be referred to as a "lateral section". In some cases, more than one horizontal lateral section may be drilled from the same wellsite and share a common vertical section with other lateral sections. In other cases, each of the horizontal wells does not share the same vertical section, but rather are drilled at different surface locations. In some examples, the horizontal wellbore may extend approximately 2,000 feet or more. In contrast, a silo is typically much shorter. Horizontal drilling reduces the surface footprint since fewer wells are involved in accessing the same volume of rock. Generally, horizontal wells are in contact with more rock with natural resources and can have higher productivity over a longer period of time.

Hydraulic fracturing may be used to increase the production of natural resources (such as oil, water, or natural gas) extracted through a wellbore. In some cases, hydraulic fracturing can maintain the same production rate at a lower cost to optimize economic production of the well. Hydraulic fracturing may increase initial production, estimated ultimate recovery of the well, or increase another aspect of well production. Hydraulic fracturing can also be used for: such as completing a first completion in the target zone; re-completing the well, such as completing the well in another portion of the well; re-fracturing the well, such as re-fracturing the well in an initial completion or a re-completion; deepening a well, such as when drilling deeper and completing the completion of that portion of the well with a smaller diameter; re-drilling, such as drilling another well next to the existing well, re-drilling while at another drilling or completion task, or a combination thereof.

Natural resources may be located in different types of rock, such as sandstone, limestone, dolomite, shale, coal beds, other types of formations, or combinations thereof. Hydraulic fracturing may be applied in rock formations located below the water level of a groundwater reservoir. At these depths, the permeability in the reservoir may not be sufficient to allow gas and oil to flow from the rock into the wellbore with the desired rate of return. By fracturing the rock, the permeability of the formation is increased, thereby improving the production of natural resources.

The location of one or more fractures along the length of the borehole can be determined by different methods. One such method includes forming a hole in a wellbore casing using a perforating gun.

Hydraulic fractures may be formed by injecting a fracturing fluid into a wellbore through perforations in the wellbore at a sufficiently high pressure. This pressurized fluid increases the pressure of the subterranean formation to the level of rock fracturing. As the rock cracks, fractures form allowing the fracture fluid to penetrate deeper into the rock, thereby forcing the formation pressure deeper and deeper into the formation, further enlarging the fracture. The hydraulic fluid may include a proppant (e.g., sand, ceramic, or other particles) that remains in the fracture and prevents the fracture from closing after the hydraulic fluid is drained from the formation. The propped fracture maintains an increased permeability to allow natural resources to flow to the well.

Equipment that may be used for hydraulic fracturing may include slurry mixers, one or more high pressure high capacity fracturing pumps, monitoring units, units for storing and treating proppants, chemical additive units, low pressure flexible hoses, and gauges and meters for flow, fluid density, and treatment pressure.

Any suitable type of fracturing fluid may be used in accordance with the principles described in this disclosure. In some examples, the fracturing fluid includes a slurry of water, proppant, and chemical additives. In some cases, the fracturing fluid may also include a gel, foam, and compressed nitrogen, compressed carbon dioxide, compressed air, another type of compressed gas, hydrochloric acid, acetic acid, sodium chloride, polyacrylamide, ethylene glycol, borate, zirconium salts, chromium salts, antimony salts, titanium salts, other types of salts, sodium carbonate, potassium carbonate, glutaraldehyde, guar gum, citric acid, isopropyl alcohol, methanol, isopropyl alcohol, 2-butoxyethanol and ethylene glycol, aluminum phosphate, and ester oils, or combinations thereof. The fracturing fluid may be between 85.0% to 95.0% liquid or gas, between 5.5% and 9.5% proppant, and between 1.0% to 0.25% chemical additives.

In other examples, the fracturing fluid may be gel, foam, or slickwater-based. Gels may be useful in situations where the proppant is difficult to keep in suspension. Slickwater, which is less viscous and has lower friction, can cause fluids to be pumped at higher rates, creating fractures further from the wellbore.

