Patent Application
20190249527
Hydraulic fracturing is a technique for fracturing a subterranean formation with a pressurized liquid. The process involves injecting fluid under high pressure into a wellbore to fracture the rock of the subterranean formation. The liquid propagates throughout the fractures. When the liquid is removed, the fractures stay open because sand or other types of proppants suspended in the fracturing fluid remain in the fractures and keep the fractures from closing. The open fractures provide greater access to natural resources such as natural gas and liquid petroleum and allow these natural resources to flow easier within the subterranean formation to the well bore for recovery.
One method of hydraulic fracturing is disclosed in U.S. Pat. No. 4,724,905 issued to Duane C. Uhri, et al. In this reference, a process for sequential hydraulic fracturing of a hydrocarbon fluid-bearing formation. A fracture is induced in said formation by hydraulically fracturing via one wellbore. Thereafter, while the formation remains pressurized from the first induced-fracture operation, a second hydraulic fracturing operation is conducted via another wellbore substantially within the pressurized formation area of the first fracturing operation which causes a fracture trajectory to form contrary to the far-field in-situ stresses. This second hydraulic fracture will tend to curve away from the first hydraulic fracture and has the potential of intersecting natural hydrocarbon fluid-bearing fractures in said formation.
One method of hydraulic fracturing is disclosed in U.S. Pat. No. 4,830,106 issued to Duane C. Uhri, et al. A process and apparatus for simultaneous hydraulic fracturing of a hydrocarbonaceous fluid-bearing formation. Fractures are induced in said formation by hydraulically fracturing at least two wellbores simultaneously. While the formation remains pressurized curved fractures propagate from each wellbore forming fracture trajectories contrary to the far-field in-situ stresses. By applying simultaneous hydraulic pressure to both wellbores, at least one curved fracture trajectory will be caused to be transmitted from each wellbore and intersect a natural hydrocarbonaceous fracture contrary to the far-field in-situ stresses. Each of these references may be incorporated by reference for all that they teach.
In one embodiment, a method for extracting a natural resource includes creating a fracture network in a target formation by simultaneously pressurizing the target formation on opposing sides with hydraulic fracturing liquid through different wells creating a series of fractures from each of the different wells with effective fracture lengths that overlap with each other.
The effective fracture lengths may be 300 feet or less from each of the wells.
The effective fracture lengths may be 200 feet or less from each of the wells.
The different wells may be spaced apart from each other at a distance of less than 600 feet.
The different wells may be spaced apart from each other at a distance of less than 400 feet.
Each of the different wells may be horizontal wells.
The target formation may include a known hydrocarbon deposit.
The target formation may be in an oil shale formation.
The natural resource may be a liquid hydrocarbon.
The target formation may be between the different wells.
In some embodiments, a method for extracting a natural resource includes creating a first series of fractures from a first well bore section by pressurizing a target formation with a first hydraulic fracturing liquid from a first well bore section where the first series of fractures includes a first effective fracture length that protrudes into the target formation, and simultaneously creating a second series of fractures by pressurizing the target formation with a second hydraulic fracturing liquid from a second well bore section that is spaced apart from the first well bore section at a distance and the target formation is located between the first and the second well bore section where the first series of fractures includes a second effective fracture length that protrudes into the target formation and overlaps with the first effective 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 well bore section may be spaced apart from the second well bore section at a distance of less than 600 feet.
The first well bore section may be spaced apart from the second well bore section at a distance of less than 400 feet.
Each of the first well bore section and the second well bore section may be horizontal well bore sections.
The target formation may include a known hydrocarbon deposit.
The target formation may be in an oil shale formation.
The natural resource may be a liquid hydrocarbon.
In one embodiment, a method for extracting a natural resource includes creating a first series of fractures from a first horizontal well bore section by pressurizing a target formation with a first hydraulic fracturing liquid from a first horizontal well bore section where the first series of fractures includes a first fracture length that protrudes into the target formation, and simultaneously creating a second series of fractures by pressurizing the target formation with a second hydraulic fracturing liquid from a second horizontal well bore section that is spaced apart from the first horizontal well bore section that is spaced away from the first horizontal well bore section less than 800 feet away and the target formation is located between the first and the second horizontal well bore section where the first series of fractures includes a second fracture length that protrudes into the target formation.
The second horizontal well bore section may be spaced less than 400 feet apart from the first horizontal well bore section.
