CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority under 35 U.S.C. § 119 to (1) United States Provisional Patent Application Serial Number 62/938,016 titled “Remote Actuated Multi-Cycle Ball Operated Fracturing Sleeve System For Multi-Stage Fracture Completions Operations” and filed on November 20, 2019; (2) United States Provisional Patent Application Serial Number 62/957,668 titled “Remote Actuated Multi-Cycle Ball Operated Fracturing Sleeve System For Multi-Stage Fracture Completions Operations” and filed on January 6, 2020; (3) United States Provisional Patent Application Serial Number 63/053,815 titled “Remote Actuated Multi-Cycle Ball Operated Fracturing Sleeve System For Multi-Stage Fracture Completions Operations” and filed on July 20, 2020; and (4) United States Provisional Patent Application Serial Number 63/073,872 titled “Collapsible and Expandable Ball Seat For Use In a Ball-Actuated Sleeve of a Multi-Stage Fracturing System” and filed on September 2, 2020. The entire contents of these aforementioned references are hereby incorporated herein by reference.

TECHNICAL FIELD

[0002] The present invention generally relates to hydrocarbon well stimulation equipment and, in particular, to fracturing sleeves and related systems for enabling single entry point, non sequential hydraulic fracture staging in multi-stage horizontal completion operations from multi well pads with wellbores landed in one or more subterranean formations to extract subterranean resources.

BACKGROUND

[0003] Maximizing hydraulic fracture complexity (i.e., fracture surface area per volume of bulk reservoir rock) is an important completions goal in the development of liquids-rich tight unconventional resources (UCR) (e.g., oil, natural gas) using stage-fractured horizontal subterranean wellbores. The ability to achieve fracture complexity is primarily a function of two factors: (1) the sub-surface conditions, including mechanical properties of the rock, mineralogy, effective in-situ stress state (total stress and pore pressure), and natural fractures and/or other rock fabric features, and (2) the well design and execution of the completion, giving consideration to offset well injection and production activity and/or prior fluid injection related to the well’s completion operation. It is important to note that actions subsequent to the well design and completion execution of one or more wells will dynamically introduce modified sub-surface conditions that will affect the ability to achieve fracture complexity during the completion of future neighboring wells. These factors should be considered when optimizing drilling and completion designs along with the operational sequencing of future wells.

[0004] Natural heterogeneity may result in significant variability in both the mechanical properties and the stress state along a lateral wellbore. Furthermore, the stress field adjacent to a wellbore (near-field) is affected by how the well is constructed and the ensuing completion operations. For example, the opening of hydraulic fractures results in a change to the stress field at several scales, the magnitude and dynamic behavior of which is dependent on numerous rock properties. This evolved stress field will affect subsequent operations, such that new induced hydraulic fractures propagate in a modified stress field and themselves induce changes on pre existing structures in the same and adjacent wells. These stress changes may enhance or impede the amount of fracture complexity of subsequent fractures in the vicinity, and thus require careful consideration in order to optimize stimulation sequencing in a single well and between multiple adjacent wells which are being completed in the same operation.

[0005] Currently, the most commonly used multi-stage hydraulic fracturing technology for cemented horizontal completions is “plug n’ perf ' (“P n’ P”), which involves temporarily plugging the wellbore, then perforating multiple discrete locations along a horizontal section of the wellbore with a spacing ranging typically from 15 feet to 60 feet, then pumping fracture fluids and proppant at relatively high rates (e.g., more than 80 barrels per minute), and then repeating the process in stages starting near the toe (distal end) of the horizontal section of the wellbore and working toward the heel (proximal end) of horizontal section of the wellbore. Operators have generally found P n’ P offers a more cost-effective completion method for creating many fracture entry points in long horizontal development wells to promote hydraulic fracture complexity. However, this technology may not allow for an appropriate scale of sensitivity to the inherent rock properties and dynamic stress field as they typically have greater than four fracture entry point locations ("perf clusters") in each discrete pumping operation ("stage"); have perf clusters and stages that are uniformly spaced along the lateral; and must proceed in a specific toe-to-heel sequence. A direct outcome of these inherent constraints, combined with a lack of characterization of lateral changes in rock properties ( e.g ., in situ stress, minerology, natural fractures, bedding planes) and understanding of dynamic stress changes, is the unpredictable nature of fracture geometries and poor perf cluster efficiency, both of which have may have adverse impacts on full field development economics and hydrocarbon recovery efficiency. Generally, on average, more than 40% of perf clusters are either not effectively stimulated and/or are not contributing significantly to production in P n’ P completions due in part to the previously described challenges related to sub-surface environmental heterogeneity and stress shadowing. Other potential causes of poor perf cluster efficiency in P n' P operations include (a) inertial effects of proppant bypassing heel-side clusters in multi-cluster P n' P fracturing stages causing slurry dehydration towards the toe, (b) proppant concentration gradations from turbulence or gravity across the wellbore causing further slurry dehydration towards the toe, (c) slurry velocity reductions in the casing toward toe-side clusters causing proppant settling and systematic premature screen outs of the toe-side clusters, and (d) unfavorable/inconsistent perforation phasing, entrance hole diameters, and penetration.

[0006] Another potential limitation of the P n' P treatment technique is the limited ability to modify the fracture design or operation during the treatment. Hence, it may be difficult to respond to unexpected scenarios, such as variations from the predicted natural heterogeneity of the formation rocks being treated and/or the modified dynamic in situ stress conditions resulting from the previous fracturing operations in the well being treated, offset wells that have already been treated, and/or wells that are currently being stimulated.

[0007] Various ball-actuated fracturing sleeve solutions are available in the market which are capable of providing single entry point fracturing staging and improved operational efficiency over P n' P, but all have significant limitations related to yielding a cost competitive solution compared to P n' P and an inability to address stress shadowing since they require systematic fracturing staging from toe to heel. Similarly, various coiled tubing-actuated fracturing sleeve solutions are available in the market that provide a similar goal of providing single entry point fracturing and offer an option for non-sequential staging to address stress shadowing, but the all-in cost of these solutions is not cost-competitive compared to P n' P, and these solutions require fracturing wells down the coiled tubing/casing annulus, which introduces significant operational risk, such as sticking the coiled tubing bottom hole assembly in the wellbore or experiencing a surface failure of the coiled tubing under high pressures.

SUMMARY

[0008] In general, in one aspect, the disclosure relates to a fracturing sleeve for fracturing a subterranean formation can include a wall that forms a cavity and has multiple wall fracturing ports. The fracturing sleeve can also include: a mandrel movably disposed within the cavity, where the mandrel has multiple mandrel fracturing ports; a ball seat assembly (BSA) disposed with the cavity and coupled to the mandrel; a magnetometer sensor configured to measure a magnetic field; and a controller. The controller is configured to: receive a measurement value of the magnetic field from the magnetometer sensor; determine that the measurement value meets a threshold condition; operate the BSA into a closed BSA position to receive a frac ball, causing the mandrel to move from a first closed position to an open position; and release, after a period of time, the mandrel so that the mandrel moves from the open position to a second closed position. One or more of these fracturing sleeves can be used in systems and methods, including methods implemented on a non-transitory computer readable medium, for fracturing a subterranean formation.

[0009] These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0010] The drawings illustrate only example embodiments and are therefore not to be considered limiting in scope, as the example embodiments may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positions may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements.

[0011] Figures 1A and IB show a plan view and section view, respectively, of a system for performing a fracturing operation according to certain example embodiments. [0012] Figure 2 shows results of a multi-well fracturing operation in plan view using techniques currently used in the art.

[0013] Figure 3 shows results of a multi-well fracturing operation in plan view using example embodiments.

[0014] Figures 4A through 4E are plan view drawings that show a sequence of a multi-well fracturing operation using example embodiments.

[0015] Figures 5A through 5E are plan view drawings that show another sequence of a multi well fracturing operation using example embodiments.

[0016] Figure 6 shows a section a subassembly that includes a fracturing sleeve according to certain example embodiments.

[0017] Figures 7 through 14B are section view drawings that show how the fracturing sleeve of Figure 6 can be used during a fracturing operation.

[0018] Figures 15 and 16 show section view drawings of a subassembly that includes another fracturing sleeve according to certain example embodiments.

[0019] Figure 17 is a plan view drawing that shows a configuration of a multi -well fracturing operation, commonly referred to as a Texas two-step fracturing method, using example embodiments.

[0020] Figures 18A through 23 show another fracturing sleeve according to certain example embodiments.

[0021] Figures 24 through 26 show yet another fracturing sleeve according to certain example embodiments.

[0022] Figure 27 shows a diagram of a system that includes a fracturing sleeve according to certain example embodiments.

[0023] Figure 28 shows a computing device according to certain example embodiments.

DESCRIPTION OF THE INVENTION

[0024] The example embodiments discussed herein are directed to systems, methods, and devices for fracturing sleeves and related systems for multi-stage fracturing completions operations. While example embodiments are described herein as being used with fluids containing hydrocarbons (e.g., oil) during exploration and/or production of a subterranean field (e.g., oilfield), example embodiments can also be used with fluids containing any of a number of other materials (e.g., gold, iron) that are used in any of a number of other applications (e.g., water extraction, formation fracturing, mining).

[0025] The present invention is directed toward an alternative multi-stage fracturing solution for horizontal sections of subterranean wellbores with cemented casing (also called casings strings or liner strings) in tight liquids-rich UCR subterranean formations that enables cost-effective non sequential pinpoint staging (from a single entry point) and simultaneous fracturing of multiple wellbores (also called wells herein) on a pad to (a) maximize fracture complexity, (b) promote self-propping shear failure mode fractures, and (c) provide better stimulated rock volume (SRV) containment within targeted drainage volume for avoiding geohazards and fracture hits and for optimizing lateral/vertical well spacing and the timing between fracturing discrete locations along multiple adjacent laterals ("4D completions optimization") to maximize recovery efficiency and project economics.

[0026] In addition to addressing many of the contributory factors behind the above-mentioned cluster efficiency problem, the example fracturing sleeve technology discussed herein has no mechanical limit to the number of fracturing sleeves that can be installed on the production casing or liner, is operationally less complex than P n' P or coiled tubing actuated fracturing sleeves currently used in the art, and will result in reduced pad development cycle time. The example fracturing system using example fracturing sleeves described herein provides for an ideal environment because it does not require the use of wireline, select-fire perforating guns, frac plugs, dedicated pump-down equipment, tall lubricators, overhead crane work, zipper manifolds or coiled tubing intervention during the stage frac operation and/or for a subsequent frac plug/ball/seat mill- out operation. A single stage of a multi-stage fracture completion can be characterized as including a fracturing operation that targets one or more adjacent perf clusters or frac entry points in a separate and distinct pumping operation.

[0027] The system leverages a novel wireless downhole sensing and automatic processing technology to enable three discrete fracturing sleeve actuations during the stage-fracturing completion process - open, close, and re-open. After fracturing through the last sleeve and shutting in the well for a pre-defmed duration, the sleeves may be configured to automatically re-open. In certain example embodiments, each example fracturing sleeve and its associated mandrel are tubular in shape. [0028] The improved certainty of the fracturing rate exiting the casing at a single point is also expected to provide improved control over fracture height growth (i.e., lower rate to contain the fractures in a thinner zone or a higher rate to ensure a thicker interval is covered by the fracturing). Single entry point fracturing, non-sequential staging and simultaneous fracturing of multiple adjacent wells ("4D completions") are expected to increase fracture complexity by promoting more shear fracturing events {i.e. “torque the rock” rather than fracturing sequentially from toe to heel). [0029] The example fracturing sleeve and related system of the present invention is also expected to facilitate completing longer laterals (substantially horizontal sections of a wellbore) without increasing the casing, wellhead, or fracturing iron specification due to the lower fracturing rate requirements (compared to P n' P) and due to the elimination of pump-down and fracturing plug/ball drillout operations. Finally, the system may facilitate re-fracturing or improved oil recovery (IOR) injection processes by allowing the example fracturing sleeves to be closed and re-opened repeatedly at any time after initial completion using coiled tubing intervention and a standard sleeve shifting tool (e.g., HB-3).

[0030] Those of ordinary skill in the art will appreciate that words such as “frac” and “fracture”, or variations thereof, have the same meaning. Other words and terms associated with fracturing operations and field operations in general can similarly have other abbreviations or long forms that are used interchangeably in the industry. This application at times uses an acronym, an abbreviated word, or a term that will be understood by one of ordinary skill in the art to have the meaning of a full and/or unabbreviated form of that word or term, which may also be used at times herein.

[0031] An example fracturing sleeve includes multiple components that are described herein, where a component can be made from a single piece (as from a mold or an extrusion). When a component (or portion thereof) of an example fracturing sleeve is made from a single piece, the single piece can be cut out, bent, stamped, and/or otherwise shaped to create certain features, elements, or other portions of the component. Alternatively, a component (or portion thereof) of an example fracturing sleeve can be made from multiple pieces that are mechanically coupled to each other. In such a case, the multiple pieces can be mechanically coupled to each other using one or more of a number of coupling methods, including but not limited to adhesives, welding, fastening devices, compression fittings, mating threads, and slotted fittings. One or more pieces that are mechanically coupled to each other can be coupled to each other in one or more of a number of ways, including but not limited to fixedly, hingedly, rotatably, removably, slidably, and threadably.

[0032] Components and/or features described herein can include elements that are described as coupling, fastening, securing, or other similar terms. Such terms are merely meant to distinguish various elements and/or features within a component or device and are not meant to limit the capability or function of that particular element and/or feature. For example, a feature described as a “coupling feature” can couple, secure, abut against, fasten, and/or perform other functions aside from merely coupling. In addition, each component and/or feature described herein (including each component of an example fracturing sleeve) can be made of one or more of a number of suitable materials, including but not limited to metal (e.g., stainless steel), ceramic, rubber, glass, and plastic.

[0033] A coupling feature (including a complementary coupling feature) as described herein can allow one or more components (e.g., a housing) and/or portions of an example fracturing sleeve to become mechanically coupled, directly or indirectly, to another portion of the fracturing sleeve and/or another component (e.g., a casing pipe) of a casing string. A coupling feature can include, but is not limited to, a portion of a hinge, an aperture, a recessed area, a protrusion, a slot, a spring clip, a tab, a detent, and mating threads. One portion of an example fracturing sleeve can be coupled to another portion of the fracturing sleeve and/or another component of casing string by the direct use of one or more coupling features.

[0034] In addition, or in the alternative, a portion of an example fracturing sleeve can be coupled to another portion of the fracturing sleeve and/or another component of a casing string using one or more independent devices that interact with one or more coupling features disposed on a component of the fracturing sleeve. Examples of such devices can include, but are not limited to, a pin, a hinge, a fastening device (e.g., a bolt, a screw, a rivet), an adapter, and a spring. One coupling feature described herein can be the same as, or different than, one or more other coupling features described herein. A complementary coupling feature as described herein can be a coupling feature that mechanically couples, directly or indirectly, with another coupling feature. [0035] When used in certain systems (e.g., for certain subterranean field operations), example embodiments can be designed to help such systems comply with certain standards and/or requirements. Examples of entities that set such standards and/or requirements can include, but are not limited to, the Society of Petroleum Engineers, the American Petroleum Institute (API), the International Standards Organization (ISO), and the Occupational Safety and Health Administration (OSHA).

[0036] If a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure can be inferred to that component. Conversely, if a component in a figure is labeled but not described, the description for such component can be substantially the same as the description for the corresponding component in another figure. The numbering scheme for the various components in the figures herein is such that each component is a three-digit or a four-digit number and corresponding components in other figures have the identical last two digits. For any figure shown and described herein, one or more of the components may be omitted, added, repeated, and/or substituted. Accordingly, embodiments shown in a particular figure should not be considered limited to the specific arrangements of components shown in such figure.

