PROPPANT-FREE HYDRAULIC FRACTURING
A subterranean zone penetrated by a wellbore is hydraulically fractured. A well tool assembly is positioned within a casing installed in the wellbore. The well tool assembly includes a perforation tool and a resettable packer. The casing is perforated, such that fluid can be conducted from inside the casing to the subterranean zone through the perforations. The well tool assembly is positioned at a location within the casing that is downhole of the perforations. A portion of the casing that is downhole of the perforations is sealed with the resettable packer. A fracturing fluid is pulsed into the subterranean zone via the perforations by alternating between a first flow rate and a second flow rate. The second flow rate is in a range of from about 10% to about 40% of the first flow rate. The fracturing fluid is free of proppant.
This disclosure relates to hydraulically fracturing subterranean zones, and more specifically with proppant-free fracturing fluid.
BACKGROUNDHydraulic fracturing is a process of stimulating a well through one or more fractured rock formations. The process involves injection of a fracturing fluid into a wellbore to create fractures, so that fluids can flow more freely through the rock formation. Hydraulic fracturing can increase the mobility of trapped hydrocarbons and therefore increase recovery of hydrocarbons from a reservoir. There are challenges in hydraulic fracturing caused by wide variability of the propagation of the fractures within a subterranean zone. The propagation can depend on mechanical stresses in the reservoir and the fracture properties of the rocks.
SUMMARYThis disclosure describes technologies relating to hydraulically fracturing subterranean zones, and more specifically with proppant-free fracturing fluid. Certain aspects of the subject matter described can be implemented as a method for hydraulically fracturing a subterranean zone penetrated by a wellbore. A well tool assembly is positioned within a casing installed in the wellbore. The well tool assembly includes a perforation tool and a resettable packer. The casing is perforated with the perforation tool to form perforations in the casing, such that fluid can be conducted from inside the casing to the subterranean zone through the perforations. The well tool assembly is positioned at a location within the casing that is downhole of the perforations. A portion of the casing that is downhole of the perforations is sealed with the resettable packer from a remaining portion of the casing. A fracturing fluid is pulsed into the subterranean zone via the perforations by alternating between flowing the fracturing fluid into the casing at a first flow rate and flowing the fracturing fluid into the casing at a second flow rate. The first flow rate is equal to or less than 6 barrels per minute. The second flow rate is in a range of from about 10% to about 40% of the first flow rate. The fracturing fluid is free of proppant and has a viscosity that is substantially equal to that of water.
This, and other aspects, can include one or more of the following features.
The perforations can be a first cluster of perforations. The resettable packer can be unset to unseal the portion of the casing that is downhole of the first cluster of perforations. The well tool assembly can be positioned at a location within the casing that is uphole of the first cluster of perforations. The casing can be perforated with the perforation tool to form a second cluster of perforations in the casing uphole of the first cluster of perforations. The well tool assembly can be positioned at a location within the casing that is downhole of the second cluster of perforations. A portion of the casing that is downhole of the second cluster of perforations can be sealed with the resettable packer from a remaining portion of the casing. The fracturing fluid can be pulsed into the subterranean zone via the second cluster of perforations by alternating between flowing the fracturing fluid into the casing at the first flow rate and flowing the fracturing fluid into the casing at the second flow rate. The resettable packer can be unset to unseal the portion of the casing that is downhole of the second cluster of perforations.
The well tool assembly can remain within the casing throughout implementation of the method.
Each cluster of perforations can span a portion of the casing that is at most 1.5 meters in longitudinal length.
Each cluster of perforations can include at most 12 perforations.
The fracturing fluid can be flowed into the casing at the first flow rate for at most 5 minutes before alternating to the second flow rate.
The fracturing fluid can be flowed into the casing at the second flow rate for at most 1.5 minutes before alternating to the first flow rate.