For purposes of this disclosure, the term “aligned” means parallel, substantially parallel, or forming an angle of less than 35.0 degrees. For purposes of this disclosure, the term “transverse” means perpendicular, substantially perpendicular, or forming an angle between 55.0 and 125.0 degrees. Also, for purposes of this disclosure, the term “length” means the longest dimension of an object. Also, for purposes of this disclosure, the term “width” means the dimension of an object from side to side. Often, the width of an object is transverse the object's length. For the purposes of this disclosure, the “effective fracture length” generally refers to just the portion of the fracture that corresponds having 90.0% of the cumulative gas flow rate from the formation to the well bore.
For the purposes of this disclosure, the term “horizontal well bore section” generally involves wellbores with a section of the well bore aligned with the rock layer containing the natural resource to be extracted. Generally, the horizontal section is a terminal section of the well bore and may be referred to as a “lateral.” In some cases, more than one horizontal lateral may be drilled from the same well site and share a common vertical section with other laterals. In other cases, each of the horizontal wells do not share the same vertical section, but are drilled at different surface locations. In some examples, a horizontal well bore may extend nearly 2,000 feet or longer. In contrast, a vertical well is generally much shorter. Horizontal drilling reduces the surface footprint as fewer wells are involved to access the same volume of rock. Generally, horizontal wells make contact with more of the rock bearing the natural resource and may have greater production rates over a longer period of time.
Hydraulic fracturing may be used to increase the production of natural resources to be extracted through a well bore, such as petroleum, water, or natural gas. In some cases, hydraulic fracturing can optimize the economic production of the well by maintaining the same productions rates at a lower cost. Hydraulic fracturing may increase the initial production, the estimated ultimate recovery from the well, or increase another aspect of the well's production. Hydraulic fracturing may also be used in making a first completion, such as in the zone of interest; recompleting a well, such making a completion in another part of the well; refracturing the well, such as when re-stimulating a primary completion or a recompletion; deepening the well, such as when drilling the well deeper and completing that portion of well with a smaller diameter; re-drilling the well, such as when drilling another well next to an existing well, another drilling or completion task, or combinations thereof.
The natural resources may be located in different types of rocks, such as sandstones, limestones, dolomite rocks, shale rock, coal beds, other types of formations, or combinations thereof. Hydraulic fracturing can be applied in rock formations below the earth's groundwater reservoir levels. At these depths, there may be insufficient permeability in the reservoir to allow natural gas and oil to flow from the rock into the wellbore at desirable returns. By fracturing the rock, the permeability of the formation increases thereby improving the production of the natural resource.
The placement of one or more fractures along the length of the borehole can be determined by different methods. One type of method includes using a perforating gun to create holes in the well bore's casing.
A hydraulic fracture may be formed by injecting a fracturing fluid into a wellbore with a high enough pressure through the well bore's perforations. This pressurized fluid increases the subterranean formation's pressure to a level where the rock fractures. As the rock cracks, fissures are created that allows the fracture fluid to permeate deeper into the rock and thereby increasing the formation pressure deeper and deeper into the formation thereby extending the cracks further. The hydraulic fluid may include a proppant (e.g. grains of sand, ceramic, or other particulate) that remain in the fractures after the hydraulic fluid has drained out of the formation and prevent the fractures from closing. The propped fracture maintains an increased permeability to allow the flow of the natural resource to the well.
Equipment that may be used in hydraulic fracturing may include a slurry blender, one or more high-pressure, high-volume fracturing pumps, a monitoring unit, units for storage and handling of proppant, a chemical additive unit, low-pressure flexible hoses, and gauges and meters for flow rate, fluid density, and treating pressure.
Any appropriate type of fracturing fluid may be used in accordance with the principles described in the present 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 gels, foams, and compressed nitrogen, compressed carbon dioxide, compressed air, another type of compressed gas, hydrochloric acid, acetic acid, sodium chloride, polyacrylamide, ethylene glycol, borate salts, zirconium salts, chromium salts, antimony salts, titanium salts, other types of salts, sodium carbonates, potassium carbonates, glutaraldehyde, guar gum, citric acid, isopropanol, methanol, isopropyl alcohol, 2-butoxyethanol, and ethylene glycol, aluminum phosphate and ester oils or combinations thereof. The fracturing fluid may be between 85.0 percent to 95.0 liquid or gas, between 5.5 percent and 9.5 percent proppant, and 1.0 to 0.25 percent chemical additives.
In other examples, the fracturing fluid may be a gel, a foam, or be slickwater-based. Gels may be useful in situations where it would otherwise be difficult to keep the proppant in suspension. Slickwater, which is less viscous and has a lower friction, may allow fluid to be pumped at higher rates which allows fractures to be created farther out from the wellbore.