Any suitable proppant may be used in accordance with the principles described in this disclosure. In some cases, the proppant may be a particulate material, such as sand or a synthetic material, that may prevent the fracture from closing after the target formation is pressurized. The type of proppant may include silica sand, resin coated sand, bauxite, man-made ceramic, another type of proppant, or a combination thereof. Bauxite or ceramics may be used where the formation pressure is high enough to crush the natural silica sand.

Subsurface pressure and fracture growth rate may be measured during the hydraulic fracturing process. Alternatively, the fracture may be modeled by length and width using known geological features.

The injection profile and the location of the formed fracture can be determined using a radioactive tracer. Any suitable radiotracer may be used in accordance with the principles described in this disclosure. A suitable radioisotope chemically bound to at least some of the proppants may also be injected into the formation with the hydraulic fluid to trace the fracture. In some examples, some proppants may be coated with an isotope of silver, an isotope of iridium, an isotope of technetium, an isotope of iodine, another suitable type of isotope, or a combination thereof to track fracture profiles and/or flow rates of hydraulic fluid.

The temperature of the well may be monitored at different lengths, which facilitates determination of the location and associated volume of the fracturing fluid. This data may be transmitted to the surface in real time using fiber optic cables, wired pipes, or other types of communication systems. In other examples, the data may be retrieved after the fracturing procedure and analyzed thereafter.

Horizontal wellbores may be useful in shale formations where production from horizontal wellbores tends to be more economical than vertical wells. In a cemented or non-cemented wellbore, shale may be fractured in the wellbore by a plug and perforation method. The wireline tool may be lowered to a first position in the wellbore to perforate the wellbore. After the wellbore has been perforated, a fracturing fluid is pumped into the formation. Another plunger is then placed in the well to temporarily close off the previously pressurized section of the wellbore so that the next section of the wellbore can be perforated and then pressurized with hydraulic fracturing fluid. This process is repeated along the horizontal length of the wellbore. The fractures form channels in the rock, allowing hydrocarbons to flow from the rock to the wellbore for production. The low permeability of shale reservoirs results in the relative immobilization of hydrocarbon molecules in the reservoir.

In other examples, the sliding sleeve is used to sequentially fracture the formation at different locations along the length of the wellbore. Once a stage has completed pressurizing the formation, the next sleeve is opened while the previous stage is isolated, and the process is repeated.

The number of stages used to hydraulically fracture the formation may vary depending on the formation targeted. In some cases, the hydraulic fracturing method may have a single hydraulic fracturing stage to greater than thirty hydraulic fracturing stages. Any suitable number of fracturing stages may be used in accordance with the present disclosure.

When the subterranean formation is pressurized, fractures form along the path of least resistance. Each time a single wellbore is hydraulically fractured, the fractures may radiate outward from the wellbore in a single direction or in multiple directions. The entire length of the fracture may extend a considerable distance, but the proppant may not extend as far as the entire length of the fracture. Further, the entire length of the fracture may not cause the formation to separate out a meaningful amount to increase the permeability of the target formation. Generally, only a sub-portion of the fracture length results in increased contact with the formation, thereby increasing production. The portion of the fracture length that accounts for 90.0% of the increased flow rate through the target formation may be referred to as the effective fracture length, which is typically below 300 feet.

During a hydraulic fracturing treatment, the propagation of the fracture is controlled by the in situ stresses in the rock. The crack will generally propagate in a direction perpendicular to the least principal stress. Each time a single well bore is hydraulically fractured, multiple fractures may be launched outward in multiple directions near the well, but as the fractures gradually diffuse outward from the well bore, the fractures tend to converge together. Fractures propagating in one direction tend to be long, but do not necessarily contact large volumes of rock.

Since rock resists fracturing in complex patterns, maximization of fracture density (sometimes referred to as reservoir modification volume (SRV)) can be a difficult task, with fracture behavior being governed by the stresses of the earth. Rock tends to fracture in the direction of the greatest principal stress.

The principles described herein include: the simultaneous pumping of a fracturing treatment into two or more adjacent wellbores where the fracturing stages are azimuthally arranged along a fracture artificially increases the pressure of the target formation at a local zone, resulting in increased fracturing complexity, further resulting in increased reservoir modification volume and increased well productivity.