Pulsing the fracturing fluid into the subterranean zone can include alternating between flowing the fracturing fluid into the casing at the first flow rate and flowing the fracturing fluid into the casing at the second flow rate, such that each of the first flow rate and the second flow rate occur at least 5 times.
Pulsing the fracturing fluid into the subterranean zone can include alternating between flowing the fracturing fluid into the casing at the first flow rate and flowing the fracturing fluid into the casing at the second flow rate until at least 2,000 barrels of fracturing fluid have been flowed into the subterranean zone via the respective cluster of perforations.
Certain aspects of the subject matter described can be implemented as a method for hydraulically fracturing a subterranean zone having a matrix permeability of at most 100 nanoDarcy and a clay content of at most 60 volume %. A fracturing fluid is injected into the subterranean zone at a first flow rate that is equal to or less than 6 barrels per minute. The fracturing fluid is free of proppant and has a viscosity that is substantially equal to that of water. The fracturing fluid is injected into the subterranean zone at a second flow rate that is in a range of from about 10% to about 40% of the first flow rate. The fracturing fluid is injected into the subterranean zone, alternating between the first flow rate and the second flow rate.
This, and other aspects, can include one or more of the following features.
The fracturing fluid can be injected into the subterranean zone at the first flow rate for at most 5 minutes.
The fracturing fluid can be injected into the subterranean zone at the second flow rate for at most 1.5 minutes.
The fracturing fluid can be injected into the subterranean zone, alternating between the first flow rate and the second flow rate at least 5 times.
The fracturing fluid can be injected into the subterranean zone, alternating between the first flow rate and the second flow rate until at least 2,000 barrels of fracturing fluid have been injected into the subterranean zone.
Certain aspects of the subject matter described can be implemented as a system for hydraulically fracturing a subterranean zone penetrated by a wellbore. The system includes a well tool assembly, a fracturing fluid, and a pump. The well tool assembly includes a perforation tool and a resettable packer. The perforation tool is configured to form perforations in a casing installed within the wellbore. The resettable packer is configured to reversibly seal a portion of the casing from a remaining portion of the casing while a fracturing fluid is injected into the subterranean zone via the perforations. The well tool assembly is configured to remain within the casing during hydraulic fracturing. The fracturing fluid is free of proppant and has a viscosity that is substantially equal to that of water. The pump is configured to flow the fracturing fluid into the subterranean zone via the perforations formed by the perforation tool by pulsing the fracturing fluid into the casing between a first flow rate and a second flow rate, thereby hydraulically fracturing the subterranean zone. The first flow rate is equal to or less than 6 barrels per minute. The second flow rate is in a range of from about 10% to about 40% of the first flow rate.
This, and other aspects, can include one or more of the following features.
The perforation tool can be configured to form the perforations in the casing across a portion of the casing that is at most 1.5 meters in longitudinal length.
The perforations can include a cluster of at most 15 perforations.
The details of one or more implementations of the subject matter of this disclosure are set forth in the accompanying drawings and the description. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.
This disclosure describes hydraulic fracturing stimulation of wells, and more specifically, of wells in ultra-low matrix permeability unconventional resources, such as shale. The matrix permeability of shale reservoirs can be 100 nanoDarcy (nD) or less (for example, 50 nD or less), and the clay content of such reservoirs can be 60 volume percent (vol. %) or less. The systems and methods described can be implemented to increase well productivity with smaller hydraulic fracturing fluid volumes injected at smaller flow rates without proppant in comparison to traditional methods. The systems and methods described can be implemented to induce reservoir self-propping, thereby allowing the reservoir to be fractured with a fracturing fluid that is free of proppant. Fractures in subterranean formations can be created by intermittent/pulsed injections of fracturing fluid (that is, alternating between different flow rates) to induce fracture tip degradation, elongation, and failure. The pulsed mechanism causes the shale reservoir rock to fail at lower stress than would be predicted from its natural mechanical strength, due to the induced fatigue by the pulsed injections.