[0037] Further, a statement that a particular embodiment (e.g., as shown in a figure herein) does not have a particular feature or component does not mean, unless expressly stated, that such embodiment is not capable of having such feature or component. For example, for purposes of present or future claims herein, a feature or component that is described as not being included in an example embodiment shown in one or more particular drawings is capable of being included in one or more claims that correspond to such one or more particular drawings herein.

[0038] Example embodiments of fracturing sleeves and related systems for hydraulic fracturing operations will be described more fully hereinafter with reference to the accompanying drawings, in which example embodiments of fracturing sleeves and related systems for hydraulic fracturing operations are shown. Fracturing sleeves and related systems for hydraulic fracturing operations may, however, be embodied in many different forms and should not be construed as limited to the example embodiments set forth herein. Rather, these example embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of fracturing sleeves and related systems for hydraulic fracturing operations to those of ordinary skill in the art. Like, but not necessarily the same, elements (also sometimes called components) in the various figures are denoted by like reference numerals for consistency.

[0039] Terms such as “first”, “second”, “outer”, “inner”, “top”, “bottom”, “distal”, “proximal”, “on”, and “within” are used merely to distinguish one component (or part of a component or state of a component) from another. This list of terms is not exclusive. Such terms are not meant to denote a preference or a particular orientation, and they are not meant to limit embodiments of fracturing sleeves and related systems for hydraulic fracturing operations. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0040] Figures 1 A and IB show various views of a field system 100 for performing a fracturing operation according to certain example embodiments. Specifically, Figure 1 A shows a schematic diagram of a land-based field system 100 in which fracturing sleeves 130 can be used within a subterranean wellbore 120 (also sometimes referred to more simply as a wellbore 120 herein) according to certain example embodiments. Figure IB shows a detail of part of the substantially horizontal section 105 of the wellbore 120. The field system 100 in this example includes a wellbore 120 disposed in a subterranean formation 110 using field equipment (e.g., a derrick, a tool pusher, a clamp, a tong, drill pipe, casing pipe, a drill bit, a wireline tool, a firac ball launcher 191, and a fluid pumping system 104) located above a surface 108 and within the wellbore 120. Once the wellbore 120 is drilled, a casing string 125 is inserted into the wellbore 120 to stabilize the wellbore 120 and allow for the extraction of subterranean resources (e.g., oil, natural gas) from the formation 110.

[0041] The surface 108 can be ground level for an on-shore application and the sea floor for an off-shore application. The point where the wellbore 120 begins at the surface 108 can be called the wellhead. While not shown in Figures 1 A and IB, there can be multiple wellbores 120, each with their own wellhead but that are located close to the other wellheads, drilled into the subterranean formation 110 and having substantially horizontal sections 105 that are close to each other. In such a case, the multiple wellbores 120 can be drilled at the same pad location. When the drilling process is complete, other operations, such as fracturing operations, can be performed. In this case, the frac ball launcher 191 and the fluid pumping system 104 are positioned at the surface 108 and the casing string 125 is inserted into the subterranean wellbore 120 to perform fracturing operations in multiple stages.

[0042] The subterranean formation 110 can include one or more of a number of formation types, including but not limited to shale, limestone, sandstone, clay, sand, and salt. In certain embodiments, a subterranean formation 110 can include one or more reservoirs in which one or more resources (e.g., oil, gas, water, steam) can be located. One or more of a number of field operations (e.g., fracking, coring, tripping, drilling, setting casing, extracting downhole resources) can be performed to reach an objective of a user with respect to the subterranean formation 110. [0043] The wellbore 120 can have one or more of a number of segments or hole sections, where each segment or hole section can have one or more of a number of dimensions. Examples of such dimensions can include, but are not limited to, size (e.g., diameter) of the wellbore 120, a curvature of the wellbore 120, a total vertical depth of the wellbore 120, a measured depth of the wellbore 120, and a horizontal displacement of the wellbore 120. There can be multiple overlapping casing strings of various sizes (e.g., length, outer diameter) contained within these segments or hole sections to ensure the integrity of the wellbore construction. In this case, one of the segments of the subterranean wellbore 120 is the substantially horizontal section 105, which is defined by a heel 106 at its proximal end and a toe 107 at its distal end.

[0044] As discussed above, inserted into and disposed within the wellbore 120 of Figures 1A and IB are a number of casing pipes 124 and example fracturing sleeves 130 that are coupled to each other end-to-end to form the casing string 125. In this case, each end of a casing pipe 124 and each end of each example fracturing sleeve 130 has mating threads (a type of coupling feature) disposed thereon, allowing a casing pipe 124 to be mechanically coupled to an adjacent example fracturing sleeve 130 (or to another casing pipe 124) in an end-to-end configuration. The casing pipes 124 and example fracturing sleeves 130 of the casing string 125 can be mechanically coupled to each other directly or indirectly using a coupling device, such as a coupling sleeve.

[0045] In the detail shown in Figure IB, the casing pipes 124 and the example fracturing sleeves 130 are directly coupled to each other. Specifically, starting from the heel 106 and moving toward the toe 107, casing pipe 124-1 is coupled to fracturing sleeve 130-1, which is coupled to casing pipe 124-2, which is coupled to fracturing sleeve 130-2, which is coupled to casing pipe 124-3, which is coupled to fracturing sleeve 130-3, which is coupled to casing pipe 124-4, which is coupled to fracturing sleeve 130-4, which is coupled to casing pipe 124-5, which is coupled to fracturing sleeve 130-5, which is coupled to casing pipe 124-6. The casing string 125 is not disposed in the entire wellbore 120. Often, the casing string 125 is disposed from approximately the surface 108 to some other point near, but not at, the distal end of the subterranean wellbore 120 [0046] Also shown in Figure 1 A is a pressure-actuated toe sleeve 195 located near the distal end of the casing string 125 to establish a robust flow path from the wellhead of the wellbore 120 at the surface 108 through the casing string 125 near the toe 107 of the wellbore 120 after pressure testing the casing string 125 and before initiating multi-stage fracturing operations. Pressure- actuated toe sleeves (such as toe sleeve 195) are commercially available from a number of oilfield service providers and are commonly used in P n’ P and other current multi-stage fracturing methods. One or multiple toe sleeves 195 can be used in multi-stage fracturing completions that are designed to use the example fracturing sleeves 130, as shown in Figure 1 A. In such a case, the one or more toe sleeves 195 are opened at the beginning of a multi-stage fracturing operation and remain open while each stage (in which one of the example fracturing sleeves 130 is in an open position while the remainder of the example fracturing sleeves 130 in the casing string 125 are in a closed position) of the fracturing operation is pumped.

[0047] While the casing pipe 124 and example fracturing sleeves 130 in Figure IB are shown to be alternating with each other and equally spaced (in other words, the casing pipes 124 are all the same length and outer diameter, and the fracturing sleeves 130 are all the same length (less than the length of the casing pipes 124) and outer diameter, and the outer diameter of the entire casing string is the same), the size (e.g., length, outer diameter) of one or more fracturing sleeves 130 can differ from the size of one or more of the other fracturing sleeves 130. Also, the spacing between two adjacent fracturing sleeves 130 can be the same as or differ than the spacing between two or more other adjacent fracturing sleeves 130. In this case, the casing pipes 124 and the fracturing sleeves 130 are tubular in shape.

[0048] Each casing pipe 124 of the casing string 125 can have a length and a width (e.g., outer diameter). The length of a casing pipe 124 can vary. For example, a common length of a casing pipe 124 is approximately 40 feet. The length of a casing pipe 124 can be longer (e.g., 60 feet) or shorter (e.g., 10 feet) than 40 feet. The width of a casing pipe 124 can also vary and can depend on the cross-sectional shape of the casing pipe 124. For example, when the cross-sectional shape of the casing pipe 124 is circular, the width can refer to an outer diameter, an inner diameter, or some other form of measurement of the casing pipe 124. Examples of a width in terms of an outer diameter can include, but are not limited to, 4-1/2 inches, 7 inches, 7-5/8 inches, 8-5/8 inches, 10- 3/4 inches, 13-3/8 inches, and 14 inches. [0049] Similarly, each fracturing sleeve 130 of the casing string 125 can have a length and a width (e.g., outer diameter). The length of a fracturing sleeve 130 can vary. For example, a common length of a fracturing sleeve 130 can be approximately 10 feet. The length of a fracturing sleeve 130 can be longer (e.g., 20 feet) or shorter (e.g., 6 feet) than 10 feet. The width of a fracturing sleeve 130 can also vary and can depend on the cross-sectional shape of the fracturing sleeve 130. For example, when the cross-sectional shape of the fracturing sleeve 130 is circular, the width can refer to an outer diameter, an inner diameter, or some other form of measurement of the fracturing sleeve 130. Examples of a width in terms of an outer diameter can include, but are not limited to, 3-1/2 inches, 4-1/2 inches, and 5 inches. Example fracturing sleeves 130 can have an outer diameter (e.g., less than 7 inches) that is less than what can be used in P n’ P fracturing operations, which means that example fracturing sleeves 130 can be used in wellbores 120 having a smaller diameter compared to what is required in P n’ P fracturing operations.

[0050] The size (e.g., width, length) of the casing string 125 can be based on the information (e.g., diameter of the borehole drilled) gathered using field equipment with respect to the subterranean wellbore 120. The walls of the casing string 125 have an inner surface that forms a cavity 165 that traverses the length of the casing string 125. Each casing pipe 124 and each fracturing sleeve 130 can be made of one or more of a number of suitable materials, including but not limited to stainless steel. Cement 109 is poured into the wellbore between the outer surface of the casing string 125 and the wall of the subterranean wellbore 120. In some cases, a liner may additionally be used with or alternatively be used in place of some or all of the casing pipes 124. [0051] Historically, sleeve-based fracturing solutions have not been successful for reasons such as cost, physical limitations related to the number of large ID sleeves that can be used in a lateral completion (conventional ball-drop systems), and/or mechanical risk and associated NPT cost related to fracing down the annulus during a coiled tubing intervention (CT-actuated systems). The example fracturing sleeves 130 allow for non-sequential staging (firac in any pre programmed order), which can promote the same or better stimulation effectiveness with fewer frac entry points, as shown in Figure 3 below. Also, example fracturing sleeves 130 are run and cemented as part of the production casing or liner string with an inside diameter which is nearly full drift to the ID of the host pipe and have no physical limitation on how many fracturing sleeves 130 can be run in the substantially horizontal section 105 (also called a lateral 105) of the wellbore 120 [0052] Example fracturing sleeves 130 do not require wireline/perforating/plug setting operations, dedicated pump-down equipment, overhead crane work with tall lubricators, zipper manifolds, personnel in the high pressure “red zones”, or coiled tubing/snubbing unit intervention during the stage-frac operation or for post-frac millout, positively affecting the all-in cost per foot of completed lateral 105. Also, the hydraulic horsepower (HHP) requirements per well are significantly lower with completions using example fracturing sleeves 130 due to the reduction in fluid friction pressure (e.g., pumping at 80 to 100 BPM into 10+ clusters in a P n’ P stage compared to < 50 BPM for a fracturing sleeve 130 single entry point stage). There is also an opportunity to reduce completion cycle time due to extremely short frac stage transition times and the option to use higher frac rates per foot of completed lateral 105 if simul-frac techniques are used on multi well pads.

[0053] In liquids-rich S&T plays with nanodarcy-scale permeability, reservoir productivity is correlative with the amount of induced fracture surface area that is created within the targeted drainage volume for a group of roughly parallel horizontal wells drilled from one or more adjacent multi-well pads. Within the confines of the targeted drainage volume, induced fracture surface area increases as hydraulic fracture complexity increases. Since frac fluid leak-off rate into the “reservoir” matrix is very low, the volume of hydraulic fractures created in a frac stage is approximately equal to the volume of materials pumped (material balance). The goal for S&T completions is to create pervasive complex fractures that are contained within and are extensive throughout the targeted drainage volume rather than creating relatively simple, large aperture, co- planar fractures that propagate beyond the targeted stimulated rock volume (SRV) as defined by the well spacing strategy, as contrasted between Figures 2 and 3 below.

[0054] Modern high-density P n’ P completions use tremendous volumes of frac materials. Recent studies related to proppant transport efficiency indicate that the industry is doing a poor job distributing proppant throughout the targeted SRV. The evidence shows that most of the proppant is concentrated near the frac entry point as a result of a “sand dune” propagation after the frac job. Because proppant typically represents only about 5% of the total material pumped by volume, and most of the proppant is concentrated very close to the lateral 105 and frac entry points, the majority of the created surface area does not receive any proppant. Using example fracturing sleeves 130 promotes constructive interference during stage frac operations to drive more “self propping” fracture complexity by enabling cost-effective single entry point, non-sequential staging and simultaneous fracturing of multiple closely-spaced stacked lateral completions from a multi well pad site (“4D completion” concept). Completions that use example fracturing sleeves 130 enable delivery of high-performance wells with significantly less proppant, resulting in significantly reduced costs.

[0055] Figure 2 shows results of a multi-well fracturing operation using techniques currently used in the art. Referring to Figures 1 A through 2, the system 200 of Figure 2 shows a plan view of the substantially horizontal sections of 3 different wellbores 220 in the subterranean formation 210. Wellbore 220-1 is disposed adjacent to wellbore 220-2, which is disposed adjacent to wellbore 220-3. The fracturing of the wellbores 220 of Figure 2 were conducted using the P n’ P method, as discussed above. As a result, the various fractures 201 of each wellbore 210 have inconsistent penetration lengths perpendicular to the wellbores 220. Further, there are large pockets of undisturbed formation 292, which means that the subterranean resource in those pockets of undisturbed formation 292 will not be as efficiently extracted.

[0056] In addition, the overlap of fractures 201 between adjacent wellbores 220 result in an overstimulation or waste of resources (e.g., time, money, energy and materials to provide fracturing fluid at high pressure), as additionally fracturing part of a formation 210 that has already been fractured results in no added yield of subterranean resources from the formation 210. In other words, the fracturing operations of the current art result in inconsistent fracturing geometries, which leads to poor multi-well / FFD recovery efficiency, fracturing hits, fracturing “out of zone”, and challenges related to future productivity enhancement interventions.

[0057] Figure 3 shows results of a multi-well fracturing operation in plan view using example embodiments. Referring to Figures 1A through 3, the system 300 of Figure 3 shows the substantially horizontal sections of 3 different wellbores 320 in the subterranean formation 310. Wellbore 320-1 is disposed adjacent to wellbore 320-2, which is disposed adjacent to wellbore 320-3. The fracturing of the wellbores 320 of Figure 3 were conducted using the example fracturing sleeves in an example single entry point, non- sequential manner described below. As a result, the various fractures 301 of each of the wellbores 320 have consistent penetration lengths perpendicular to each wellbore 320 and consistent coverage along the entire lateral length (substantially horizontal section) of each of the wellbores 320. Further, there are essentially no pockets of undisturbed formation 392, which means that the vast majority of the subterranean resources in this part of the formation 310 can be extracted. [0058] In addition, there is little or no overlap of fractures 301 between adjacent wellbores 320. As a result, there is little to no waste of resources. In other words, the fracturing operations using example embodiments results in consistent fracturing network geometries, more fracturing complexity / surface area, and better distribution of fracturing energy and materials covering the targeted SRV-defmed 3D well spacing.