The pressure increase caused by simultaneous fracturing operations need not overcome both the minimum and maximum stresses. Instead, the pressure increase need only exceed the minimum stress by a certain percentage to initiate growth of the complex fracture away from the initial fracture. In other words, where fractures are simultaneously located on multiple sides of the target formation and the first and second wellbores are sufficiently close to each other, the fractures diverge from each other rather than converge into a single trunk fracture.

By simultaneously fracturing the target formation along the azimuthal fracture direction to localize the pressure, the perforated fractures develop a complex network of fractures that diffuse outward rather than converging the fractures into a single trunk fracture that occurs only at each fracturing of a single wellbore. The increase in fracture network complexity results in higher well production.

While fracturing the target formation between wells may be more strongly fractured, other complex fractures may expose more rock for production. The simultaneous hydraulic fractures arise from wellbores that are close to the target formation, such that the effective fracture lengths from each wellbore may spatially overlap. The pressure generated by the first well affects the fracture from the second well, and the pressure generated by the second well affects the fracture from the first well. Thus, pressure from the first well prevents the fractures from the second well from converging into a single main fracture, and pressure from the second well prevents the fractures from the first well from converging into a single main fracture. Thus, fracture propagation forms a larger and more complex fracture network, increasing contact with more target formations.

Referring now to the specific examples of the drawings, fig. 1 depicts an example of simultaneously hydraulically fracturing a formation of interest 100 from a first wellbore 102 and a formation of interest 100 from a second wellbore 104. In this example, first wellbore 102 includes a first wellbore section 106 extending horizontally from a first vertical section 108. Additionally, in this example, second wellbore 104 includes a second wellbore section 110 that extends horizontally from a second vertical section 112. The target formation 100 is between a first wellbore section 106 and a second wellbore section 110. A first subset 114 of the fractures emanate from the first wellbore 102 and a second subset 116 of the fractures emanate from the second wellbore 104. As depicted in the example of fig. 1, the fissures from the first subset 114 and the fissures from the second subset 116 overlap one another. In some cases, the fractures from the first subset and the fractures from the second subset are interconnected.

Further, the fractures of the first subset 114 propagate toward the second wellbore 104, and the fractures of the second subset 116 propagate within the target formation 100 toward the first wellbore 102. The fractures of the first subset and the fractures of the second subset within the target formation may propagate without converging into a trunk fracture direction. However, those fractures emanating from the distal sides 118 of the first and

second wellbores

102, 104 may include fractures converging into a single main trunk fracture. On the other hand, at least some of the fractures within the target formation 100 may even be dispersed from one another. It is believed that the pressure increase from first wellbore 102 and the pressure increase from second wellbore 104, when released simultaneously, may cause more destructive damage to the target formation than if each wellbore were used to hydraulically fracture the formation at different times.

Each of the first wellbore 102 and the second wellbore 104 may be perforated using a perforating gun or using another suitable mechanism. Clusters of perforations of the first wellbore 102 formed by the perforating gun may be aligned with clusters of perforations of the second wellbore 104. The fracture stage 120 may be a zone along the length of the wellbore that is pressurized during a hydraulic fracturing event and may contain clusters of perforations. The fracturing stages 120 of the first wellbore 102 may be aligned with the fracturing stages 120 of the second wellbore 104. In some examples, while the first and

second wellbores

102, 104 may include multiple fracturing stages that require pressurization, only one of the stages may be pressurized at a time within the same wellbore. In some cases, stages within a single wellbore may be fractured sequentially along the length of the wellbore while still simultaneously fracturing with aligned stages of other wellbores.

However, the fracture stages 120 of the first wellbore 102 that are aligned with the fracture stages 120 of the second wellbore 104 may be triggered simultaneously. Where the aligned fracturing stages are triggered simultaneously, the pressure between the aligned stages forces the pressure released from the first wellbore 102 to interact with the pressure released from the second wellbore 104 due to the proximity of the hydraulic fracturing stages.

The stage length may be any suitable length. In some examples, at least one of the stage lengths is less than 150 feet, less than 200 feet, less than 250 feet, less than 300 feet, less than 400 feet, or less than another suitable distance.