To facilitate Continuous Multi-Stage Execution of Hydraulic Fracturing Stimulation, the present disclosure is conducted with a defined tool assembly to allow multiple stimulation stages to be completed. The elimination of proppant which is a hurdle in continuous multi-stage perforating operations opens limitless frac stages to be stimulated.
The subject matter described in this disclosure can be implemented in particular implementations, so as to realize one or more of the following advantages. The methods and systems described in this disclosure can be implemented to improve productivity of a well and increase the estimated ultimate recovery (EUR) of the well. Perforation of adjacent virgin zones along the lateral (for example, multi-stage perforating operations) can be continuous, that is, without interruptions (for example, interruptions associated with running perforation tools into and out of the wellbore between fracturing stages in conventional hydraulic fracturing operations). The use of a proppant-free fracturing fluid can require fewer fracturing service equipment than conventional hydraulic fracturing methods and systems. For example, implementation of the subject matter can eliminate the need for gel hydration units for transporting gel and mixing of the gel, the need for proppant storage and proppant delivery, and the need for high pressure pump trucks. The pulsed injections of the fracturing fluid can require less fracturing fluid volume to be used in comparison to conventional hydraulic fracturing methods and systems. Therefore, by implementing the methods and systems described in this disclosure, both capital and operational costs can be saved. By implementing the methods and systems described in this disclosure, conductive fractures can be created and remain in the zone of interest within the subterranean zone (in contrast to conventional hydraulic fracturing methods and systems that may create fractures that extend beyond the zone of interest). Keeping the conductive fractures in the zone of interest can lead to increased productivity and less costs. Utilizing a proppant-free, low viscosity fracturing fluid can reduce or eliminate the tendency of fracture growth (for example, beyond the zone of interest), hence facilitating long (that is, along the longitudinal axis of the wellbore) in-zone fractures, which can increase reservoir contact area and in turn, improve well productivity. The pulsed injections of the fracturing fluid induces cyclic loading that can enhance fracture tip fatigue and lateral extension, which can cause fracture surface area in the zone of interest to increase. Utilizing low viscosity fracturing fluids can eliminate the need of various additives (such as viscosifying agents) and can also conserve water. The methods and systems described in this disclosure can be implemented to eliminate the risks associated with screen out during hydraulic fracturing operations.
Referring back to
The wellbore of the well 100 is typically, although not necessarily, cylindrical. All or a portion of the wellbore is lined with a tubing, such as casing 112. The casing 112 connects with a wellhead at the surface 106 and extends downhole into the wellbore. The casing 112 operates to isolate the bore of the well 100, defined in the cased portion of the well 100 by the inner bore of the casing 112, from the surrounding Earth 108. The casing 112 can be formed of a single continuous tubing or multiple lengths of tubing joined (for example, threadedly and/or otherwise) end-to-end. In
The wellhead defines an attachment point for other equipment to be attached to the well 100. For example,
The fracturing fluid 150 is free of proppant. The fracturing fluid 150 has a viscosity that is substantially equal to that of water. In some implementations, the fracturing fluid 150 has a viscosity of 5 centipoise (cP) or less. In some implementations, the fracturing fluid 150 has a viscosity in a range of from approximately 0.85 cP to approximately 1.0 cP. The fracturing fluid 150 can include water. In some implementations, the fracturing fluid 150 includes one or more additives. Some non-limiting examples of suitable additives include friction reduces (such as polyacrylamide or low gel loading polymers), surfactants (such as non-ionic, cationic, and amphoteric surfactants), and clay stabilizers (such as potassium chloride and quaternary salts).
In particular, casing 112 is commercially produced in a number of common sizes specified by the American Petroleum Institute (the “API), including 4½, 5, 5½, 6, 6⅝, 7, 7⅝, 16/8, 9⅝, 10¾, 11¾, 13⅜, 16, 116/8 and 20 inches, and the API specifies internal diameters for each casing size.