Any appropriate proppant may be used in accordance with the principles of described in the present disclosure. In some cases, the proppant may be a granular material, such as sand or a synthetic material that prevents the fractures from closing after the target formation is pressurized. Types of proppant may include silica sand, resin-coated sand, bauxite, man-made ceramics, another type of proppant, or combinations thereof. Bauxite or ceramics may be used in situations where the formation pressure is high enough to crush natural silica sand.
The subterranean pressure and fracture growth rate may be measured during the hydraulic fracturing process. Additionally, known geological features can be used to model the fractures by length and width.
Radioactive tracers can be used to determine the injection profile and location of created fractures. Any suitable radiotracers may be used in accordance with the principles described in the present disclosure. Suitable radioactive isotopes chemically bonded to at least some of the proppant may also be injected into the formation with the hydraulic fluid to track fractures. In some examples, some of the proppant may be coated with isotopes of silver, isotopes of iridium, isotopes of technetium, isotopes of iodine, another appropriate type of isotope, or combinations thereof to track the fracture profiles and/or flow rates of the hydraulic fluid.
The temperature of the well may be monitored at different lengths, which assists in determining where the fracturing fluid is located and the associated volumes. Fiber optic cable, wired pipe, or other types of communication systems may be used to transmit this data to the surface in real time. In other examples, the data may be retrieved after the fracturing procedure and analyzed at a later time.
Horizontal wellbores can be useful in shale formations where horizontal wellbores tend to produce more economically than with a vertical well. Shales may be fractured by the plug and perforation method in the well bore either in a cemented or uncemented well bore. A wireline tool may be lowered into the well bore at a first stage location to perforate the well bore. With the well bore perforated, the fracturing fluid is pumped into the formation. Next, another plug is set in the well to temporarily seal off the previously pressurized section of the well bore so the next section of the wellbore can be perforated and then pressurized with the hydraulic fracturing fluid. The process is repeated along the horizontal length of the wellbore. Fracturing creates pathways in the rock, allowing for hydrocarbons to flow from the rock to the wellbore for production. The low permeability in the shale reservoirs results in hydrocarbon molecules that are relatively immobile in the reservoir.
In other examples, sliding sleeves are used to sequentially fracture the formation at different locations along the length of the well bore. Once one stage has finished the pressurizing the formation, the next sleeve is opened, concurrently isolating the previous stage, and the process repeats.
The number of stages used to hydraulically fracture the formation may vary from target formation to target formation. In some cases, a hydraulic fracturing method may have a single hydraulic fracturing stage to greater than thirty hydraulic fracturing stages. But, any appropriate number of fracturing stages may be used in accordance with the present disclosure.
When the subterranean formation is pressurized, the fracture is created along the path of least resistance. The fracture may radiate out from the well bore in a single direction or in multiple directions when a single well bore is hydraulically fractured at a time. The entire fracture length may stretch a substantial distance, but the proppant may not travel as far as the entire length of the fracture. Further, the entire length of the fracture may not cause the formation to separate a meaningful amount to increase the permeability of the target formation. Generally, just a sub-portion of the fracture length results in increasing contact with the formation to yield an increase in production. That portion of the fracture length that contributes to 90.0 percent of the increased flow through the target formation may be referred to as an effective fracture length and is generally under 300 feet long.
Propagation of fractures during hydraulic fracturing treatments is governed by in-situ stresses in the rock. Fractures will generally propagate in a direction perpendicular to the least principal stress. Close to the well, multiple fractures may emanate outward in multiple directions when a single well bore is hydraulically fractured at a time, but those fractures tend to converge together as the fractures progress outward away from the well bore. Fractures propagating in one direction tend to be long, but do not necessarily contact high volumes of rock.
Maximizing fracture density, sometimes called stimulated reservoir volume (SRV), can be a difficult task because rock resists being fractured in a complex pattern. Fracture behavior is governed by stresses in the earth. Rock tends to fracture in the direction of maximum principal stress.
The principles described herein include simultaneously pumping a fracturing treatment into two or more adjacent wellbores with fracturing stages lined up along a fracture azimuth to artificially increase the pressure of the target formation at a localized area, resulting in a growth of fracture complexity, further resulting in higher stimulated reservoir volume and a more productive well.
The increase in pressure from the simultaneous fracturing operation would not need to overcome both minimum and maximum stresses. Rather, the increase in pressure just needs to exceed minimum stress by some percentage to start growing complex fractures away from the initial fracture. In other words, with the simultaneous fracturing on multiple sides of the target formation and with the first and second well bores in close enough proximity to each other, the fractures diverge from each other rather than converging to a single dominant fracture.