[0059] Hydraulic fractures 301 typically propagate toward lower stress rock and in the direction perpendicular to the current least principal horizontal stress. In the case of a sequential toe-to-heel frac process, as in Figure 2, a significant stress shadow results from pumping tremendous volumes of material in the first stage at the toe compared to what is experienced by the next stage to be stimulated toward the heel of the well (~ 284,000 cu ft of material in the toe stage of a typical Permian 4-well zipper frac process). Stage fracing horizontal wells introduce tremendous local stress changes in the formation by increasing the minimum horizontal stress (Shmin) starting at the toe of the well and then moving systematically toward the heel with each successive group of stages pumped.

[0060] Everything else being equal, each sequential stage pumped subsequent to the initial toe stage in a P n’ P process is thought to have a tendency to propagate at an oblique angle to the wellbore, which is oriented toward the heel of the well where there has not been any injection operations yet (e.g., lower stressed rock). This is often referred to as heel-side bias since the perf clusters closest to the heel in a given stage often take a disproportionate amount of the frac rate and materials. In an effort to distribute the frac energy and materials equally along the entire completed lateral length, current P n’ P techniques often include limited entry perforating, variable shot cluster perforating, using only 100 mesh with low viscosity slickwater, chemical diverters, and wine rack landing zone strategies. However, achieving high perforation cluster efficiency (more equal distribution of material leaving the wellbore at each cluster) is still a challenge for several reasons, including the above-described intra-well and inter-well stress shadowing phenomena.

[0061] Using example fracturing sleeves helps to ensure “100% cluster efficiency” via single entry point staging, which can also be used to mitigate the risk of detrimental frac hits into previously produced offset or “parent” wells. In these cases, previously produced parent wells cause a production-induced stress shadow which biases fracture propagation from the “child” well toward the stress sink and further contributes to poor cluster efficiency using the multi-entry point P n’ P completion method. In a worst-case scenario, nearly all of the - 100 BPM injection rate is concentrated into one per cluster, which is detrimental to the goal of maximizing fracture complexity and containing fracture networks within the child well’s targeted SRV, which is defined by offset well spacing strategy.

[0062] Example fracturing sleeves enable having one frac entry point per stage (e.g., pumping 45 BPM will exit the wellbore at one location in the lateral) and allowing for pumping the stages in a pre-programmed, SME-defmed order up and down the wellbore that is not sequential. For example, the “Texas 2-Step” (as shown in Figure 17 below) can be implemented by fracing stage 1, then stage 3, then stage 2 (numbered order of frac entry points from toe to heel). This may create more stress homogeneity for the middle frac stage, which should promote non-planar hydraulic fractures that exploit various planes of weakness or other rock fabric features in the targeted “reservoir” such as natural fractures, thin lithofacies surfaces, and lower compressive strength minerology.

[0063] Also, fracturing multiple adjacent wells at the same time (simul -fracing), landing the laterals in a wine-rack stacked pattern (multiple sub-landing zones), and using non-sequential staging can promote more shear slippage fracturing events as the tremendous volumes of frac fluid are pushing on the reservoir in a prescribed, but non-sequential manner. This approach, using example fracturing sleeves, strategically “torques the rock” to steer fractures and promote constructive interference with previous frac stages pumped in the well and from neighbor wells that are being fractured simultaneously. In other words, completions using example fracturing sleeves can exploit stress shadowing to promote greater fracture network complexity, address cluster efficiency challenges, improve containment of hydraulic fractures within the targeted SRV, reduce completion cycle time, and greatly simplify the operation and frac spread equipment on location.

[0064] Figures 4A through 4E show a sequence of a multi-well fracturing operation in plan view using example embodiments. Referring to Figures 1 A through 4E, the system 400 of Figures 4A through 4E show the substantially horizontal sections of 3 different wellbores 420 in a subterranean formation 410. Wellbore 420-1 is disposed adjacent to wellbore 420-2, which is disposed adjacent to wellbore 420-3. The fracturing of the wellbores 420 of Figures 4 A through 4E are conducted using the example fracturing sleeves described below, for example in Figure 6, as part of a casing string (such as casing string 125). The system 400 of Figures 4A through 4E also includes a firac ball launcher 491 and a fluid pumping system 404.

[0065] The fluid pumping system 404 can include one or more pumps and one or more valves to pump, often at high pressure and/or flow rates, one or more fluids (e.g., a fracturing fluid) into one or more of the wellbores 420 at a given point in time. The fluid pumping system 404 operates during each stage of the fracturing operation. Between stages, there can be times when the fluid pumping system 404 is shut down. The frac ball launcher 491 can release one or more frac balls down one or more wellbores 420 at various times (e.g., before the start of a new stage in the fracturing operations) so that the frac balls, carried by the fluid, travel toward the toe of the wellbore 420 in which it was released.

[0066] In Figure 4A, a single fracturing operation stage is performed at location 1 in each of the wellbores 420 at or nearly at the same time. Location 1 is toward the toe (distal end) of each of the wellbores 420. At a subsequent time relative to the time captured in Figure 4A, as shown in Figure 4B, another single fracturing operation stage is performed at location 2 in each of the wellbores 420 at or nearly at the same time. Location 2 somewhat is close to location 1, but is closer to the heel of the wellbore 420. At a subsequent time relative to the time captured in Figure 4B, as shown in Figure 4C, yet another single fracturing operation stage is performed at location 3 in each of the wellbores 420 at or nearly at the same time. Location 3 is located between location 2 and location I in each wellbore 420.

[0067] At a subsequent time relative to the time captured in Figure 4C, as shown in Figure 4D, three more fracturing operation stages have been individually performed at locations 4, 5, and 6 in each of the wellbores 420 at or nearly at the same time. Locations 4, 5, and 6 are all located toward the heel of the wellbores 420 relative to location 2 of those wellbores 420, with the order from the toe to the heel being location 5, location 4, and location 6. The spacing between location 4 and location 5 in each wellbore 420 is substantially the same as the spacing between location 5 and location 2, location 2 and location 3, and location 3 and location I . There is about twice the spacing between location 6 and location 4. In the time frame captured in Figure 4D, location 4 is fractured first, followed by location 5, followed by location 6 for each wellbore 420.

[0068] At a subsequent time relative to the time captured in Figure 4D, as shown in Figure 4E, the final three fracturing operation stages have been individually performed at locations 7, 8, and 9 in each of the wellbores 420 at or nearly at the same time. Locations 7, 8, and 9 are all located toward the heel of the wellbores 420 relative to location 4 of that wellbore 420, with the order from the toe to the heel being location 1, location 3, location 2, location 5, location 4, location 7, location 6, location 9, and location 8. The spacing between adjacent locations in each wellbore 420 is substantially equidistant. In the time frame captured in Figure 4E, location 7 is fractured first, followed by location 8, followed by location 9 for each wellbore 420.

[0069] This method of fracturing according to example embodiments is sometimes referred to in the industry as “Texas Two-Step” and offers several benefits over the current sequential toe-to- the-heel methods of fracturing that are commonly used in UCR completions. For example, in the current P n’ P method of fracturing, multiple locations or perf clusters are fractured within a wellbore at one time as a discrete fracture stage. This requires a larger volume of fracturing fluid and/or delivering the fracturing fluid at a higher rate and surface treating pressure relative to what needs to be delivered in the system 400 of Figures 4A through 4E, where only a single location within one of the wellbores 420 is fractured at a time as a discrete stage.

[0070] As another example, in the current method of fracturing, the frac entry point locations of each subsequent frac stage always move from the toe of the horizontal section to the heel. This systematic and sequential frac staging process starting near the toe of a wellbore 420 and ending near the heel of the wellbore 420 is known to contribute to the problem of poor perf cluster efficiency, which is illustrated in Figure 2. By fracturing stages in such a sequential order, a phenomenon commonly known as “stress shadowing” occurs. In this case, stress shadowing is caused by stress buildup in the previous frac stage biasing fracture initiation and growth of the stage currently being pumped away from the perf clusters located proximal to the previous frac stage. By contrast, the location of subsequent fracturing stages in one of the wellbores 420 can be toward the toe or toward the heel in non-sequential fashion to avoid stress shadowing bias. As a result, example embodiments allow for a fracturing operation that leads to more consistent and complete coverage of the targeted SRV, such as what is shown in Figure 3 above.

[0071] For the fracturing operation captured by Figures 4A through 4E, a stage performed at a certain location (e.g., location 4) in one wellbore 420 (e.g., wellbore 420-1) can be performed at or nearly at the same time and for the same or nearly the same period of time (e.g., 30 minutes) as the corresponding location of one or more other wellbores 420. Alternatively, a stage performed at a certain location in one wellbore 420 can be performed at a different time and/or for a different period of time relative to the corresponding location of one or more other wellbores 420. [0072] Figures 5A through 5E show another sequence of a multi-well fracturing operation using example embodiments. Referring to Figures 1 A through 5E, the system 500 of Figures 5 A through 5E show in plan view the substantially horizontal sections of 3 different wellbores 520 in a subterranean formation 510. Wellbore 520-1 is disposed adjacent to wellbore 520-2, which is disposed adjacent to wellbore 520-3. The fracturing of the wellbores 520 of Figures 5 A through 5E are conducted using the example fracturing sleeves described below, for example in Figure 6, as part of a casing string (such as casing string 125). The system 500 of Figures 5 A through 5E also includes a firac ball launcher 591 and a fluid pumping system 504, which can be substantially the same as the corresponding systems and mechanisms discussed above.

[0073] In Figure 5A, a single fracturing operation stage is performed at location 1 in each of the wellbores 520 at or nearly at the same time. Location 1 is toward the toe of the wellbore 520- 1. Location 1 is toward the middle but closer to the toe of the wellbore 520-2. Location 1 is toward the heel of the wellbore 520-3. At a subsequent time relative to the time captured in Figure 5 A, as shown in Figure 5B, another single fracturing operation stage is performed at location 2 in each of the wellbores 520. For wellbore 520-1, location 2 toward the middle but closer to the heel. For wellbore 520-2, location 2 is close to the heel. For wellbore 520-3, location 2 is about halfway between the middle and the toe.

[0074] At a subsequent time relative to the time captured in Figure 5B, as shown in Figure 5C, two more fracturing operation stages have been individually performed at locations 3 and 4 in each of the wellbores 520. For wellbore 520-1, location 3 is about halfway between the middle and the toe, and location 4 is toward the heel. For wellbore 520-2, location 3 is toward the toe, and location 4 is near and to the right of location 1. For wellbore 520-3, location 3 is toward the middle but closer to the heel, and location 4 is near the toe. In the time frame captured in Figure 5C, location 3 is fractured first followed by location 4 for each wellbore 520.

[0075] At a subsequent time relative to the time captured in Figure 5C, as shown in Figure 5D, another single fracturing operation stages have been performed at location 5 in each of the wellbores 520. For wellbore 520-1, location 5 is near and to the left of location 1. For wellbore 520-2, location 5 is toward the middle but closer to the heel. For wellbore 520-3, location 5 is about halfway between the middle and the toe.

[0076] At a subsequent time relative to the time captured in Figure 5D, as shown in Figure 5E, the final four fracturing operation stages have been individually performed at locations 6, 7, 8, and 9 in each of the wellbores 520. For wellbore 520-1, the order from the toe to the heel is location 1, location 5, location 8, location 3, location 7, location 9, location 2, location 6, and location 4. For wellbore 520-2, the order from the toe to the heel is location 3, location 7, location 6, location 4, location 1, location 9, location 5, location 8, and location 2. For wellbore 520-3, the order from the toe to the heel is location 4, location 6, location 2, location 5, location 9, location 8, location 3, location 7, and location 1. The spacing between adjacent locations in each wellbore 520 is substantially equidistant. In the time frame captured in Figure 5E, location 6 is fractured first, followed by location 7, followed by location 8, followed by location 9 for each wellbore 520. This method is referred to as “Relax-a-Frac” because this single entry point, non- sequential staging method allows for a maximum stress relaxation and fracture surface lubrication time between fracturing one location or frac entry point of a wellbore 520 (e.g., wellbore 520-2) and fracturing an adjacent location in the same or adjacent wellbore 520 (e.g., wellbore 520-1).

[0077] The benefits related to addressing systematic stress shadowing caused by a sequential toe-to-heel staging process of the current P n’ P multi-stage frac process and realized by this method of fracturing according to example embodiments are similar to the benefits set forth with respect to the system 400 of Figures 4 A through 4E. For the fracturing operation captured by Figures 5A through 5E, a stage performed at a certain location (e.g., location 5) in one wellbore 520 (e.g., wellbore 520-1) can be performed at or nearly at the same time and for the same or nearly the same period of time (e.g., 30 minutes) as the corresponding location of one or more other wellbores 520. Alternatively, a stage performed at a certain location in one wellbore 520 can be performed at a different time and/or for a different period of time relative to the corresponding location of one or more other wellbores 520.

[0078] Figure 6 shows a subassembly 699 that includes a fracturing sleeve 630 according to certain example embodiments. Referring to Figures 1 A through 6, the subassembly 699 includes the fracturing sleeve 630, which is directly coupled to two casing pipes 624. Specifically, the left end of the fracturing sleeve 630 is coupled to the casing pipe 624-1 using coupling features 627 (e.g., mating threads), and the right end of the fracturing sleeve 630 is coupled to the casing pipe 624-2 using coupling features 627 (e.g., mating threads). The subassembly 699 is part of a casing string (such as casing string 125) that is disposed in a wellbore 620 in a subterranean formation 610. In addition, cement 609 has been placed into the space between the outer surfaces of the fracturing sleeve 630 and the casing pipes 625 and the inner surface of the wellbore 620 via a cement pumping operation. The inner diameter 629 of the fracturing sleeve 630 (defined by the wall 658) is greater than the inner diameter 628 of the casing pipes 625 in this case. In alternative embodiments, the inner diameter 629 of the fracturing sleeve 630 can be the same as the inner diameter 628 of the casing pipes 625.

[0079] The example fracturing sleeve 630 has multiple components. For example, in addition to the coupling features 1627 used to couple to the casing pipes 625, the fracturing sleeve 630 includes a mandrel 650, an outer wall 658, a ball seat assembly 670, a number of sealing devices 653, one or more sensor devices 660, a controller 640 (which can include a timer), one or more retention devices 657, and one or more energy storage devices 665. The wall 658 in this case forms a cylinder. The wall 658 has multiple ports 659 (sometimes referred to as wall fracturing ports 659 or simply as ports 659 herein) that traverse some or all of the thickness of the wall 658. The ports 659 are located toward the end of the fracturing sleeve 630 oriented toward the heel of the wellbore 620.

[0080] The mandrel 650 is slidably movable within the cavity 655 formed by the wall 658. The mandrel 650 has a wall 651 that forms a cylinder. The wall 651 has multiple ports 652 (sometimes referred to as mandrel fracturing ports 652 or as pre-existing frac ports 652 herein) that traverse some or all of the thickness of the wall 651. The ports 652 are located toward the end of the fracturing sleeve 630 oriented toward the heel of the wellbore 620. As the mandrel 650 moves within the cavity 655, there are a number of positions that the mandrel 650 has, for example, relative to the ports 659 in the wall 658. In Figure 6, the mandrel 650 is in a closed position (also called a first closed position) because the ports 652 of the mandrel 650 are located toward the heel of the wellbore 620 relative to (and so are not aligned with) the ports 659 in the wall 658. At least one sealing device 653 separates and isolates the ports 652 of the mandrel 650 from the ports 659 in the wall 658.