The well 100 can also include a well tool apparatus 102 residing in the wellbore, for example, at a depth that is nearer to subterranean zone 110 than the surface 106. The apparatus 102 is of a type configured in size and robust construction for installation within the well 100. The apparatus 102 can be configured to fit in, and (as discussed in more detail below) in certain instances, seal to the inner diameter of one of the specified API casing sizes. Of course, the apparatus 102 can be made to fit in and, in certain instances, seal to other sizes of casing or tubing or otherwise seal to a wall of the well 100.
Additionally, the construction of the components of the apparatus 102 are configured to withstand the impacts, scraping, and other physical challenges the apparatus 102 will encounter while being passed hundreds of feet/meters or even multiple miles/kilometers into and out of the well 100. For example, the apparatus 102 can be disposed in the well 100 at a depth of up to 20,000 feet (6,096 meters). Beyond just a rugged exterior, this encompasses having certain portions of any electronics being ruggedized to be shock resistant and remain fluid tight during such physical challenges and during operation. Additionally, the apparatus 102 is configured to withstand and operate for extended periods of time (e.g., multiple weeks, months or years) at the pressures and temperatures experienced in the well 200, which temperatures can exceed 400° F./205° C. and pressures over 2,000 pounds per square inch, and while submerged in the well fluids (for example, gas, water, or oil). Finally, the apparatus 102 can be configured to interface with one or more of the common deployment systems 118, such as jointed tubing (that is, lengths of tubing joined end-to-end, threadedly and/or otherwise), a sucker rod, coiled tubing (that is, not-jointed tubing, but rather a continuous, unbroken and flexible tubing formed as a single piece of material), or wireline with an electrical conductor (that is, a monofilament or multifilament wire rope with one or more electrical conductors, sometimes called e-line) and thus have a corresponding connector (for example, a jointed tubing connector, coiled tubing connector, or wireline connector). In some implementations, the apparatus 102 can be implemented to alter characteristics of a wellbore by a mechanical intervention at the source. The apparatus 102 can be implemented to effect increased well production.
The apparatus 102 can operate in a variety of downhole conditions of the well 100. For example, the initial pressure within the well 100 can vary based on the type of well, depth of the well 100, production flow from the perforations into the well 100, and/or other factors. In some examples, the pressure in the well 100 proximate a bottomhole location is sub-atmospheric, where the pressure in the well 100 is at or below about 14.7 pounds per square inch absolute (psia), or about 101.3 kiloPascal (kPa). The apparatus 102 can operate in sub-atmospheric well pressures, for example, at well pressure between 2 psia (13.8 kPa) and 14.7 psia (101.3 kPa). In some examples, the pressure in the well 100 proximate a bottomhole location is much higher than atmospheric, where the pressure in the well 100 is above about 14.7 pounds per square inch absolute (psia), or about 101.3 kiloPascal (kPa). The apparatus 102 can operate in above atmospheric well pressures, for example, at well pressure between 14.7 psia (101.3 kPa) and 5,000 psia (34,474 kPa).
Referring to
In some implementations, the perforation tool 102a is configured to perforate a portion of the tubing (for example, the casing 112) that spans at most 1.5 meters in longitudinal length of the tubing at a time. In other words, a single use of the perforation tool 102a can result in forming perforations in a portion of the tubing that spans at most 1.5 meters in longitudinal length of the tubing. The perforation tool 102a can be used multiple times to perforate additional portions of the tubing. For example, the perforation tool 102a can be moved to another location within the tubing to perforate another portion of the tubing that spans at most 1.5 meters in longitudinal length of the tubing. In some implementations, the perforation tool 102a is configured to form at most 12 perforations in the tubing (for example, the casing 112) at a time. In other words, a single use of the perforation tool 102a can result in forming a single fracturing stage with at most 12 perforations in the tubing. The perforation tool 102a can be used multiple times to form additional perforations (additional fracturing stages) in the tubing. In some implementations, the perforation tool 102a is configured to form at most 12 perforations in a portion of the tubing (for example, the casing 112) that spans at most 1.5 meters in longitudinal length of the tubing at a time. In some implementations, the perforation tool 102a is configured to form at least 5 perforations in the tubing (for example, the casing 112) at a time.