By simultaneously fracturing the target formation along the azimuth fracture direction to localize the pressure, the perforation fractures develop a complex network of fractures that spread outward rather than having the fractures converge to a single dominant fracture that occurs with just a single well bore that is fractured at a time. The increased complexity of the fracture network can result in greater well production.
Simultaneously fracturing the target formation between the wells may be fractured more intensely with additional complex fractures exposing more rock for production. The simultaneous hydraulic fractures are from well bores that are close to the target formation such that the effective fracture lengths from each of the well bores may spatially overlap. The pressure generated from the first well affects the fracture from the second well, and the pressure generated from the second well affects the fracture from the first well. Thus, the pressure from the first well prevents the fractures from the second well from converging to a single dominant fracture, and the pressure from the second well prevents the fractures from the first well to converge to a single dominant fracture. As a result, the fractures spreads creating a larger and more complex fracture network that increases the contact with more of the target formation.
Now referring to specific examples with the figures,
Further, the fractures of the first subset 114 propagate towards the second well bore 104, and fractures of the second subset 116 propagate forward towards the first well bore 102 within the target formation 100. Fractures of the first and second subsets within the target formation may propagate without converging into a dominant fracture direction. However, those fractures that emanate out from the far sides 118 of the first and second well bores 102, 104 may include fractures that converge into a single dominant fracture. On the other hand, at least some of the fractures within the target formation 100 may even diverge from each other. It is believed that the pressure increase from the first well bore 102 and the pressure increase from the second well bore 104 create more destructive damage to the target formation when released simultaneously than would otherwise occur if each of the well bores were used to hydraulically fracture the formation at separate times.
Each of the first and second well bores 102, 104 may be perforated with a perforation gun or with another appropriate mechanism. The perforated clusters formed by the perforation guns of the first well bore 102 may be aligned with the perforation clusters of the second well bore 104. The fracturing stage 120 may be the area along the length of the well bores that is pressurized during a hydraulic fracturing event and may encompass the perforated clusters. The fracturing stage 120 of the first well bore 102 may be aligned with the fracturing stage 120 of the second well bore 104. In some examples, while the first and second well bores 102, 104 may include multiple fracturing stages to be pressurized, just one of the stages may be pressurized at a time within the same well bore. In some cases, the stages within a single well bore may be fractured sequentially along the length of the well bore while still being fractured simultaneously with the aligned stages of the other well bore.
However, the fracturing stage 120 of the first well bore 102 that is aligned with the fracturing stage 120 of the second well bore 104 may be triggered simultaneously. With the aligned fracturing stages being triggered at the same time, the pressure between the aligned stages forces the pressures released from the first well bore 102 to interact with the pressures released from the second well bore 104 due to the proximity of the hydraulic fracturing stages.
The stage lengths may be any appropriate 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 appropriate distance.
In the example of
The first well bore section 200 and the second well bore section 202 may be spaced apart at any appropriate distance that allows the pressures from the simultaneous fracturing of the different well bores to prevent the convergence of the fractures to a dominant fracture and/or direction. In some examples, the first well bore section is spaced at a distance of less than 800 feet from the second well bore section. In some cases, the first well bore section is spaced at a distance of less than 600 feet from the second well bore section. Further, the first well bore section may be spaced at a distance of less than 400 feet from the second well bore section.
As the pressure recedes in the formation after pressurization, the proppant in the hydraulic fracturing liquid remains behind keeping the fractures open. With the fractures remaining open, the natural resources within the formation may move towards either the first well bore section 200 or the second well bore section 202. In some cases, the strata 204 containing the natural resource is a shale material that contains oil within the pores of the shale. The downhole pressure may cause the oil in the pores to move towards areas lower pressure, such as in the fractures towards the well bores. This pressure differential may cause the oil to move from the subterranean formation into the well bore and move towards the surface where the oil can be collected.
The fractures formed on the target side 206 of the well bores may be included in those fractures that synergistically crack more rock while those fractures that are on the far side 208 of the well bores may converge into a single dominant fracture 210.
In other examples, the first well bore may be a vertical well bore and the second well bore may be a horizontal well bore. In such an example, the first stage of the first well bore may still be aligned with the second stage of the second well bore. When they are fractured simultaneously, the collective pressurization may cause the fractures to spread rather than allow the fractures to converge into a congregate towards a single fracture.