[0081] The sealing devices 653 are disposed at different points along the length of the mandrel 650 between the outer surface of the wall 651 of the mandrel 650 and the inner surface of the wall 658. In this case there are five sealing devices 653. Examples of a sealing device 653 can include, but are not limited to, a gasket and an O-ring. Each sealing device 653 is designed to prevent the passage of fluids and other debris therethrough. In addition, each sealing device 653 prevents the mandrel 650 from moving to a different position unless a minimal force is applied to the mandrel 650 along the length of the fracturing sleeve 630. [0082] The ball seat assembly 670 of the fracturing sleeve 630 is disposed at the distal end of the mandrel 650. The ball seat assembly 670 can be coupled to the mandrel 650. Alternatively, the ball seat assembly 670 can be integrated with the mandrel 650. The ball seat assembly 670 can have multiple positions. For example, in this case, the ball seat assembly 670 of the fracturing sleeve 630 has an open position (as shown in Figure 6, also called an open BSA position) and a closed position (as shown in Figure 8 below, also called a closed BSA position). As discussed below, when the ball seat assembly 670 is in the closed position, it is configured to retain a frac ball. The position of the ball seat assembly 670 can be controlled by the controller 640. The ball seat assembly 670 can include multiple components. An example of a ball seat assembly is provided in detail below with respect to Figures 18 through 25.

[0083] The distal end of the ball seat assembly 670 forms a side of a cavity 656 inside of which the controller 640, the one or more retention devices 657, the one or more sensor devices 660, and the energy storage device 655 are positioned. The cavity 656 also is bounded by a wall 654 and part of the wall 658. As the mandrel 650 (and so the ball seat assembly 670) moves along the length of the fracturing sleeve 630, the size of the cavity 656 changes. In certain example embodiments, the controller 640, the one or more retention devices 657, the one or more sensor devices 660, and the energy storage device 665 are in a fixed position. In such a case, the placement of those components can be toward the distal end of the cavity 656, outside the range of movement of the mandrel 650. In some cases, one of the components (e.g., the energy storage device 665) can be used to set a boundary or stop for the maximum distal movement of the mandrel 650 within the cavity 655 of the fracturing sleeve 630. When the ball seat assembly 670 includes a sealing device (such as sealing device 653), the cavity 656 can be relatively protected from the influx of fluids and debris.

[0084] The controller 640 of the fracturing sleeve 630 is configured to communicate with and/or control one or more other components of the fracturing sleeve 630. For example, the controller 640 can be configured to receive measurements made by each of the sensor devices 660. As another example, the controller 640 can change the position of the ball seat assembly 670. In such a case, the control can be based on a measurement of a sensor device 660. The controller 640 can operate using power provided by the energy storage device 665. More details about the controller 640 and its components are provided below with respect to Figure 16. [0085] Each sensor device 660 is used to measure one or more parameters. Examples of such parameters can include, but are not limited to, presence of a magnetic field and pressure. A sensor device 660 can include one or more of a number of components, including but not limited to a sensor (e.g., sensor 1661 of Figure 16 below), a housing, and wiring. Examples of a sensor of a sensor device 1660 can include, but are not limited to, a magnetometer and a pressure sensor. Each sensor device 660 is communicably coupled to the controller 640. If the sensor device 660 requires power to operate, then the sensor device 660 can receive power, directly or indirectly, from the energy storage device 665.

[0086] The energy storage device 665 provides power to the controller 640, the sensor devices 660, and any other components of the fracturing sleeve 630 that require power to operate. The energy storage device 665 can be or include one or more batteries, one or more supercapacitors, and/or any other device that can store and distribute power. The energy storage device 665 can have an energy saving mode and/or have recharging capability to extend the amount of time that the energy storage device 665 can be disposed with the fracturing sleeve 630 in the wellbore 620 before being used.

[0087] A retention device 657 is a component that is meant to retain the mandrel 650 in a particular position (e.g., the open position) within the cavity 655 of the fracturing sleeve 630. Examples of a retention device 657 can include, but is not limited to, a pin, a clamp, and a tab. A retention device 657 can be retractable (e.g., as controlled by the controller 640). Alternatively, a retention device 657 can be a single-use device that mechanically fails based on some factor (e.g., passage of time, an amount of minimum force applied against the retention device 657).

[0088] Figures 7 through 14B show how the example fracturing sleeve 630 of Figure 6 can be used during a fracturing operation. Referring to Figures 1 A through 14B, the subassembly 799 of Figure 7 shows the subassembly 699 of Figure 6 between fracture stages (or before the first stage that is pumped through an example fracturing sleeve) of a fracturing operation. Specifically, a frac ball 735 (sometimes more simply referred to herein as a ball 735) is injected into the wellbore 620 at the surface (e.g., surface 108) by a frac ball launcher (e.g., frac ball launcher 191). Each ball 735 is circulated by the fluid 728 downhole at a high velocity, eventually passing through the cavity 655 of the example fracturing sleeve 630 at the time captured in Figure 7. If the time captured in Figure 7 is before the pumping the first fracture stage of the fracturing operation through an example fracturing sleeve of the present invention is activated, then the frac ball 735 is released directly by the frac ball launcher at the surface (e.g., surface 108) and passes to the pressure-activated toe sleeve (e.g., toe sleeve 195), disposed toward the toe of the wellbore 620, without being stopped in its progress along the length of the casing string. If the time captured in Figure 7 is between stages of the fracturing operation using example fracturing sleeves (similar to the fracturing sleeve 630) of the present invention, then the frac ball 735 is released by the ball seat assembly (similar to the ball seat assembly 670) of a fracturing sleeve (similar to the fracturing sleeve 630) that is upstream (closer to the heel of the wellbore 620 relative to the position of the fracturing sleeve 630 within the wellbore 620.

[0089] As the system 799 of Figure 7 shows, the mandrel 650 is still in the first closed position so that at least one sealing device 653 separates and isolates the ports 652 of the mandrel 650 from the ports 659 in the wall 658. While the frac ball 735 has passed the ball seat assembly 670, which remains in the open position, the frac ball 735 has not yet passed by the sensor device 660. The sensor device 660 is communicably coupled to the controller 640 and receives power from the energy storage device 665.

[0090] The subassembly 899 of Figure 8 shows the subassembly 799 of Figure 7 a very brief period of time later, still between fracture stages (or before the first stage that is pumped through an example fracturing sleeve) of a fracturing operation. Specifically, the frac ball 735, still propelled by the fluid 728, is now passed through the cavity 655 of the fracturing sleeve 630 at the time captured in Figure 8. In this case, all of the frac balls released by the frac ball launcher (e.g., frac ball launcher 191) are magnetic. Also, in this example, the sensor device 660 is or includes a magnetometer sensor. As a result, when the magnetized frac ball 735 passes by the sensor device 660, the sensor device 660 measures the magnetic field (a type of parameter) emitted by the frac ball 735.

[0091] The sensor device 660 sends its measurement to the controller 640, which determines that the amount of magnetic field exceeds a threshold value. Upon making this determination, the controller 640 increments a count that is accumulating based on each such measurement made by (and so each time a frac ball passes by) the sensor device 660. Put another way, the sensor device 660 and the controller 640 (powered by the energy storage device 665) work together in this example to determine when a frac ball has passed through the fracturing sleeve 630 a certain number of times, which is correlative with the number of actual frac stages pumped. When the count reaches a threshold value, the controller 640 takes an action based on pre-programming of the controller 640. Each fracturing sleeve 630 included in the completion of the wellbore 620 is pre-programmed to actuate on a different count, corresponding to a different fracturing stage. In this example, the controller 640 operates the ball seat assembly 670 from the open BSA position to the closed BSA position. The combination of the controller 640 determining the threshold value of the measurement by the sensor device 660 and the threshold value of the count can collectively be defined as determining a threshold condition. Those of ordinary skill in the art will appreciate that there can be other ways in which the ball seat assembly 670 can be operated from the open BSA position to the closed BSA position.

[0092] When the ball seat assembly 670 is in the closed BSA position, the ball seat assembly 670 extends into the cavity 655 a certain distance so that the next frac ball that passes through the cavity 655 of the fracturing sleeve 630 is retained by the ball seat assembly 670. Even though the ball seat assembly 670 is in the closed BSA position in Figure 8, without a subsequent frac ball to become seated in the ball seat assembly 670, the mandrel 650 remains in the first closed position (so that at least one sealing device 653 separates and isolates the ports 652 of the mandrel 650 from the ports 659 in the wall 658) because the flow of the fluid 728 is not great enough to force the mandrel 650 to move distally by flowing past the ball seat assembly 670 in the closed BSA position.

[0093] The subassembly 999 of Figure 9 shows the subassembly 899 of Figure 8 some period of time later. This later period of time may be before the next (or first) stage of the fracturing operation or after a stage of the fracturing operation has recently been completed. Specifically, the frac ball 935, propelled by the fluid 728 that is pumped by the fluid pumping system and released by the frac ball launcher, after entering the cavity 655 of the fracturing sleeve 630, is engaged with the ball seat assembly 670 in the closed BSA position at the time captured in Figure 9. The frac ball 935, when engaged with the ball seat assembly 670 in the closed BSA position within the cavity 655 of the fracturing sleeve 630, essentially creates a plug or barrier within the cavity 655 and thus prevents fluid flow from above the frac ball 935 past the ball seat assembly 670 and into the open ports of the toe sleeve (e.g., toe sleeve 195) or open “wet shoe” toward the toe of the wellbore 620. As the fluid 728 continues to be pumped by the fluid pumping system, the fluid 728 pushing against the frac ball 935 and ball seat assembly 670 generates enough lateral force to move the mandrel 650 distally (toward the toe of the wellbore 620) until the ball seat assembly 670 (or distal end of the mandrel 650) abuts against the retention device 657. [0094] When the mandrel 650 makes contact with the retention device 657, the mandrel 650 is maintained at that position because the retention device 657 is sufficient enough to withstand the continued flow of the fluid 728. When the mandrel 650 abuts against the retention device 657, the mandrel is in the open position because the ports 652 of the mandrel 650 are substantially aligned with the ports 659 in the wall 658. In addition to the retention device 657, the fracturing sleeve 630 can remain in the open position because of the friction force applied to the wall 651 of the mandrel 650 by the sealing devices 653. Once the mandrel 650 of the fracturing sleeve 630 is in the open position, the fluid pumping system pumps the fluid 728 through the cavity 655.

[0095] At this point in time, the mandrel of all of the other example fracturing sleeves in the casing string (not counting all toe sleeves (e.g., toe sleeve 195), which remain open at all times by the time the fracturing operation begins to maintain a robust flow path) are in a closed position except for the mandrel 650 of the fracturing sleeve 630 in Figure 9. Example embodiments do not use plugs, currently used in the art, to isolate portions of a wellbore for a stage of a fracturing operation. Because of the time and resources involved in setting and removing plugs to isolate parts of a wellbore for a stage of a fracturing operation, multiple adjacent entry points in the wellbore are fractured at the same time. By contrast, using example embodiments, only a single entry point (in the case in Figure 9, adjacent to the ports 652 of the mandrel 650 and the ports 659 in the wall 658) is fractured at a time during a stage within a particular wellbore 620. In other words, using example fracturing sleeves and the example method described herein, for each stage of a fracturing operation, only the mandrel of one fracturing sleeve 630 in a wellbore 620 is in the open position while the mandrels of the remainder of fracturing sleeves in the wellbore 620 are in a closed position.

[0096] As discussed above, as a point of clarification, the one or more toe sleeves (e.g., toe sleeve 195) or a “wet shoe” remains open at the toe of the casing string 625 of wellbore 620, but the frac ball 935 and ball seat assembly 670 in the BSA closed position temporarily prevents fracture fluids and proppant from bypassing the single entry point caused by the alignment of ports 652 of the mandrel 650 with the ports 659 in the wall 658. Toe sleeves and “wet shoes” are known in the art, but are used, in an open position, in conjunction with example fracturing sleeves 630 during multi-stage fracturing operations. Specifically, before the first fracturing stage begins in a fracturing operation, the toe sleeve is opened and remains open throughout the fracturing operation. In an open state, the toe sleeve can establish and maintain a flow path to the toe of the wellbore. Alternatively, a “wet shoe” technique can be used to establish a flow path to the toe of the well during a fracturing operation.

[0097] The subassembly 1099 of Figure 10 shows the subassembly 999 of Figure 9 some period of time later. Specifically, the fluid pumping system (e.g., fluid pumping system 104) continues pumping the fluid 728 (e.g., fracturing fluid) into the wellbore 620 at high rates and/or high pressure. However, since only a single entry point in the entire wellbore 620 is being fractured at this stage, the velocity and/or pressure required to effectively fracture the subterranean formation 610 is significantly less than what is required in the current art, where multiple entry points are fractured at once during a single stage of a fracturing operation. Furthermore, the single entry point staging of the present invention provides greater assurance that all of the designed fracture fluid volumes and proppant amounts designated for the given stage are leaving the wellbore 620 at the desired location than current multi -entry point fracturing (e.g., P n’ P), where a disproportionate amount of the fracturing fluids and proppant may be exiting the wellbore 620 at the frac entry points or perf clusters located toward the heel of the wellbore 620 for the reasons previously described.

[0098] As the fracturing fluid 728 is pumped into the wellbore 620 and reaches the cavity 655 of the fracturing sleeve 630, the fluid 728 flows through the ports 652 of the mandrel 650 and the ports 659 in the wall 658 to penetrate the cement 609 and create fractures 1001 in the subterranean formation 610. Since the single point of entry within the wellbore 620 is targeted, the fractures 1001 that result in this stage of the fracturing operation have the desired uniformity and consistency, as shown above with respect to Figure 3.

[0099] The pumping operation of each fracture stage typically lasts for a certain known duration (e.g., 30 to 45 minutes) for a given well completion design. The timer functionality of the controller 640 can record the duration that the fracturing sleeve 630 has been in the open position, whereby the ports 652 of the mandrel 650 and the ports 659 in the wall 658 are in alignment. The controller 640 can be pre-programmed to enable triggering the release of the retention device 657 after a certain duration (also called a time threshold value) (e.g., 45 minutes) of the fracturing sleeve 630 being in the open position. Briefly stopping the fluid pumping system after completing the pumping operation used to place the designed volume of fracturing fluids and amount of proppant will signal the controller 640 that the end of the stage of the fracturing operation has occurred if the duration condition of the fracturing sleeve 630 in the open position has been met. This scenario is captured in Figure 10 immediately before the controller 640 triggers the release of retention device 657, which allows the mandrel 650 to continue a measured movement down toward the heel of the wellbore 620 such that the ports 652 of mandrel 650 are no longer aligned with the ports 659 in the wall 658 (the mandrel 650 moves to the second closed position).

[0100] Because of the configuration of the example fracturing sleeve 630, where each sleeve has multiple fracturing ports 659 in the outer wall 658, there is no need to perform a perforating operation before the fracturing operation begins. In other words, there is no need to use resources to run equipment into the wellbore 620 after the casing string is inserted and the cement 609 is displaced via a pumping operation and has cured in order to perforate or make holes in the casing pipe so that the formation can be fractured in a subsequent fracturing operation.

[0101] The subassembly 1199 of Figure 11 shows the subassembly 1099 of Figure 10 some period of time (e.g., a fraction of a second) later. Specifically, at the end of the stage of the fracturing operation in which the fracturing sleeve 630 is used, the mandrel 650 moves from the open position to the second closed position. When this occurs, the ports 652 of the mandrel 650 no longer align with, and in fact are isolated from, the ports 659 in the outer wall 658 of the fracturing sleeve 630, preventing the fluid 728 from continuing to create the fractures 1001 in the subterranean formation 610. The mandrel 650 can be moved from the open position to the second closed position in one or more of a number of ways. For example, the retention device 657 has been retracted or destructed (e.g., by an action of the controller 640, by dissolving in a fluid (e.g., fluid 728), allowing the fluid 728, still flowing through the cavity 655, to push the mandrel 650 in a further distal direction so that the mandrel 650 moves from the open position to a second closed position, as shown in Figure 11. While the mandrel 650 is in the second closed position at this time, the ball seat assembly 670 remains in the closed BSA position, which means that the frac ball 935 continues to be engaged with the ball seat assembly 670.