The resettable packer 102b can divide the well 100 into an uphole zone above the resettable packer 102b and a downhole zone below the resettable packer 102b.
Additional perforations can be formed in the casing 112 at another location in the subterranean zone 110 to hydraulically fracture that location of the subterranean zone 110.
Although shown in
At step 506, the well tool assembly 102 is positioned at a location within the casing 112 that is downhole of the perforations 120a (an example is shown in
At step 510, a fracturing fluid (150) is pulsed into the subterranean zone 110 via the perforations 120a by alternating between flowing the fracturing fluid 150 into the casing 112 at a first flow rate and flowing the fracturing fluid 150 into the casing 112 at a second flow rate (different from the first flow rate). In other words, the fracturing fluid 150 can be pulsed into the subterranean zone 110 using the pump 104 (alternating between a large first flow rate and a small second flow rate). As mentioned previously, the fracturing fluid 150 is free of proppant and has a viscosity that is substantially equal to that of water. The first flow rate is equal to or less than 6 barrels per minutes. In some implementations, the first flow rate is in a range of from about 4 barrels per minute to 6 barrels per minute. The second flow rate is in a range of from about 10% to about 40% of the first flow rate. For example, in cases where the first flow rate is 6 barrels per minute, the second flow rate is in a range of from about 0.6 barrels per minute to about 2.4 barrels per minute. Neither the first flow rate nor the second flow rate need to be constant throughout step 510. For example, the first flow rate can vary throughout step 510 in a range of from about 4 barrels per minute to 6 barrels per minute. For example, the second flow rate can vary throughout step 510 in a range of from about 10% to about 40% of the first flow rate.
In some implementations, the fracturing fluid 150 is flowed into the casing 112 at the first flow rate for at least 1 minute before alternating to the second flow rate. In some implementations, the fracturing fluid 150 is flowed into the casing 112 at the first flow rate for at most 5 minutes before alternating to the second flow rate. For example, the fracturing fluid 150 is flowed into the casing 112 at the first flow rate for at least 1 minute and at most 5 minutes before alternating to the second flow rate. For example, the fracturing fluid 150 is flowed into the casing 112 at the first flow rate for at least 3 minutes and at most 5 minutes before alternating to the second flow rate.
In some implementations, the fracturing fluid 150 is flowed into the casing 112 at the second flow rate for at least 30 seconds before alternating to the second flow rate. In some implementations, the fracturing fluid 150 is flowed into the casing 112 at the second flow rate for at most 1.5 minutes before alternating to the first flow rate. For example, the fracturing fluid 150 is flowed into the casing 112 at the second flow rate for at least 30 seconds and at most 1.5 minutes before alternating to the first flow rate. For example, the fracturing fluid 150 is flowed into the casing 112 at the second flow rate for at least 1 minute and at most 1.5 minutes before alternating to the first flow rate.
In some implementations, pulsing the fracturing fluid 150 into the subterranean zone 110 at step 510 includes alternating between flowing the fracturing fluid 150 into the casing 112 at the first flow rate and flowing the fracturing fluid 150 into the casing 112 at the second flow rate, such that each of the first flow rate and the second flow rate occur at least 5 times (for example, 5 times, 6 times, 7 times, 8 times, 9 times, 10 times, or more). In some implementations, pulsing the fracturing fluid 150 into the subterranean zone 110 at step 510 includes alternating between flowing the fracturing fluid 150 into the casing 112 at the first flow rate and flowing the fracturing fluid 150 into the casing 112 at the second flow rate until a pre-determined volume of fracturing fluid 150 has been injected into the casing 112. The pre-determined volume of fracturing fluid 150 can depend on one or more of the following factors: thickness of the reservoir (that is, radial distance of the zone of interest from the casing 112), desired length of the hydraulic fractures, and reservoir leak-off characteristics. In some implementations, the pre-determined volume of fracturing fluid 150 is at least approximately 2,000 barrels. In some implementations, the pre-determined volume of fracturing fluid 150 is at most 20,000 barrels. For example, pulsing the fracturing fluid 150 into the subterranean zone 110 at step 510 continues until at least 2,000 barrels of fracturing fluid 150 have been injected into the casing 112.