In the example of fig. 1, the first wellbore section and the second wellbore section are horizontal sections positioned at different elevations. In this example, the first wellbore section is located deeper within the earth than the second wellbore section. The target formation is positioned between different elevations of the first wellbore section and the second wellbore section. In this example, the first wellbore section and the second wellbore section may be positioned within the same formation, such as a porous petroliferous rock layer. In other examples, the first wellbore section and the second wellbore section may be positioned in different rock formations, or even different types of rock formations.

Fig. 2 depicts an example of a first horizontal wellbore section 200 and a second horizontal wellbore section 202 within the same formation 204. In this example, first wellbore section 200 and second wellbore section 202 are generally located at the same earth depth. However, in other examples, the first wellbore section 200 and the second wellbore section 202 may be located at different depths, but still be horizontally spaced within the same formation 204.

First and

second wellbore sections

200, 202 may be spaced apart by any suitable distance that enables the pressures resulting from fracturing different wellbores simultaneously to prevent fractures from converging to a main trunk fracture and/or direction. In some examples, the first wellbore section is separated from the second wellbore section by a distance of less than 800 feet. In some cases, the first wellbore section is separated from the second wellbore section by a distance of less than 600 feet. Further, the first wellbore section may be separated from the second wellbore section by a distance of less than 400 feet.

As the pressure in the formation subsides after pressurization, the proppant in the hydraulic fracturing fluid remains in the formation, keeping the fractures open. With the fractures remaining open, natural resources within the formation may move toward first wellbore section 200 or toward second wellbore section 202. In some cases, the formation 204 containing natural resources is a shale material containing oil within the shale pores. Downhole pressure may cause oil in the pores to move toward lower pressure regions, such as toward the wellbore in fractures. This pressure differential may cause oil to move from the subterranean formation into the wellbore and toward the surface where it may be collected.

Fractures formed on the target side 206 of the wellbore may be included in those fractures that synergistically fracture more rock, while those fractures on the far side 208 of the wellbore may converge into a single trunk fracture 210.

FIG. 3 depicts an example of a first vertical wellbore 300 and a second vertical wellbore 302, wherein a first stage 304 of the first wellbore 300 is fractured simultaneously with a second stage 306 of the second wellbore 302. The first stage 304 and the second stage 306 are aligned with each other along a trunk direction of the target formation. In some examples, the first stage 304 and the second stage 306 of the simultaneous fracture are located at the same depth, substantially the same depth, or within 5.0% of the same depth. In some cases, the first stage 304 and the second stage 306 are located in the same mineral bearing formation.

In other examples, the first wellbore may be a vertical wellbore and the second wellbore may be a horizontal wellbore. In this example, the first stage of the first wellbore may still be aligned with the second stage of the second wellbore. When they are fractured simultaneously, collective pressurization may cause the fractures to spread without causing the fractures to converge into an aggregate toward a single fracture.

One advantage of fracturing rock with stages aligned azimuthally along the fracture is that a fracture network or fracture network is formed in both the direction of the maximum principal stress and the direction perpendicular to that stress. When the stages simultaneously fracture the formation but are misaligned, it is believed that pressure from the first well will cause fracturing from the second well to angle away from the hydraulic fracturing stage of the first well. Such misdirected fractures may not form a fracture network and may not increase the surface area of rock accessible to the first well or the second well. In contrast, misaligned simultaneously activated stages may be used to guide the fracture, but may not form an increased fracture network.

Fig. 4 depicts an example of a cutaway view of a first shaft 400 and a second shaft 402 as viewed from the surface of the earth. In this example, the fracture between the first silo 400 and the second silo 402 forms a fracture network 404. On the other hand, those fractures formed on the distal side 406 of the first and second wells 400, 402 are fewer and come together to form a single main trunk fracture.

Fig. 5 depicts an example of a cross-sectional view of a horizontal well 500 and a second horizontal well 502 as viewed from the earth's surface. In this example, the fractures between the first horizontal well 500 and the second horizontal well 502 form a fracture network 504. On the other hand, those fractures formed on the distal side of the first well 500 and the second well 502 are fewer and come together to form a single main trunk fracture.