[0102] In the second closed position, the distal end (in this case, the ball seat assembly 670) of the mandrel 650 abuts against the energy storage device 665, a sensor device 660, and/or some other component (e.g., another retention device) within the cavity 656, which is now very small compared to its size when the mandrel 650 is in the first closed position, as in Figure 7. When the mandrel 650 is in the second closed position, the ports 652 of the mandrel 650 are no longer aligned with the ports 659 in the wall 658, and at least one sealing device 653 separates and isolates the ports 652 of the mandrel 650 from the ports 659 in the wall 658. Further, at least one additional sealing device 653 isolates the ports 659 in the wall 658 from the cavity 655.

[0103] The removal/retraction of the retention device 657 can be performed in one or more of a number of ways. For example, the controller 640, powered by the energy storage device 665, can set a timer based on the amount of time since a sensor device 660 has first detected the fracturing sleeve 630 in the first open position (corresponding to a stage of the fracturing operation) and automatically retract the retention device 657 when a threshold amount of time has elapsed and the fluid pumping system has been shut-down. As another example, when the controller 640 determines (e.g., using another sensor device 660 and the onboard timer of the controller 640) that the stage of the fracturing operation has ended, the controller 640 can initiate a mechanical shearing of the retention device 657.

[0104] As yet another example, once the stage of the fracturing operation has begun, an atmospheric chamber within the cavity 656 can be opened (e.g., by the controller 640 and a sensor device 660 that detects the fracturing sleeve 630 in the open position) to release a chemical that dissolves the retention device 657 in a known period of time, which is calculated to be slightly greater than the duration of the stage of the fracturing operation. Those of ordinary skill in the art can appreciate other ways in which the mandrel 650 can be moved from the open position to the second closed position.

[0105] The subassembly 1299 of Figure 12 shows the subassembly 1199 of Figure 11 a brief period of time later. Specifically, the fracture pumping system remains pumping the fluid 728 into the wellbore 620, but in this case, the ball seat assembly 670 has reverted to the open position, thereby releasing the frac ball 935. When this occurs, the frac ball 935 is carried by the fluid 728 flowing distally in the cavity 655 toward the toe of the wellbore 620. At least one sealing device 653 continues to separate and isolate the ports 652 of the mandrel 650 from the ports 659 in the wall 658. Further, at least one additional sealing device 653 continues to isolate the ports 659 in the wall 658 from the cavity 655.

[0106] The ball seat assembly 670 can be operated from the closed BSA position to the open BSA position in any of a number of ways. For example, once the distal end of the mandrel 650 abuts against the energy storage device 665, a sensor device 660, or some other form of a stop (e.g., another retention device), a mechanical release can be activated to trigger the operation of the ball seat assembly 670 from the closed BSA position to the open BSA position. [0107] As another example, a sensor device 660 that includes a proximity sensor can detect that the mandrel 650 has moved to the second closed position. The controller 640, in communication with the sensor device 660, can trigger a release to operate the ball seat assembly 670 from the closed BSA position to the open BSA position. As still another example, a ball seat assembly 670 configured as shown and described with respect to Figures 18 through 25 below can be used to trigger its own operation from the closed BSA position to the open BSA position. Those of ordinary skill in the art will appreciate that there can be other ways to operate the ball seat assembly 670 from the closed BSA position to the open BSA position.

[0108] When the ball seat assembly 670 of the fracturing sleeve 630 releases the ball 935, the ball 935 can flow with the fluid 728 and engage with a ball seat assembly in a closed position of another fracturing sleeve in the casing string closer to the toe of the wellbore 620. Additionally, or alternatively, the ball 935 can flow with the fluid 728 and trigger a measurement by a sensor device of another fracturing sleeve in the casing string closer to the toe of the wellbore 620, thereby triggering the operation of the ball seat assembly 670 from the open position to the closed position, much in the same way that the ball seat assembly 670 of the fracturing sleeve 630 in this example operated, as shown in Figure 8.

[0109] As yet another alternative, if all fracturing sleeves in the casing string downhole of the fracturing sleeve 630 in this example have already acted as the single entry point of a stage of the fracturing operation, which means that the mandrel of all of these fracturing sleeves is in the second closed position and the ball seat assembly of all of these fracturing sleeves is in the open BSA position, the ball 935 will pass into the toe sleeve (discussed below with respect to Figure 15). In some cases, the ball 935 is made of a material that, in addition to sometimes being made of a magnetic material, also includes a material that can slowly dissolve when exposed to the fluid 728. In such a case, an accumulation of balls in the casing string near the toe sleeve (e.g., toe sleeve 195) or “wet shoe” can be avoided by dissolving them partially or completely over a period of time. Such dissolvable material can be engineered to more quickly dissolve in the presence of low pH (acidic) fluids, which can be used to facilitate the removal of an accumulation of balls near the toe of the wellbore 620.

[0110] The subassembly 1399 of Figure 13 shows the subassembly 1299 of Figure 12 a brief period of time later. Specifically, the subassembly of Figure 13 is an optional embodiment that can be utilized in certain situations. For example, when the fracturing fluid 728 includes relatively high proppant intensity slurries, a coiled tubing (CT) or jointed pipe intervention may be required to clean excess proppant not injected into the fractures 1001 out of the wellbore 620 during flowback. After concluding fracturing operations of all frac stages in the wellbore 620 through the multitude of example fracturing sleeves 630, the mandrel 650 of each fracturing sleeve 630 needs to be moved from the second closed position back to the open position. One way that the mandrel 650 of each fracturing sleeve 630 can be returned to the open position is by using a CT/workstring-conveyed sleeve shifting tool to physically engage the profile of the mandrel 650 of each fracturing sleeve 630.

[0111] The re-opening of each mandrel 650 can be done in one continuous operation starting at the example fracturing sleeve 630 located closest to the toe of the wellbore 620 and moving sequentially to each successive fracturing sleeve 630 towards the heel while continuously circulating out proppant out of the wellbore until all of the fracturing sleeves 630 have been re opened. Figure 14A shows a detailed plan view of part of the fracturing sleeve 630 with the mandrel 650 in the second closed position, and Figure 14B shows a detailed plan view of part of the fracturing sleeve 630 with the mandrel 650 returning to the open position.

[0112] If proppant flowback is not a concern, each example fracturing sleeve 630 may optionally include one or more atmospheric chambers 1493 (or alternative mechanical means for releasing locally stored potential energy), as shown in Figure 14A, for automatically moving the mandrel 650 back to the open position, as shown in Figures 13 and 14B, without a CT/workstring intervention based on a programmed duration after initial sleeve actuation (e.g., 2 weeks) using the controller 640 (with its onboard timer) powered by the energy storage device 665. At the time that the atmospheric chamber 1493 is breached, one or more retention device 657 (as shown in Figures 13 and 14B) can be deployed (e.g., by the controller 640) to prevent the mandrel 650 from traveling beyond the open position to the first closed position. The retention device 657 of Figures 13 and 14B can be the same as, or different than, the retention device 657 discussed above with respect to Figures 6 through 10.

[0113] Figures 15 and 16 show section view drawings of a subassembly 1599 that includes another fracturing sleeve 1530 according to certain example embodiments. Specifically, Figure 15 shows a section view drawing of the fracturing sleeve 1530 with the mandrel 1550 in the second closed position. Figure 16 shows a section view drawing of the fracturing sleeve 1530 with the mandrel 1550 returning to the open position. Referring to Figures 1 through 16, the subassembly 1599 of Figure 15 shows another optional embodiment of a fracturing sleeve 1530 that can be utilized in certain situations. The fracturing sleeve 1530 of Figure 15, including its various components are substantially the same as the fracturing sleeve 630 of Figure 6, including its corresponding components (e.g., the controller 1540, the sensor devices 1560, the energy storage device 1565), except as described below. For example, the fracturing sleeve 1530 is part of a casing string that is disposed in a subterranean formation 1510.

[0114] To address issues related to proppant flowback of the fracturing fluid (e.g., fracturing fluid 728) from the fractures 1501 into the cavity 1555 of the fracturing sleeve 1530 after production operations commence, example fracturing sleeves 1530 may be configured with a proppant flowback control screen/filter 1549 integrated into the wall 1551 of the mandrel 1550 or exterior wall 1558 (not shown) of the fracturing sleeve 1530 which covers a set of “production ports” which are different than the ports 1552 in the wall 1551 of the mandrel 1550 and the ports 1559 in the wall 1558. Degradable material may be used to protect the screen/filter 1549 from plugging with cement and other debris prior to moving the mandrel 1550 of each fracturing sleeve 1530 back to the open position. Moving the mandrel 1550 from the second closed position, as shown in Figure 15, back to the open position, as shown in Figure 16, does not involve operating the ball seat assembly 1570.

[0115] Figure 17 shows a configuration of a multi -well fracturing operation using example embodiments. Referring to Figures 1A through 17, the subsystem 1798 of Figure 17 shows part of a casing string in three substantially horizontal sections of wellbores in a subterranean formation 1410. The part of the casing string 1425 of wellbore 1420 shown in Figure 17 has, from right (toward the toe of the wellbore 1420) to the left (toward the heel of the wellbore 1420), a casing pipe 1424-1, a toe sleeve 1495, a casing pipe 1424-2, a fracturing sleeve 1430-2, a casing pipe 1424-3, a fracturing sleeve 1430-1, a casing pipe 1424-4, a fracturing sleeve 1430-4, a casing pipe 1424-5, a fracturing sleeve 1430-3, and a casing pipe 1424-6.

[0116] The part of the casing string 1625 of wellbore 1620 shown in Figure 17 has, from right (toward the toe of the wellbore 1620) to the left (toward the heel of the wellbore 1620), a casing pipe 1624-1, a toe sleeve 1695, a casing pipe 1624-2, a fracturing sleeve 1630-2, a casing pipe 1624-3, a fracturing sleeve 1630-1, a casing pipe 1624-4, a fracturing sleeve 1630-4, a casing pipe 1624-5, a fracturing sleeve 1630-3, a casing pipe 1624-6, a fracturing sleeve 1630-5, and a casing pipe 1624-7. [0117] The part of the casing string 1725 of wellbore 1720 shown in Figure 17 has, from the right (toward the toe of the wellbore 1720) to the left (toward the heel of the wellbore 1720), a casing pipe 1724-1, a toe sleeve 1795, a casing pipe 1724-2, a fracturing sleeve 1730-2, a casing pipe 1724-3, a fracturing sleeve 1730-1, a casing pipe 1724-4, a fracturing sleeve 1730-4, a casing pipe 1724-5, a fracturing sleeve 1730-3, and a casing pipe 1724-6.

[0118] For all three casing strings in Figure 17, the fracturing sleeves and the casing pipe are substantially the same as the example fracturing sleeves (e.g., fracturing sleeve 630) and casing pipe discussed above. For example, each example fracturing sleeve is programmed to actuate or deploy on a different frac ball count or stage count. The numbering system for the fracturing sleeves of Figure 17 provide an example for how each fracturing sleeve is pre-programmed to actuate the closure of its ball seat assembly based on a stage count as recorded by the controller in each fracturing sleeve and that the sleeve actuation order does not have to be in a toe-to-heel sequence.

[0119] For example, fracturing sleeve 1630-1 is programmed to actuate closure of its ball seat assembly upon the passing of the first magnetic frac ball, fracturing sleeve 1630-2 is programmed to actuate closure of its ball seat assembly upon the passing of the second magnetic frac ball, fracturing sleeve 1630-3 is programmed to actuate closure of its ball seat assembly upon the passing of the third magnetic frac ball, and so forth. Also, after a fracturing sleeve is open for a stage, the mandrel of the fracturing sleeve moves to the second closed position when the stage is complete and before the next stage begins. In this example, fracturing sleeve 1630-2, which is opened second, is located closer to the toe of the well than fracturing sleeve 1630-1, which is opened first. Also, fracturing sleeve 1630-4, which is opened forth, is located closer to the toe of the well than fracturing sleeve 1630-3, which is opened third. This shows the non-sequential (relative to the traditional toe-to-heel sequencing) frac staging that can be employed using example fracturing sleeves.

[0120] For all three casing strings in Figure 17, the toe sleeve is substantially the same as the toe sleeve discussed above. In other words, the toe sleeves are opened via the application of pressure and other means that allows the initial flow of fluid to be established from the wellhead to the toe of the wellbore before the first stage of the fracturing operation through one of the fracturing sleeves and remains open throughout the multi-stage fracturing operation. This provides a flow path to inject fluid and displace frac balls ultimately to a location near to where the toe sleeve is disposed.

[0121] Figures 18A through 23 show another fracturing sleeve 1830 according to certain example embodiments. Specifically, Figures 18A and 18B show cross-sectional side views of a subsystem 1896 that includes part of the fracturing sleeve 1830 with the mandrel 1850 in a first closed position and with a ball 1835 traveling therethrough. Figure 19 shows a cross-sectional side view of the fracturing sleeve 1830 with the mandrel 1850 in an open position and without the ball 1835. Figure 20 shows a subsystem 2096 that includes the fracturing sleeve 1830 retaining the ball 1835 with the mandrel 1850 in the open position. Figure 21 shows a subsystem 2196 that includes the fracturing sleeve 1830 releasing the ball 1835 when the mandrel 1850 is in the second closed position. Figures 22 A and 22B show perspective views of a ball seat 1871 of a ball seat assembly 1870 of the fracturing sleeve 1830. Figure 23 shows a subassembly 2396 that includes the ball seat 1871 and the support sleeve 1875 of the ball seat assembly 1870 of the fracturing sleeve 1830.

[0122] Referring to Figures 1 A through 23, the fracturing sleeve 1830 is substantially the same as the fracturing sleeves discussed above, except as described below. For example, the fracturing sleeve 1830 of Figures 18A and 18B includes an outer wall 1858, a mandrel 1850 movably disposed within a cavity 1855 formed by the outer wall 1858, and a ball seat assembly 1870. The mandrel 1850 has a wall 1851 with ports 1852 that traverse therethrough toward a proximal end of the mandrel 1850. The fracturing sleeve 1830 of Figures 18A through 23 can be utilized in a single stage of a fracturing operation, including non-sequential fracturing operations.

[0123] For simplicity, components such as the sealing devices, the sensor device, the controller, and the energy storage device, shown and described above with respect to the fracturing sleeve 630 of Figures 6 through 13, are not shown in Figures 18A through 23 even though they are part of the fracturing sleeve 1830. For example, a sensor device (e.g., sensor device 660) can detect the presence of a magnetic field that corresponds to when a ball (e.g., ball 735) with magnetic properties passes through the cavity (e.g., cavity 665) of the fracturing sleeve 1830 near the sensor device. A controller (e.g., controller 640) in communication with the sensor device can determine whether these measurements taken by the sensor device exceed a parameter threshold value (also called a measurement threshold value herein) and, if so, increment a count. The controller can also determine when the count equals a count threshold value. [0124] The fracturing sleeve 1830 includes a ball seat assembly 1870 that moves between an open position (shown in Figures 18A, 18B, and 21) and a closed position (shown in Figures 19 and 20). The ball seat assembly 1870 is disposed within a cavity 1855 formed by the outer wall 1858 of the fracturing sleeve 1830. The fracturing sleeve 1830 includes a coupling feature 1827 at each end that is configured to couple to another component (e.g., a casing tube (casing tube 124), another fracturing sleeve) of a casing string (e.g., casing string 125). In other words, the fracturing sleeve 1830 is configured to be positioned in-line with a casing string within a wellbore (e.g., wellbore 120) of a proposed non-sequentially hydraulic fracturing operation.