This paragraph outlines one specific example of an implementation of step 510. The first flow rate is 5 barrels per minute, and the second flow rate is 1 barrel per minute. The fracturing fluid 150 is flowed into the casing 112 (through the perforations 120a and into the subterranean zone 110) at the first flow rate for 4 minutes and then at the second flow rate for 1 minute. The fracturing fluid 150 is flowed into the casing 112, alternating between the first flow rate for 4 minutes and the second flow rate for 1 minute for 10 iterations (that is, for a total of 10 instances of first flow rate for 4 minutes and 10 instances of second flow rate for 1 minute). Therefore, in this example, step 510 spans 50 minutes with a total volume of 210 barrels injected into the casing 112.
The cyclic loading of step 510 creates fractures (121a) in the subterranean formation 110. The mechanism at step 510 can cause fracture degradation at fracture tips and therefore increase fracture half length. After pulsing the fracturing fluid 150 into the subterranean zone 110, the resettable packer 102b can be unset to unseal the casing 112. The well tool assembly 102 can then be moved, for example, out of the well 100 or to another location within the casing 112. In some implementations, the well tool assembly 102 is positioned at another location within the casing 112 that is uphole of the perforations 120a, and the method 500 is repeated.
At step 602, a fracturing fluid (150) is injected into the subterranean zone 110 at a first flow rate that is equal to or less than 6 barrels per minute. As mentioned previously, the fracturing fluid 150 is free of proppant and has a viscosity that is substantially equal to that of water. In some implementations, the fracturing fluid 150 is injected into the subterranean zone 110 at the first flow rate for at least 1 minute at step 602. In some implementations, the fracturing fluid 150 is injected into the subterranean zone 110 at the first flow rate for at most 5 minutes at step 602. For example, the fracturing fluid 150 is injected into the subterranean zone 110 at the first flow rate for at least 1 minute and at most 5 minutes at step 602. For example, the fracturing fluid 150 is injected into the subterranean zone 110 at the first flow rate for at least 3 minutes and at most 5 minutes at step 602.
At step 604, the fracturing fluid 150 is injected into the subterranean zone 110 at a second flow rate that is in a range of from about 10% to about 40% of the first flow rate. In some implementations, the fracturing fluid 150 is injected into the subterranean zone 110 at the second flow rate for at least 30 seconds at step 604. In some implementations, the fracturing fluid 150 is injected into the subterranean zone 110 at the second flow rate for at most 1.5 minutes at step 604. For example, the fracturing fluid 150 is injected into the subterranean zone 110 at the second flow rate for at least 30 seconds and at most 1.5 minutes at step 604. For example, the fracturing fluid 150 is injected into the subterranean zone 110 at the second flow rate for at least 1 minute and at most 1.5 minutes at step 604.
Steps 602 and 604 are then sequentially repeated. Steps 602 and 604 are repeated to provide pulsations of fracturing fluid 150 injection into the subterranean zone 110 until a single fracturing stage is complete. In some implementations, steps 602 and 604 are sequentially repeated at least 5 times (for example, 5 times, 6 times, 7 times, 8 times, 9 times, 10 times, or more). In some implementations, steps 602 and 604 are sequentially repeated until a pre-determined volume of fracturing fluid 150 has been injected into the subterranean zone 110. Once the pre-determined volume of fracturing fluid 150 has been injected into the subterranean zone 110, a single fracturing stage is complete. For example, steps 602 and 604 are sequentially repeated until at least 2,000 barrels of fracturing fluid have been injected into the subterranean zone 110.