One advantage to fracturing the rock with stages that are aligned along the fracture azimuth is that a web or network of fractures in both the directions of maximum principle stress and perpendicular to that stress are created. Whereas when the stages fracture the formation simultaneously, but are misaligned, it is believed that the pressure from first well will cause the fractures from the second well to be angled away from the hydraulic fracturing stage of the first well. Such a misdirected fracture may not form the network of fractures and increase the surface area of the rock accessible to the either the first well or the second well. Rather, misaligning the stages that are activated simultaneously may be used to direct a fracture, but may not have the result of creating an increased fracture network.
At block 602, a target formation is fractured by simultaneously pressurizing the target formation from two directions. The pressurization from both sources is close enough to each other that the target formation is compressed in tension in some directions and pulled in tension in other directions such that the induced fractures are caused to spread out rather than converge together. The effective fracture lengths of the series of fractures from the first well and the series of fractures from the second well travel deep enough into the target formation that the effective fracture lengths may cross each.
At block 702, a first series of fractures from a first well are formed in a target formation by pressurizing the formation with a first hydraulic fracturing fluid. This series of fractures includes at least one effective fracture length that protrudes into the target formation. The effective fracture length may be that portion of a fracture that corresponds to 90 percent of the flow for that particular fracture.
At block 704, a second series of fractures from a second well are formed in a target formation simultaneously pressurizing the target formation with a second hydraulic fluid. These fractures include effective fracture lengths that also protrude into the target formation. The effective fracture lengths of the first series of fractures and the effective fracture lengths of the second series of fractures may spatially overlap each other in the target formation.
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 same as, substantially the same as, or different than the volume of the second hydraulic fluid. Additionally, the pressure induced with the first hydraulic fluid may be the same as, substantially the same as, or different than the amount of pressure induced with the second hydraulic fluid.
In some examples, simultaneously creating fractures from the first well and the second well may include triggering the hydraulic fracturing events in both wells at exactly the same time. In some cases, simultaneously creating fractures from the first well and the second well may include triggering the hydraulic fracturing events in both wells within one minute of each other, within five minutes of each other, within ten minutes of each other, within 15 minutes of each other, within 25 minutes of each other, within another appropriate time period, or combinations thereof.
In other examples, simultaneously creating fractures from the first well and the second well include different triggering start time, but that at least some period of time exists where the pressure from the first well and the pressure from the second well are increasing at the same time. For example, in some cases, pressurizing a target formation from a first well from a base formation pressure to a peak formation pressure may occur over a period of time. This period of time may be referred to as a first pressurization time period. Likewise, pressurizing the target formation from the second well from the base formation pressure to the peak formation pressure may also occur over a period of time. This second period of time may be referred to as a second pressurization time period. Thus, for the purposes of this disclosure, simultaneously creating fractures in the target formation from the first well and creating fractures in the target formation from the second well may include having at least some temporal overlap between the first pressurization time period and the second pressurization time period.
In another example, simultaneously creating fractures from the first well and the second well include having at least some period of time that exists where the pressure from the first well and the pressure from the second well are increased at the same time. In this example, the target formation remains in an increased pressurized state even after reaching a peak pressure. After reaching the peak pressure, the pressure in the target formation may diminish, but still have an elevated pressure above the base formation pressure resulting the hydraulic fluid from either the first well or the second well. Fractures may be created even after the formation pressure is diminishing. After some point, the formation pressure may return to the base formation pressure or drop below the base formation pressure. The time period in which the target formation initially increases pressure from the base formation pressure and returns to at least 50 percent of the base pressure from the hydraulic fluid from the first well may be referred to as the first elevated pressure time period. Similarly, the time period in which the target formation initially increases pressure from the base formation pressure and returns to at least 50 percent of the base pressure from the hydraulic fluid from the second well may be referred to as the second elevated pressure time period. In some examples, simultaneously creating fractures from the first well and the second well may include having a temporal overlap between the first elevated pressure time period and the second elevated pressure time period.
In another example, simultaneously creating fractures from a first well and a second well may refer to a time period in which fractures are still forming in the target formation as a result of the hydraulic fracturing. In some cases, as the target formation is pressurized, the stresses in the target formation cause the formation to move creating the fractures, but as the formation depressurizes the target formation may still move resulting in additional fractures.
It should be noted that the methods described above describe possible implementations, and that the operations and the steps may be rearranged or otherwise modified and that other implementations are possible. Furthermore, aspects from two or more of the methods may be combined.
The description herein is provided to enable a 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 disclosure is not limited to the examples described herein, but is to be accorded the broadest scope consistent with the principles and novel features disclosed herein.