[0125] In its default configuration (when the mandrel 1850 is in the first closed position), as shown in Figures 18A and 18B, the ball seat assembly 1870 of the fracturing sleeve 1830 is expanded (in an open position, also called an open BSA position) so that the inner diameter of the ball seat 1870 is slightly larger than the outer diameter of a firac ball 1835. In such a case, the frac ball 1835 (and any subsequent frac balls) can pass through the ball seat assembly 1870 without being engaged by the ball seat assembly 1870. In certain embodiments, one or more ports 1852 (also called pre-existing penetrations frac ports) are incorporated into the wall 1851 of the mandrel 1850. Similarly, although hidden from view by the mandrel 1850 in Figure 18A due to the mandrel 1850 being in the first closed position, one or more ports 1859 (shown in Figure 19 when the mandrel 1850 is in the open position) can be disposed in the outer wall 1858 of the fracturing sleeve 1830.

[0126] The ports 1852 and the ports 1859, when aligned with each other when the mandrel 1850 is in the open position, allow fracturing fluid (e.g., fracturing fluid 728) to flow therethrough during a stage of a fracturing operation in which the fracturing sleeve 1830 is used as the point of entry. Conversely, when the ports 1852 in the mandrel 1850 and the ports 1859 in the outer wall 1858 of the fracturing sleeve 1830 are not aligned with each other (i.e., when the mandrel 1850 is in the first closed position or the second closed position), fracturing fluid is unable to flow through the ports 1859.

[0127] The fracturing sleeve 1830 in this case also includes an atmospheric chamber and piston actuator 1867 that uses a pressure differential to linearly actuate the mandrel 1850 to move between the first closed position (as shown in Figure 18 A), an open position (as shown in Figures 19 and 20), and optionally a second closed position (as shown in Figure 21). In certain exemplary embodiments, the atmospheric chamber, piston actuator 1867, and the piston (which, in this embodiment, is integral to the mandrel 1850) provides the stored energy and mechanical configuration required to simultaneously move the mandrel 1850 from the first closed position to the open position and collapse the ball seat assembly 1870 from the open position to the closed position. The piston actuator 1867 may be electrically triggered to actuate by the controller via a pyro-actuator / rupture disk combination (not shown) or by other actuation methods known to one having ordinary skill in the art.

[0128] The ball seat assembly 1870 in this case includes multiple components. The ball seat 1871 of the ball seat assembly 1870 is disposed at (e.g., coupled to, integrated with, abutting against) the distal end of the mandrel 1850. Figures 22A and 22B show perspective views of the ball seat 1871 in the open position and the closed position, respectively. The ball seat 1871 has a short cylindrical shape defined by a wall 1872. The wall 1872 has a slit 1874 that traverses the wall 1872 along the entire height of the wall 1872. In this case, the slit 1874 has a staggered configuration so that the slit 1874 is not linear along the wall 1872. The non-linear (also called staggered herein) slit 1874 is configured to minimize fluid leakage across the seat when the ball seat 1871 is in the closed position. In addition, the top of the wall 1872 (in this case, the outer surface of the distal end of the wall 1872 when the ball seat 1871 is utilized with the mandrel 1850) has a tapered portion 1873. In the open position, which is the natural state of the ball seat 1871, there is a gap in the slit 1874. When there is a compressive force applied to the outer surface of the wall 1872, the ball seat 1871 is forced into the closed position, where the gap in the slit 1874 disappears.

[0129] Another component of the ball seat assembly 1870 is a support sleeve 1875. In its default state, the support sleeve 1875 is against in a portion 1892 of the outer wall 1858. The support sleeve 1875 has a cylindrical shape (taller than the ball seat 1871) defined by a wall 1876. The wall 1876 has a slit 1878 that traverses the wall 1876 along the entire height of the wall 1876. In this case, the slit 1878 has a staggered configuration so that the slit 1878 is not linear along the wall 1876. The non-linear (also called staggered herein) slit 1878 is configured to minimize fluid leakage when the support sleeve 1875 is in the closed position. In addition, the bottom of the wall 1876 (in this case, the inner surface of the proximal end of the wall 1876 when the support sleeve 1875 is positioned within the fracturing sleeve 1830) has a tapered portion 1877.

[0130] In the open position, which is the natural state of the support sleeve 1875, there is a gap in the slit 1878. When there is a compressive force applied to the outer surface of the wall 1876, such as when the support sleeve 1875 is disposed in the portion 1892, the support sleeve 1875 is forced into the closed position, where the gap in the slit 1878 disappears. The staggered slit 1878 of the support sleeve 1875, when engaged by the ball seat 1871, acts as a leaf spring system and functions to hold the ball seat 1871 in the closed position when the support sleeve 1875 is in the closed position. In certain alternate embodiments, multiple ball seats 1871 can be utilized with a single support sleeve 1875 of a ball seat assembly 1870 of the fracturing sleeve 1830. In addition, or in the alternative, multiple support sleeves 1875 can be utilized with a single ball seat 1871 of a ball seat assembly 1870 of the fracturing sleeve 1830.

[0131] When the mandrel 1850 is in the first closed position, the support sleeve 1875 and the ball seat 1871 are separated from each other. Once the piston actuator 1867 is actuated/energized (e.g., by the controller), the mandrel 1850 moves distally (toward the right in this case) from the first closed position (in Figure 18 A) to the open position (in Figures 19 and 20). As the mandrel 1850 begins to move distally from the first closed position, the ball seat 1871, in the open position, begins to engage a sleeve-to-seat interface 1879, which is tapered and gradually transitions from a larger diameter of the outer wall 1858 to a smaller diameter of the outer wall 1858,. The tapered interface 1879 and the smaller diameter induce not only a longitudinal force but a resulting radial (compressive) force to the outer surface of the wall 1872 of the ball seat 1871 to collapse the ball seat 1871 into its closed position.

[0132] As the mandrel 1850 continues to move distally, the ball seat 1871, remaining in its closed position because of the smaller diameter of the outer wall 1858, begins to engage the stationary support sleeve 1875. Specifically, the tapered portion 1873 of the wall 1872 of the ball seat 1871 begins to make contact with the tapered portion 1877 of the wall 1876 of the support sleeve 1875. Since the support sleeve 1875 is already in the closed position because of the compressive force applied to the outer surface of the wall 1876 by the portion 1892 of the outer wall 1858, as the ball seat 1871 continues to move distally against the stationary support sleeve 1875, the tapered portion 1873 of the wall 1872 and the tapered portion 1877 of the wall 1876 apply a compressive force to the outer surface of the wall 1872 of the ball seat 1871 to force the ball seat 1871 into the closed position. Eventually, the ball sleeve 1871 becomes fully engaged with the support sleeve 1875 and can no longer move distally. This consequently stops the mandrel 1850 from moving further distally, which secures the mandrel 1850 in the open position. [0133] Since the support sleeve 1875 is longer than the ball seat 1871, the support sleeve 1875 functions to support and seal against the ball seat 1871. In this configuration, the support sleeve 1875 and the ball seat 1871 facilitate a two-piece leaf spring design that reduces the overall thickness/stiffness of each component, and so also reduces the stresses applied when the support sleeve 1875 and the ball seat 1871 are in the closed (collapsed) position and are engaged with each other, as shown in Figure 23. In certain example embodiments, the material stresses of the ball seat 1871 and the support sleeve 1875 are maintained in the elastic range, so as to not cause permanent plastic deformation. When in the closed (collapsed) position, the inner diameter IDl of the ball seat 1871 is smaller than the outer diameter of the ball 1875. As a result, the ball 1875, when pushed distally by fluid flowing through the cavity 1855 of the fracturing sleeve 1830, engages the ball seat 1871 of the ball seat assembly 1870. When the fluid is fracturing fluid during a stage of a fracturing operation, this engagement between the ball 1835 and the ball seat 1871 creates a seal that blocks the fluid from continuing to flow through the rest of the cavity 1855 of the fracturing sleeve 1830, thereby diverting the flow of the fracturing fluid into the formation via the ports 1852 in the wall 1851 of the mandrel 1851 and the ports 1859 in the outer wall 1858, which are aligned with each other as a result of moving the mandrel 1850 to the closed position (actuating the fracturing sleeve 1830).

[0134] In certain example embodiments, the laterally distal force applied by the fracturing fluid against the seal created between the ball 1835 and the ball seat 1871 shifts a shroud 1881, positioned at (e.g., coupled to, an extension of, abutting against) the distal end of the support sleeve 1875, distally until a ring 1888 (a type of retention device, such as retention device 1657) disposed in the outer wall 1858 abuts against a protrusion 1887 that extends from the outer surface of the shroud 1881. In some cases, the ring 1888 can be dissolvable. In such cases, when the shroud 1881 is shifted, some of the seals are selectively compromised, and wellbore fluids can contact the dissolvable ring 1888, which initiates the dissolving process. In certain example embodiments, the dissolvable ring 1888 may be constructed of a dissolvable metal. The dissolvable ring 1888 acts as a temporary structural retaining mechanism that keeps the mandrel 1850 in the open position and reacts the pressure loading during the hydraulic fracturing process.

[0135] Careful consideration into factors such as geometry and loading of the ring 1888 must be taken into account to yield a design that gives adequate time to complete the stage of the hydraulic fracturing process for the single entry point afforded by the fracturing sleeve 1830. As a rough approximation, for a dissolvable metal dissolution rate of 100 mg/cm ² *h at 80°C (Terves Spec Sheet Alloy 1132) in a 3% KCL solution, a 3/8 thick ring designed to react a 15,000 psi differential fracturing pressure (with a 1.5 Factor of Safety) would take approximately 2-3 hours to reach a critical activation thickness. One having ordinary skill in the art can verify the dissolution/activation time by testing, and subsequently make adaptations to any given design criteria by altering factors such as, but not limited to, the dissolution medium, the dissolvable component geometry, and the dissolvable alloy type.

[0136] In certain alternate embodiments, due to the nature of the wellbore fluid composition being unknown, the fracturing sleeve 1830 can be designed so that the dissolvable ring 1888 does not contact the wellbore fluids, but rather is subjected to a specifically formulated dissolving liquid, stored in a vessel or chamber within the fracturing sleeve 1830. The vessel or chamber storing the dissolvable liquid can be breached on command (e.g., by the controller) and allowed to contact the ring 1888 by a trigger/rupture disk combination (electrically pyro-actuated or otherwise), similar to the atmospheric chamber breach process. With this methodology, a known chemical makeup of dissolving liquid, and thus a reliable and repeatable dissolving rate of the ring 1888, can be realized. This configuration would allow for greater precision as to the dissolve time required to further actuate the fracturing sleeve 1830 (in other words, move the mandrel 1850 from the open position to the second closed position) after the stage of hydraulic fracturing using the fracturing sleeve 1830 is complete. The passive nature and potential structural capacity of the dissolvable ring 1888 has multiple advantages.

[0137] Other alternative embodiments of releasing of the ball seat 1871, support sleeve 1875, and/or shroud 1881 are possible and envisioned, such as employing electromechanical (motors), shear pins or other retention devices, pyro-actuated devices, and/or other similar downhole activation devices. These devices are envisioned to react the pressure of the fracturing fluid for the duration of the stage of the fracturing operation, and then release and cause expansion of the ball seat 1871 (and so release of the ball 1835) after the stage of the fracturing operation is complete.

[0138] As stated above, the dissolvable ring 1888 may be designed such that it will safely shear and/or dissolve at a certain time after the stage of the hydraulic fracturing operation is complete. In certain embodiments, the atmospheric chamber and the ball 1835 are continuously pressurized by the hydrostatic head and applied fracturing pressure from the fracturing fluid during the stage of the fracturing operation. As a result, a substantially constant shearing force is applied against the ring 1888. As illustrated in Figure 21, once the ring 1888 has dissolved and/or sheared, the mandrel 1850, the ball seat 1871, the support sleeve 1875, and the shroud 1881 are shifted (by the unbalanced shear force) distally into a portion 1889 of the outer wall 1858 that has a larger inner diameter, which allows the support sleeve 1875 and the ball seat 1871 to expand radially into their default open positions. Located at the end of portion 1889 is a transition 1894 to another part of the outer wall 1858 that has a smaller inner diameter that smaller than the outer diameter of the shroud 1881. In this way, the transition 1894 acts as a stop that prevents the shroud 1881 traveling beyond the transition 1894. In this way, the transition also necessarily limits the distal travel of the support sleeve 1875, the ball seat 1871, and the mandrel 1850. In the open positions, the ball seat 1871 has an inner diameter ID2 that is larger than the outer diameter of the ball 1875. As a result, any additional balls that enter the cavity 1855 of the fracturing sleeve 1830 can freely pass through the fracturing sleeve 1830 unhindered. Similarly, the inner diameter of the support sleeve 1875 in its open position is larger than the outer diameter of the ball 1835.

[0139] As discussed above, by utilizing a collapsible and expandable ball seat assembly 1870 design, non-sequential stages of a hydraulic fracturing operation can be implemented, with the ability to seal and unseal fracture zones in any order. Once all the fracture zones have been treated, one at a time as single entry points, all of the fracturing sleeves (e.g., fracturing sleeve 1830) in the casing string can be shifted back to the open position from the second closed position so that production operations can be implemented. For example, Figure 19 shows the fracturing sleeve 1830 with the mandrel 1850 returned to the open position from the second closed position after the fracturing operation has been completed.

[0140] Figures 24 through 26 show yet another fracturing sleeve 2430 according to certain example embodiments. Specifically, Figure 24 shows a cross-sectional side view of the fracturing sleeve 2430 with the mandrel 2450 in the first open position. Figure 25 shows a cross-sectional side view of the fracturing sleeve 2430 with the mandrel 2450 in the open position. Figure 26 shows a cross-sectional side view of the fracturing sleeve 2430 with the mandrel 2450 in the second closed position. The fracturing sleeve 2430 and its various components (e.g., the mandrel 2450, the ball seat 2471, the support sleeve 2475, the outer wall 2458) of Figures 24 through 26 are substantially the same as the fracturing sleeve 1830 and its corresponding components of Figures 18A through 23, except as described below. [0141] Referring to Figures 1A through 26, rather than utilizing a shroud (shroud 1881 of the fracturing sleeve 1830) and dissolvable ring (ring 1888 of the fracturing sleeve 1830), the fracturing sleeve 2430 of Figures 24 through 26 utilizes an annular piston 2483 (a type of retention device, such as retention device 1657). The annular piston 2483 functions similarly to the shroud 1881 and dissolvable ring 1888 of the fracturing sleeve 1830 of Figures 18A through 23. The piston 2483 acts as a temporary retaining mechanism that keeps the mandrel 2450 and the ball seat assembly 2470 (which in this case includes the ball seat 2471 and the support sleeve 2475) in place (with the mandrel 2450 in the open position) when the ball 2435 is engaged with the ball seat assembly 2470 in the closed position and reacts the pressure loading during a stage of the hydraulic fracturing operation in which the fracturing sleeve 2430 is the point of entry.

[0142] By utilizing a sealed chamber 2484 filled with incompressible fluid opposite the piston 2483, the piston 2483 is hydrostatically locked in its position. Once the stage of the fracturing operation is complete, an electronically controlled (e.g., by a controller) pressure barrier (pyro/thermally activated rupture disk or similar) is activated/ruptured, which in turn disengages the hydro-locked piston 2483, allowing fluid release from the chamber 2484 via a fluid release port 2482 for axial displacement of the piston 2483, the ball seat assembly 2470, and the mandrel 2450, resulting in the mandrel moving to the second closed position.