The fracturing fluid 150 can be injected into the subterranean zone 110 at steps 602 and 604, for example, by flowing the fracturing fluid 150 from the surface 106, into the casing 112 and through the perforations 120 (or 120a or 120b) by using the pump 104.
In this disclosure, the terms “a,” “an,” or “the” are used to include one or more than one unless the context clearly dictates otherwise. The term “or” is used to refer to a nonexclusive “or” unless otherwise indicated. The statement “at least one of A and B” has the same meaning as “A, B, or A and B.” In addition, it is to be understood that the phraseology or terminology employed in this disclosure, and not otherwise defined, is for the purpose of description only and not of limitation. Any use of section headings is intended to aid reading of the document and is not to be interpreted as limiting; information that is relevant to a section heading may occur within or outside of that particular section.
In this disclosure, “approximately” means a deviation or allowance of up to 10 percent (%) and any variation from a mentioned value is within the tolerance limits of any machinery used to manufacture the part. Likewise, “about” and “substantially” can also allow for a degree of variability in a value or range, for example, within 10%, within 5%, or within 1% of a stated value or of a stated limit of a range.
Values expressed in a range format should be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of “0.1% to about 5%” or “0.1% to 5%” should be interpreted to include about 0.1% to about 5%, as well as the individual values (for example, 1%, 2%, 3%, and 4%) and the sub-ranges (for example, 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. The statement “X to Y” has the same meaning as “about X to about Y,” unless indicated otherwise. Likewise, the statement “X, Y, or Z” has the same meaning as “about X, about Y, or about Z,” unless indicated otherwise.
While this disclosure contains many specific implementation details, these should not be construed as limitations on the subject matter or on what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this disclosure in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.
Particular implementations of the subject matter have been described. Nevertheless, it will be understood that various modifications, substitutions, and alterations may be made. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. Accordingly, the previously described example implementations do not define or constrain this disclosure.
Claims
1. A method for hydraulically fracturing a subterranean zone penetrated by a wellbore, comprising:
- positioning a well tool assembly within a casing installed in the wellbore, the well tool assembly comprising a perforation tool and a resettable packer;
- with the perforation tool, perforating the casing to form a plurality of perforations in the casing, such that fluid can be conducted from inside the casing to the subterranean zone through the plurality of perforations;
- positioning the well tool assembly at a location within the casing that is downhole of the plurality of perforations;
- with the resettable packer, sealing a portion of the casing that is downhole of the plurality of perforations from a remaining portion of the casing; and
- pulsing a fracturing fluid into the subterranean zone via the plurality of perforations by alternating between flowing the fracturing fluid into the casing at a first flow rate that is equal to or less than 6 barrels per minute and flowing the fracturing fluid into the casing at a second flow rate that is in a range of from about 10% to about 40% of the first flow rate, wherein the fracturing fluid is free of proppant and has a viscosity that is substantially equal to that of water.
2. The method of claim 1, wherein the plurality of perforations is a first plurality of perforations, and the method further comprises:
- unsetting the resettable packer to unseal the portion of the casing that is downhole of the first plurality of perforations;
- positioning the well tool assembly at a location within the casing that is uphole of the first plurality of perforations;
- with the perforation tool, perforating the casing to form a second plurality of perforations in the casing uphole of the first plurality of perforations;
- positioning the well tool assembly at a location within the casing that is downhole of the second plurality of perforations;
- with the resettable packer, sealing a portion of the casing that is downhole of the second plurality of perforations from a remaining portion of the casing;
- pulsing the fracturing fluid into the subterranean zone via the second plurality of perforations by alternating between flowing the fracturing fluid into the casing at the first flow rate and flowing the fracturing fluid into the casing at the second flow rate; and
- unsetting the resettable packer to unseal the portion of the casing that is downhole of the second plurality of perforations.