FIG. 6 shows a flow chart illustrating a method 600 of simultaneously fracturing a target formation. The operations of method 600 may be implemented by any of the hydraulic fracturing systems described in fig. 1-5 or their components as described herein. In this example, the method 600 includes forming a fracture series from each of the different wells having effective fracture lengths that overlap one another by simultaneously pressurizing a target formation on opposite sides with hydraulic fracturing fluid through the different wells to form a fracture network in the target formation (602).

At block 602, the target formation is fractured by simultaneously pressurizing the target formation from two directions. The pressurization from the two sources is close enough to each other that the target formation is forced in some directions to compress and in other directions to pull, causing the induced fractures to spread out rather than to converge together. The effective fracture length of the fracture series from the first well and the effective fracture length of the fracture series from the second well are sufficiently deep into the target formation such that the effective fracture lengths may intersect one another.

FIG. 7 shows a flow chart illustrating a method 700 of simultaneously fracturing a formation of interest. The operations of method 700 may be implemented by any of the hydraulic fracturing systems described in fig. 1-5 or their components as described herein. In this example, the method 700 includes: forming a first fracture series from the first well by pressurizing the target formation with a first hydraulic fracturing fluid from the first well, wherein the first fracture series comprises a first effective fracture length protruding into the target formation (702); and simultaneously forming a second fracture series and the target formation positioned between the first well and the second well by pressurizing the target formation with a second hydraulic fracturing fluid from a second well spaced a distance apart from the first well, wherein the first fracture series includes a second effective fracture length protruding into the target formation and overlapping the first effective length (704).

At block 702, a first series of fractures from a first well is formed in a target formation by pressurizing the target formation with a first hydraulic fracturing fluid. This fracture series includes at least one effective fracture length protruding into the target formation. The effective fracture length may be the portion of the fracture corresponding to 90% of the particular fracture flow.

At block 704, a second fracture series from a second well is formed in the target formation by simultaneously pressurizing the target formation with a second hydraulic fluid. These fractures include effective fracture lengths that also project into the target formation. In the target formation, the effective fracture length of the first fracture series and the effective fracture length of the second fracture series may spatially overlap one another.

In some cases, the first hydraulic fluid and the second hydraulic fluid are the same type of fluid, substantially the same type of hydraulic fluid, or different types of hydraulic fluid. Further, in some cases, the volume of the first hydraulic fluid is the same, substantially the same, or different than the volume of the second hydraulic fluid. Alternatively, the amount of pressure induced by the first hydraulic fluid may be the same, substantially the same, or different than the amount of pressure induced by the second hydraulic fluid.

In some examples, simultaneously forming fractures from the first well and the second well may include triggering hydraulic fracturing events in the two wells at exactly the same time. In some cases, simultaneously forming fractures from the first well and the second well may include triggering a hydraulic fracturing event in the two wells at: within 1 minute of each other, within 5 minutes of each other, within 10 minutes of each other, within 15 minutes of each other, within 25 minutes of each other, within another suitable period of time, or a combination thereof.

In other examples, forming fractures from the first well and the second well simultaneously includes different trigger start times, but there are at least some time periods during which pressure from the first well and pressure from the second well increase simultaneously. For example, in some cases, the target formation may be pressurized from a base formation pressure to a peak formation pressure from the first well over a certain period of time. This period of time may be referred to as a first pressurization period. Likewise, the target formation may be pressurized from the base formation pressure to the peak formation pressure from the second well over a period of time. This second period of time may be referred to as a second pressurization period. Thus, for purposes of the present disclosure, simultaneously forming a fracture in the target formation from the first well and a fracture in the target formation from the second well may include having at least some time overlap between the first and second periods of pressurization.

In another example, simultaneously forming fractures from the first well and the second well includes having at least some time periods during which pressure from the first well and pressure from the second well increase simultaneously. In this example, the target formation remains in a pressurized increased state even after the peak pressure is reached. After the peak pressure is reached, the pressure in the target formation may decrease but still have a high pressure above the base formation pressure, resulting in hydraulic fluid flowing from the first well or the second well. Fractures may form even after the formation pressure is reduced. After a certain point, the formation pressure may return to or fall below the base formation pressure. The period of time in which the target formation initially increases in pressure from the base formation pressure and returns to at least 50% of the base pressure from the hydraulic fluid from the first well may be referred to as a first high pressure period. Similarly, the period of time during which the target formation initially increases in pressure from the base formation pressure and returns to at least 50% of the base pressure from hydraulic fluid from the second well may be referred to as a second high pressure period. In some examples, simultaneously forming fractures from the first well and the second well may include having a temporal overlap between the first high pressure time period and the second high pressure time period.