[0143] Once the ball seat 2471 and the support sleeve 2475 of the ball seat assembly 2470 have shifted into a larger bore formed by the outer wall 2458 of the fracturing sleeve 2430, allowing them to expand from their closed positions to their open positions, as shown in Figure 26, the inner diameter of the ball seat 2471 and the support sleeve 2475 become larger than the outer diameter of the ball 2435 (and any other subsequent balls), allowing them to pass freely through the cavity 2455 of the fracturing sleeve 2430.

[0144] Figure 27 shows a diagram of a system 2797 that includes a fracturing sleeve 2730 according to certain example embodiments. Referring to Figures 1 A through 27, the system 2797 can include one or more users 2737 (where each user can include one or more user devices 2738), and an optional network manager 2763, and the fracturing sleeve 2730. In addition to the controller 2740, the fracturing sleeve 2730 can include the one or more sensor devices 2760, one or more energy storage devices 2765, and one or more retention devices 2757. All of these components of the fracturing sleeve 2730 can be substantially similar to the corresponding components of the fracturing sleeve 630 discussed above. The controller 2740 can include one or more of a number of components. Such components, can include, but are not limited to, a control engine 2766, a communication module 2732, a timer 2733, a power module 2734, a storage repository 2764, a hardware processor 2721, a memory 2722, a transceiver 2724, an application interface 2726, and, optionally, a security module 2731.

[0145] The components shown in Figure 27 are not exhaustive, and in some embodiments, one or more of the components shown in Figure 27 may not be included in an example fracturing sleeve 2730. Any component of the example fracturing sleeve 2730 can be discrete or combined with one or more other components of the fracturing sleeve 2730. Also, one or more components of the fracturing sleeve 2730 can have different configurations. For example, one or more sensors 2761 and/or one or more retention devices 2757 can be disposed outside the cavity 2756 within the fracturing sleeve 2730.

[0146] A user 2737 may be any person that interacts with the example fracturing sleeve 2730 or is involved in a fracturing operation. Examples of a user 2737 may include, but are not limited to, a roughneck, a company representative, a drilling engineer, a completion engineer, a tool pusher, a service hand, a field engineer, an electrician, a mechanic, an operator, a consultant, a contractor, and a manufacturer’s representative. A user 2737 can use a user device 2738, which may include a display (e.g., a GUI). A user 2737 (including an associated user device 2738) can interact with (e.g., sends data to, receives data from) the controller 2740 of the fracturing sleeve 2730 via the application interface 2726 (described below). A user 2737 (including an associated user device 2738) can also interact with the optional network manager 2763.

[0147] Interaction between a user 2737 (including an associated user device 2738), the fracturing sleeve 2730, and the optional network manager 2763 can be conducted using communication links 2736. Each communication link 2736 can include wired (e.g., Class 1 electrical cables, Class 2 electrical cables, electrical connectors) and/or wireless (e.g., Wi-Fi, Zigbee, visible light communication, cellular networking, Bluetooth, WirelessHART, ISA100) technology. The communication link 2736 can transmit signals (e.g., communication signals, control signals, data) between the fracturing sleeve 2730, a user 2737 (including an associated user device 2738), and the optional network manager 2763.

[0148] The optional network manager 2763 is a device or component that controls and/or communicates with all or a portion of system 2797 that includes the controller 2740 of the fracturing sleeve 2730 and a user 2737 (including an associated user device 2738) in the system 2797. The network manager 2763 can be substantially similar to the controller 2740. Alternatively, the network manager 2763 can include one or more of a number of features and/or components in addition to, or altered from, the features and/or components of the controller 2740 described below. As described herein, communication with the network manager 2763 can include communicating with one or more other components of the system 2797. In such a case, the network manager 2763 can facilitate such communication.

[0149] A user 2737 (including an associated user device 2738) and the network manager 2763 can interact with the controller 2740 of the fracturing sleeve 2730 using the application interface 2726 according to one or more example embodiments. Specifically, the application interface 2726 of the controller 2740 receives data (e.g., information, communications, instructions, updates to firmware) from and sends data (e.g., information, communications, instructions) to a user 2737 (including an associated user device 2738) and the network manager 2763. A user 2737 (including an associated user device 2738) and the network manager 2763 can include an interface to receive data from and send data to the controller 2740 of the fracturing sleeve 2730 in certain example embodiments. Examples of such an interface can include, but are not limited to, a graphical user interface, a touchscreen, an application programming interface, a keyboard, a monitor, a mouse, a web service, a data protocol adapter, some other hardware and/or software, or any suitable combination thereof.

[0150] The controller 2740, each user 2737 (including an associated user device 2738), and the optional network manager 2763 can use their own system or share a system in certain example embodiments. Such a system can be, or contain a form of, an Internet-based or an intranet-based computer system that is capable of communicating with various software. A computer system includes any type of computing device and/or communication device, including but not limited to the controller 2740. Examples of such a system can include, but are not limited to, a desktop computer with Local Area Network (LAN), Wide Area Network (WAN), Internet or intranet access, a laptop computer with LAN, WAN, Internet or intranet access, a smart phone, a server, a server farm, an android device (or equivalent), a tablet, smartphones, and a personal digital assistant (PDA). Such a system can correspond to a computer system as described below with regard to Figure 28.

[0151] Further, as discussed above, such a system can have corresponding software (e.g., user software, controller software, network manager software). The software can execute on the same or a separate device (e.g., a server, mainframe, desktop personal computer (PC), laptop, PDA, television, cable box, satellite box, kiosk, telephone, mobile phone, or other computing devices) and can be coupled by the communication network (e.g., Internet, Intranet, Extranet, LAN, WAN, or other network communication methods) and/or communication channels, with wire and/or wireless segments according to some example embodiments. The software of one system can be a part of, or operate separately but in conjunction with, the software of another system within the system 2797.

[0152] In certain example embodiments, instructions and data (e.g., threshold values, testing of sensor devices 2760) can be transferred from a user device 2738 to the controller 2740 of the fracturing sleeve 2730 in the field when the fracturing sleeve 2730 is at the surface (e.g., surface 108) before being inserted into a subterranean wellbore (e.g., subterranean wellbore 120) as part of a casing string (e.g., casing string 125).

[0153] The fracturing sleeve 2730 can have multiple walls (e.g., wall 2754, wall 2758, which are similar to wall 654 and wall 658, respectively, discussed above) that form a cavity 2756. In some cases, the multiple walls of the fracturing sleeve 2730 form a housing that can be designed to comply with any applicable standards so that the fracturing sleeve 2730 can be located in a particular environment (e.g., in a subterranean wellbore within a subterranean formation 2710). The controller 2740 (which in this case includes the control engine 2766, the communication module 2732, the timer 2733, the power module 2734, the storage repository 2764, the hardware processor 2721, the memory 2722, the transceiver 2724, the application interface 2726, and the optional security module 2731) and the one or more sensor devices 2760 can be disposed in the cavity 2756 formed by the walls of the fracturing sleeve 2730. In alternative embodiments, any one or more of these or other components (e.g., a sensor device 2760) of the fracturing sleeve 2730 can be disposed outside of the cavity 2736.

[0154] The storage repository 2764 can be a persistent storage device (or set of devices) that stores software and data used to assist the controller 2740 in communicating with a user 2737 (including an associated user device 2738) and the network manager 2763 within the system 2797. The software and data stored in the storage repository 2764 can also be used to help the controller 2740 carry out its various functions, including determining, based on measurements made by one or more of the sensor devices 2760, whether an action (e.g., deploying a retention device 2757, retracting a retention device 2757, operate the ball seat assembly (e.g., ball seat assembly 670)) should be taken. In one or more example embodiments, the storage repository 2764 stores one or more protocols, one or more algorithms, and stored data.

[0155] The protocols can include any processes or logic steps that are implemented by the control engine 2766 based on certain conditions at a point in time. The protocols can include communication protocols that are used to send and/or receive data between the controller 2740, a user 2737 (including an associated user device 2738), and the network manager 2763. One or more of the protocols can be a time-synchronized protocol for communications. Examples of such time-synchronized protocols can include, but are not limited to, a highway addressable remote transducer (HART) protocol, a wirelessHART protocol, and an International Society of Automation (ISA) 100 protocol. In this way, one or more of the protocols can provide a layer of security to the data transferred within the system 2797.

[0156] An example of a protocol is operating, using measurements made by a sensor device 2760 (e.g., a magnetometer sensor) that exceed a parameter threshold value (also called a measurement threshold value herein) and counts equaling or exceeding a count threshold value, a ball seat assembly (e.g., ball seat assembly 670) of the fracturing sleeve 2730. Another example of a protocol is releasing a retention device (e.g., retention device 657) once an amount of time (a time threshold value) has passed since the mandrel of the fracturing sleeve 2730 is moved to the open position, as when the next stage in a multi-stage fracturing process is about to begin. Yet another example of a protocol is to enable a retention device (e.g., retention device 657) once an amount of time (a time threshold value) has passed since the mandrel of the fracturing sleeve 2730 is moved to the second closed position, as when the multi-stage fracturing operation is complete and the extraction/recovery process of the subterranean resource is about to begin.

[0157] Still another example of a protocol is to put the controller 2740 and sensor devices 2760 in sleep mode until a certain amount of time (e.g., a time threshold value) has elapsed since the controller 2740 has received instructions from a user device 2738. Yet another example of a protocol is to put the controller 2740 and sensor devices 2760 in sleep mode until a certain pressure pulse pattern initiated from the surface (e.g., surface 108) is detected by a pressure transducer (a type of sensor device 2760) in the fracturing sleeve 2730, at which time the controller 2740 and the sensor devices 2760 are awakened from power conservation hibernation mode.

[0158] The algorithms can be any models, formulas, and/or other similar operational implementations that the control engine 2766 of the controller 2740 uses. An example of an algorithm is using measurements made by a sensor module 2760 to determine (e.g., calculate) whether each measurement exceeds a parameter threshold value. For instance, an algorithm can include a formula or model that compares measurements (or results of calculations made using those measurements) made by one or more of the sensor devices 2760 with threshold values (part of the stored data). One or more algorithms can at times be used in conjunction with one or more protocols.

[0159] Stored data can be any historical, present, and/or forecast data. Stored data can be associated with a sensor device 2760, the controller 2740, the network manager 2763, and a user 2737 (including an associated user device 2738). Stored data can be associated with the fracturing sleeve 2730 or portion thereof. Such stored data can include, but is not limited to, settings, threshold values, default values, user preferences, results of an algorithm, and measurements taken by the sensor device 2760. Examples of a storage repository 2764 can include, but are not limited to, a database (or a number of databases), a file system, a hard drive, flash memory, cloud-based storage, some other form of solid state data storage, or any suitable combination thereof.

[0160] The storage repository 2764 can be operatively connected to the control engine 2766. In one or more example embodiments, the control engine 2766 includes functionality to communicate with a user 2737 (including an associated user device 2738) and the network manager 2763. More specifically, the control engine 2766 sends information to and/or receives information from the storage repository 2764 in order to communicate with a user 2737 (including an associated user device 2738) and the network manager 2763. As discussed below, the storage repository 2764 can also be operatively connected to the communication module 2732 in certain example embodiments.

[0161] In certain example embodiments, the control engine 2766 of the controller 2740 controls the operation of one or more components (e.g., the communication module 2732, the timer 2733, the transceiver 2724) of the controller 2740. For example, the control engine 2766 can operate one or more sensor devices 2760 to dictate when measurements are taken by the sensor devices 2760 and when those measurements are communicated by the sensor devices 2760 to the control engine 2766. As another example, the control engine 2766 can acquire the current time or determine an amount of time using the timer 2733.

[0162] In certain example embodiments, the control engine 2766 can identify whether threshold values have been exceeded (e.g., of a measurement made by a sensor device 2760, the number of times that a measurement made by a sensor device 2760 has been exceeded). For example, the control engine 2766 can determine whether a measurement or series of measurements made by a sensor device 2760 indicates that the ball seat assembly of the fracturing sleeve 2730 should be operated to the closed position so that a stage of a fracturing operation can be performed using the fracturing sleeve 2730. Such threshold value can be, for example, an amount of time, a count, the strength of a magnetic field measured by a sensor device 2760, and/or an amount of pressure measured by a sensor device 2760. The control engine 2766 can follow a protocol to control (e.g., when measurements should be taken, how often measurements should be taken, which measurements should be taken) each sensor device 2760.

[0163] The control engine 2766 can provide control, communication, and/or other similar signals to a user 2737 (including an associated user device 2738) and the network manager 2763. Similarly, the control engine 2766 can receive control, communication, and/or other similar signals from a user 2737 (including an associated user device 2738) and the network manager 2763. The control engine 2766 can control each sensor device 2760, each retention device 2757, and the energy storage device 2765 automatically (for example, based on one or more protocols and/or algorithms stored in the storage repository 2764). The control engine 2766 may include a printed circuit board, upon which the hardware processor 2721 and/or one or more discrete components of the controller 2740 are positioned.

[0164] In certain example embodiments, the control engine 2766 can include an interface that enables the control engine 2766 to communicate with one or more components (e.g., a sensor device 2760) of the fracturing sleeve 2730. The control engine 2766 (or other components of the controller 2740) can also include one or more hardware components and/or software elements to perform its functions. Such components can include, but are not limited to, a universal asynchronous receiver/transmitter (UART), a serial peripheral interface (SPI), a direct-attached capacity (DAC) storage device, an analog-to-digital converter, an inter-integrated circuit (I ² C), and a pulse width modulator (PWM).

[0165] The communication module 2732 of the controller 2740 determines and implements the communication protocol (e.g., from the protocols of the storage repository 2764) that is used when the control engine 2766 communicates with (e.g., sends signals to, receives signals from) a user 2737 (including an associated user device 2738), the network manager 2763, and/or another component of the fracturing sleeve 2730 (e.g., the energy storage device 2765, one or more of the sensor devices 2760). In some cases, the communication module 2732 accesses the stored data to determine which protocol is used to communicate with the sensor device 2760 associated with the stored data. In addition, the communication module 2732 can interpret the protocol of a communication received by the controller 2740 so that the control engine 2766 can interpret the communication.

[0166] The communication module 2732 can send and receive data between the network manager 2763, the users 2737 (including associated user devices 2738), other components of the fracturing sleeve 2730, and the controller 2740. The communication module 2732 can send and/or receive data in a given format that follows a particular protocol for communication. The control engine 2766 can interpret the data packet received from the communication module 2732 using information about a protocol stored in the storage repository 2764. The control engine 2766 can also facilitate the data transfer between the network manager 2763, the sensor devices 2738, and/or a user 2737 (including an associated user device 2738) by converting the data into a format understood by the communication module 2732.

[0167] The communication module 2732 can send data (e.g., protocols, algorithms, stored data, measurements made by a sensor device 2760, threshold values (e.g., count threshold values, parameter threshold values, time threshold values), user preferences) directly to and/or retrieve data directly from the storage repository 2764. Alternatively, the control engine 2766 can facilitate the transfer of data between the communication module 2732 and the storage repository 2764. The communication module 2732 can also provide encryption to data that is sent by the controller 2740 and decryption to data that is received by the controller 2740. The communication module 2732 can also provide one or more of a number of other services with respect to data sent from and received by the controller 2740. Such services can include, but are not limited to, data packet routing information and procedures to follow in the event of data interruption.

[0168] The timer 2733 of the controller 2740 can track clock time, intervals of time, an amount of time, and/or any other measure of time. The timer 2733 can also count the number of occurrences of an event, whether with or without respect to time. Alternatively, the control engine 2766 can perform the counting function. The timer 2733 is able to track multiple time measurements concurrently. The timer 2733 can track time periods based on an instruction received from the control engine 2766, based on an instruction received from a user 2737 (including an associated user device 2738), based on an instruction programmed in the software for the controller 2740, based on some other condition or from some other component, or from any combination thereof. The timer 2733 can be considered a type of sensor device 2760.