3. The method of claim 2, wherein the well tool assembly remains within the casing throughout implementation of the method.
4. The method of claim 3, wherein each plurality of perforations spans a portion of the casing that is at most 1.5 meters in longitudinal length.
5. The method of claim 4, wherein each plurality of perforations comprises at most 12 perforations.
6. The method of claim 2, wherein the fracturing fluid is flowed into the casing at the first flow rate for at most 5 minutes before alternating to the second flow rate.
7. The method of claim 6, wherein the fracturing fluid is flowed into the casing at the second flow rate for at most 1.5 minutes before alternating to the first flow rate.
8. The method of claim 7, wherein pulsing the fracturing fluid into the subterranean zone comprises alternating between flowing the fracturing fluid into the casing at the first flow rate and flowing the fracturing fluid into the casing at the second flow rate, such that each of the first flow rate and the second flow rate occur at least 5 times.
9. The method of claim 7, pulsing the fracturing fluid into the subterranean zone comprises alternating between flowing the fracturing fluid into the casing at the first flow rate and flowing the fracturing fluid into the casing at the second flow rate until at least 2,000 barrels of fracturing fluid have been flowed into the subterranean zone via the respective plurality of perforations.
10. A method for hydraulically fracturing a subterranean zone having a matrix permeability of at most 100 nanoDarcy and a clay content of at most 60 volume %, the method comprising:
- a) injecting a fracturing fluid into the subterranean zone at a first flow rate that is equal to or less than 6 barrels per minute, wherein the fracturing fluid is free of proppant and has a viscosity that is substantially equal to that of water;
- b) injecting the fracturing fluid into the subterranean zone at a second flow rate that is in a range of from about 10% to about 40% of the first flow rate; and
- c) sequentially repeating steps a) and b).
11. The method of claim 10, wherein the fracturing fluid is injected into the subterranean zone at step a) for at most 5 minutes.
12. The method of claim 11, wherein the fracturing fluid is injected into the subterranean zone at step b) for at most 1.5 minutes.
13. The method of claim 12, wherein steps a) and b) are sequentially repeated at step c) at least 5 times.
14. The method of claim 12, wherein steps a) and b) are sequentially repeated at step c) until at least 2,000 barrels of fracturing fluid have been injected into the subterranean zone.
15. A system for hydraulically fracturing a subterranean zone penetrated by a wellbore, the system comprising:
- a well tool assembly comprising: a perforation tool configured to form a plurality of perforations in a casing installed within the wellbore; and a resettable packer configured to reversibly seal a portion of the casing from a remaining portion of the casing while a fracturing fluid is injected into the subterranean zone via the plurality of perforations, wherein the well tool assembly is configured to remain within the casing during hydraulic fracturing;
- a fracturing fluid that is free of proppant and has a viscosity that is substantially equal to that of water; and
- a pump configured to flow the fracturing fluid into the subterranean zone via the plurality of perforations formed by the perforation tool by pulsing the fracturing fluid into the casing between a first flow rate that is equal to or less than 6 barrels per minute and a second flow rate that is in a range of from about 10% to about 40% of the first flow rate, thereby hydraulically fracturing the subterranean zone.
16. The system of claim 15, wherein the perforation tool is configured to form the plurality of perforations in the casing across a portion of the casing that is at most 1.5 meters in longitudinal length.
17. The system of claim 16, wherein the plurality of perforations comprises at most 12 perforations.
Type: Application
Filed: May 28, 2019
Publication Date: Dec 3, 2020
Inventors: Clay Kurison (Dhahran), Ahmed Hamed Almubarak (Saar), Huseyin Sadi Kuleli (Dhahran)
Application Number: 16/423,853