In another example, simultaneously forming fractures from the first well and the second well may refer to a period of time during which fractures are still formed in the target formation due to hydraulic fracturing. In some cases, as the target formation is pressurized, stresses in the target formation may cause the formation to move, thereby forming fractures, but as the formation is depressurized, the target formation may still move, thereby causing other fractures.

It should be noted that the above method describes possible embodiments, and that operations and steps may be rearranged or modified, and that other embodiments are possible. Further, various aspects from two or more methods may be combined.

The description is provided to enable any person skilled in the art to make or use the disclosure. Various modifications to the disclosure will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other variations without departing from the scope of the disclosure. Thus, the present disclosure is not intended to be limited to the examples described herein but is to be accorded the widest scope consistent with the principles and novel features disclosed herein.

Claims

1. A method for extracting natural resources, comprising:

a fracture network is formed in a formation of interest by simultaneously pressurizing the formation of interest on opposite sides with hydraulic fracturing fluid through different wells, thereby forming a series of fractures having effective fracture lengths that overlap one another from each of the different wells.

2. The method of claim 1, wherein the effective fracture length is 300 feet or less from each of the different wells.

3. The method of claim 2, wherein the effective fracture length is 200 feet or less from each of the different wells.

4. The method of claim 1, wherein the different wells are spaced apart from each other by a distance of less than 600 feet.

5. The method of claim 1, wherein the different wells are spaced apart from each other by a distance of less than 400 feet.

6. The method of claim 5, wherein each of the different wells is a horizontal well.

7. The method of claim 1, wherein the target formation comprises known hydrocarbon deposits.

8. The method of claim 1, wherein the target formation is in an oil shale formation.

9. The method of claim 1, wherein the target formation is between the different wells.

10. A method for extracting natural resources, comprising:

forming a first fracture series from a first wellbore section by pressurizing a target formation with a first hydraulic fracturing fluid from the first wellbore section, wherein the first fracture series comprises a first effective fracture length protruding into the target formation; and is

Simultaneously forming a second fracture series by pressurizing the target formation with a second hydraulic fracturing fluid from a second wellbore section spaced a distance from the first wellbore section and the target formation being positioned between the first wellbore section and the second wellbore section, wherein the first fracture series comprises a second effective fracture length protruding into the target formation and overlapping the first effective fracture length.

11. The method of claim 10, wherein at least one of the first effective fracture length and the second effective fracture length is 300 feet or less.

12. The method of claim 11, wherein at least one of the first effective fracture length and the second effective fracture length is 200 feet or less.

13. The method of claim 10, wherein the distance is less than 600 feet.

14. The method of claim 10, wherein the distance is less than 400 feet.

15. The method of claim 14, wherein each of the first and second sections of wellbore is a horizontal section of wellbore.

16. The method of claim 10, wherein the target formation comprises known hydrocarbon deposits.

17. The method of claim 10, wherein the target formation is in an oil shale formation.

18. The method of claim 10, wherein the natural resource is a liquid hydrocarbon.

19. A method for extracting natural resources, comprising:

forming a first fracture series from a first horizontal wellbore section by pressurizing a target formation with a first hydraulic fracturing fluid from the first horizontal wellbore section, wherein the first fracture series comprises a first fracture length protruding into the target formation; and is

Simultaneously forming a second fracture series by pressurizing the target formation with a second hydraulic fracturing fluid from a second horizontal wellbore section spaced less than 800 feet from the first horizontal wellbore section and the target formation is positioned between the first horizontal wellbore section and the second horizontal wellbore section, wherein the first fracture series comprises a second fracture length protruding into the target formation.

20. The method of claim 19, wherein the second horizontal wellbore section is spaced less than 400 feet from the first horizontal wellbore section.