[0169] The timer 2733 can be configured to track time when there is no power delivered to the controller 2740 (e.g., the power module 2734 malfunctions) using, for example, a super capacitor or a battery backup. In such a case, when there is a resumption of power delivery to the controller 2740, the timer 2733 can communicate any aspect of time to the controller 2740. In such a case, the timer 2733 can include one or more of a number of components (e.g., a super capacitor, an integrated circuit), separate from the energy storage device 2765, to perform these functions. [0170] The power module 2734 of the controller 2740 provides power to one or more other components (e.g., timer 2733, control engine 2766) of the controller 2740. In addition, in certain example embodiments, the power module 2734 can provide power to one or more sensor modules 2760 of the fracturing sleeve 2730. The power module 2734 can include one or more of a number of single or multiple discrete components (e.g., transistor, diode, resistor), and/or a microprocessor. The power module 2734 may include a printed circuit board, upon which the microprocessor and/or one or more discrete components are positioned. In some cases, the power module 2734 can include one or more components that allow the power module 2734 to measure one or more elements of power (e.g., voltage, current) that is delivered to and/or sent from the power module 2734.

[0171] The power module 2734 can include one or more components (e.g., a transformer, a diode bridge, an inverter, a converter) that receives power from the energy storage device 2765. The power module 2734 can use this power to generate power of a type (e.g., alternating current, direct current) and level (e.g., 12 V, 24 V) that can be used by the other components of the controller 2740. As discussed above, in certain example embodiments, the power module 2734 of the controller 2740 can also provide power and/or control signals, directly or indirectly, to one or more of the sensor devices 2760. In such a case, the control engine 2766 can direct the power generated by the power module 2734 to the sensor devices 2760 of the fracturing sleeve 2730. In this way, power can be conserved by sending power to the sensor devices 2760 of the fracturing sleeve 2730 when those devices need power, as determined by the control engine 2766.

[0172] The hardware processor 2721 of the controller 2740 executes software, algorithms, and firmware according to one or more example embodiments. Specifically, the hardware processor 2721 can execute software on the control engine 2766, any other portion of the controller 2740, and the sensor devices 2760, as well as software used by a user device 2738. The hardware processor 2721 can be or include an integrated circuit (IC), a central processing unit, a multi-core processing chip, SoC, a multi -chip module including multiple multi-core processing chips, or other hardware processor in one or more example embodiments. The hardware processor 2721 can be known by other names, including but not limited to a computer processor, a microprocessor, and a multi -core processor.

[0173] In one or more example embodiments, the hardware processor 2721 executes software instructions stored in memory 2722. The memory 2722 includes one or more cache memories, main memory, and/or any other suitable type of memory. The memory 2722 can include volatile and/or non-volatile memory. The memory 2722 is discretely located within the controller 2740 relative to the hardware processor 2721 according to some example embodiments. In certain configurations, the memory 2722 can be integrated with the hardware processor 2721.

[0174] In certain example embodiments, the controller 2740 does not include a hardware processor 2721. In such a case, the controller 2740 can include, as an example, one or more field programmable gate arrays (FPGA), one or more insulated-gate bipolar transistors (IGBTs), and/or one or more ICs. Using FPGAs, IGBTs, ICs, and/or other similar devices known in the art allows the controller 2740 (or portions thereof) to be programmable and function according to certain logic rules and thresholds without the use of a hardware processor. Alternatively, FPGAs, IGBTs, ICs, and/or similar devices can be used in conjunction with one or more hardware processors 2721. [0175] The transceiver 2724 of the controller 2740 can send and/or receive control and/or communication signals. Specifically, the transceiver 2724 can be used to transfer data between the controller 2740, a user device 2738, and the network manager 2763. The transceiver 2724 can use wired and/or wireless technology. The transceiver 2724 can be configured in such a way that the control and/or communication signals sent and/or received by the transceiver 2724 can be received and/or sent by another transceiver that is part of a user device 2738 and/or the network manager 2763.

[0176] When the transceiver 2724 uses wireless technology, any type of wireless technology and/or protocol can be used by the transceiver 2724 in sending and receiving signals. Such wireless technologies and/or protocols can include, but are not limited to, Wi-Fi, Zigbee, cellular networking, Bluetooth, and Bluetooth Low Energy. The transceiver 2724 can use one or more of any number of suitable protocols (e.g., ISA100, HART) when sending and/or receiving signals. Such communication protocols can be stored among the protocols of the storage repository 2764. Further, any transceiver information for a user device 2738 and the network manager 2763 can be part of the protocols (or other areas) of the storage repository 2764.

[0177] Optionally, in one or more example embodiments, the security module 2731 secures interactions between the controller 2740, the user devices 2738, and the network manager 2763. More specifically, the security module 2731 authenticates communication from software based on security keys verifying the identity of the source of the communication. For example, user software may be associated with a security key enabling the software of a user device 2738 to interact with the controller 2740. Further, the security module 2731 can restrict receipt of information, requests for information, and/or access to information in some example embodiments. [0178] The sensor devices 2760 can be substantially the same as the sensor devices discussed above with respect to Figures 6 through 13. Each sensor device 2760 includes one or more sensors 2761 that measure one or more parameters (e.g., position, azimuth, vibration, magnetic fields, pressure, flow rate). The fracturing sleeve 2730 can include one or more sensor devices 2760. A sensor device 2760 can have one or multiple sensors 2761. In some cases, a number of sensors 2761 and/or sensor devices 2760, each measuring a different parameter, can be used in combination to determine and confirm whether the controller 2740 of the fracturing sleeve 2730 should take a particular action (e.g., operate a ball seat assembly).

[0179] The retention devices 2757 are substantially the same as the retention devices described above. Each of the one or more energy storage devices 2765 can include one or more batteries, supercapacitors, and/or other components that can store and subsequently release power. The power provided by the energy storage device 2765 can be of a type (e.g., direct current, alternating current) and of a level (e.g., 12V, 24V) that are used by the recipient component (e.g., the power module 2734) of the fracturing sleeve 2730. There can be any number of energy storage devices 2765. When an energy storage device 2765 includes battery units, the battery units can use one or more of any number of battery technologies. Examples of such technologies can include, but are not limited to, nickel-cadmium, nickel-metalhydride, lithium-ion, and alkaline. In certain example embodiments, each battery unit can be rechargeable.

[0180] Figure 28 illustrates one embodiment of a computing device 2818 that implements one or more of the various techniques described herein, and which is representative, in whole or in part, of the elements described herein pursuant to certain example embodiments. For example, computing device 2818 can be implemented in the fracturing sleeve 2730 of Figure 27 in the form of the hardware processor 2721, the memory 2722, and the storage repository 2764, among other components. Computing device 2818 is one example of a computing device and is not intended to suggest any limitation as to scope of use or functionality of the computing device and/or its possible architectures. Neither should computing device 2818 be interpreted as having any dependency or requirement relating to any one or combination of components illustrated in the example computing device 2818.

[0181] Computing device 2818 includes one or more processors or processing units 2814, one or more memory/storage components 2813, one or more input/output (I/O) devices 2816, and a bus 2817 that allows the various components and devices to communicate with one another. Bus 2817 represents one or more of any of several types of bus structures, including a memory bus or a memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. Bus 2817 includes wired and/or wireless buses.

[0182] Memory/storage component 2813 represents one or more computer storage media. Memory/storage component 2813 includes volatile media (such as random access memory (RAM)) and/or nonvolatile media (such as read only memory (ROM), flash memory, optical disks, magnetic disks, and so forth). Memory/storage component 2813 includes fixed media ( e.g ., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a Flash memory drive, a removable hard drive, an optical disk, and so forth).

[0183] One or more I/O devices 2816 allow a customer, utility, or other user to enter commands and information to computing device 2818, and also allow information to be presented to the customer, utility, or other user and/or other components or devices. Examples of input devices include, but are not limited to, a keyboard, a cursor control device (e.g, a mouse), a microphone, a touchscreen, and a scanner. Examples of output devices include, but are not limited to, a display device (e.g, a monitor or projector), speakers, outputs to a lighting network (e.g, DMX card), a printer, and a network card.

[0184] Various techniques are described herein in the general context of software or program modules. Generally, software includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques are stored on or transmitted across some form of computer readable media. Computer readable media is any available non-transitory medium or non-transitory media that is accessible by a computing device. By way of example, and not limitation, computer readable media includes “computer storage media”.

[0185] “Computer storage media” and “computer readable medium” include volatile and non volatile, removable and non-removable media implemented in any method or technology for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, computer recordable media such as RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which is used to store the desired information and which is accessible by a computer.

[0186] The computer device 2818 is connected to a network (not shown) ( e.g . , a LAN, a WAN such as the Internet, cloud, or any other similar type of network) via a network interface connection (not shown) according to some example embodiments. Those skilled in the art will appreciate that many different types of computer systems exist (e.g., desktop computer, a laptop computer, a personal media device, a mobile device, such as a cell phone or personal digital assistant, or any other computing system capable of executing computer readable instructions), and the aforementioned input and output means take other forms, now known or later developed, in other example embodiments. Generally speaking, the computer system 2818 includes at least the minimal processing, input, and/or output means necessary to practice one or more embodiments. [0187] Further, those skilled in the art will appreciate that one or more elements of the aforementioned computer device 2818 is located at a remote location and connected to the other elements over a network in certain example embodiments. Further, one or more embodiments is implemented on a distributed system having one or more nodes, where each portion of the implementation (e.g., controller 2740) is located on a different node within the distributed system. In one or more embodiments, the node corresponds to a computer system. Alternatively, the node corresponds to a processor with associated physical memory in some example embodiments. The node alternatively corresponds to a processor with shared memory and/or resources in some example embodiments.

[0188] Example fracturing sleeves enable more efficient and effective horizontal multi-stage fracturing by allowing selective isolation within a casing sleeve in a wellbore for a single entry point, and non-sequential staging of a fracturing operation, which can ensure placement of the designed fracture treatment into each and every interval, and can also provide more options for leveraging stress shadowing to (a) maximize fracture complexity, (b) promote self-propping shear fractures, and (c) provide better SRV containment within targeted drainage volume for avoiding geohazards and fracture hits and for optimizing 4D well spacing to maximize recovery efficiency and project economics.

[0189] Example embodiments can also dramatically reduce or eliminate proppant via promotion of self-proppant shear fractures (e.g., 4D completion concept to “torque the rock”) and higher hydraulic impact force on the sandface by using significantly higher fracturing rates per ft of lateral. For example, the fracturing injection rate is only 0.45 barrels per minute (BPM) per foot (ft) with P n’ P at 100 BPM into 13 perforation clusters and 22 G stage spacing, while the rate can be 1.06 BPM per ft with single entry point staging at 50 BPM and 47’ stage spacing using example fracturing sleeves.

[0190] Further, example embodiments can provide for simplified fracturing operations and less non-productive time (NPT) by eliminating the need for wireline, dedicated pump-down equipment, handling perforating explosives, overhead crane/lubricator work, zipper manifolds, and post-fracturing mill-out of fracturing plugs and/or frac balls/seats currently used in fracturing operations.

[0191] Each programable example fracturing sleeve delivered to a multi-well pad site prior to casing running operations may be identical with respect to dimensions and functionality. For example, an example fracturing sleeve can have an outer diameter of 4-1/2”. Example fracturing sleeves can be designed to facilitate running and cementing inside long lateral hole sections (e.g., 6-3/4” borehole, 6-1/8” borehole, 2+ mile laterals). Tapered production casing strings (e.g., 5- 1/2” x 4-1/2”) or liners (e.g., 4-1/2”) from casing (e.g., 7-5/8”) can be considered to accommodate an artificial lift system.

[0192] Larger example fracturing sleeves can be designed to fit in wells constructed with larger wellbore profiles (e.g., 5” or 5-1/2” casing in the substantially horizontal section or lateral). For even larger hole sizes (e.g., 6-3/4”), each example fracturing sleeve can be full drift to the inside diameter (ID) of the casing to facilitate the use of conventional cementing equipment and practices, improve wellbore producibility, and enable a plug n’ perf contingency in the event the example fracturing sleeve cannot be used (e.g., a failure of a controller in the fracturing sleeve). [0193] Each example fracturing sleeve can be manufactured with an upper profile to facilitate pick-up and running operations on the rig floor. Alternatively, the example fracturing sleeves can be delivered to location with pup joints already made up to the fracturing sleeves. As discussed above, a wet shoe technique resulting in an open shoe track at the end of the production casing/liner or a pressure-actuated toe sleeve can be used to establish and maintain a flow path to the end of the well during the entire fracturing operation using example fracturing sleeves. In some cases, one or more additional example fracturing sleeves near the toe may be stimulated first and are left open (i.e., their mandrels are not moved from the open position to the second closed position) to ensure adequate injectivity into the toe of the well during the entire multi-stage fracturing operation (e.g., using conventional ball-actuated fracturing sleeves with degradable balls).

[0194] Each example fracturing sleeve is designed to be opened and then closed for a particular stage of a multi-stage fracturing operation using remote triggering protocols, a wireless magnetic frac ball counting system (using on-board a sensor module in the form of a MEMS (micro electromechanical system) magnetometer sensor, a controller, and an energy storage device), and downhole hydraulic or mechanical (e.g., retention) devices that enable release of potential energy (e.g., firing one or more atmospheric chambers) based on the logic programmed in the controller. [0195] Specifically, the magnetometer sensor detects the magnetized balls as they pass by at high velocities. By communicating these measurements to the controller, the controller can effectively count how many stages have been executed during the multi-stage fracturing operation. The controller independently increments the count by one in each example fracturing sleeve as the ball released and/or pumped at the end of each stage passes by each fracturing sleeve. The example fracturing sleeve provides the option of manually re-opening the fracturing sleeve (moving the mandrel from the second closed position back to the open position) using a shifting tool and workstring or automatically reopening the sleeves after the multi-stage fracturing operations have been completed based on a pre-programmed duration from when each fracturing sleeve completed its open/close cycle.

[0196] Multiple example methods of using example fracturing sleeves in a multi-stage fracturing operation can be realized. For example, for substantially horizontal sections of wells to be completed using a multitude of example fracturing sleeves spaced out along the lateral, a method to enable the initiation of a flowpath to the end of the wellbore to start the completion is required (e.g., using a conventional pressure-actuated toe sleeve or a “wet shoe” technique). After cementing the production casing or liner string containing an example fracturing sleeve for each planned fracture stage and optionally conventional pressure-actuated toe sleeve(s) toward the end of the casing string in the lateral hole section, the cement is allowed to set-up while preparations are made to complete the wells, which share a common drill site pad location using a fracture stimulation treatment.

[0197] After pressure testing the casing, the completion process commences by establishing a high-rate flowpath to the end of the lateral hole section using the pressure-actuated toe sleeve(s) or wet shoe technique. This high rate flowpath located proximate to the toe of the well will remain open throughout the multi-stage fracturing process. A firac ball spacer device may be pumped down to the lowermost toe sleeve or shoe track to ensure high rate injectivity is maintained around the balls that accumulate near the toe of the well and to facilitate the dissolution process. In addition, or in the alternative, the balls used can be degradable when they interact with the fluid (e.g., fracturing fluid) used during the fracturing operation.

[0198] Example fracturing sleeves can be used to complete all other stages in the substantially horizontal section of each well. If a threaded fracturing sleeve is installed between each casing pipe of API Range 3 casing, the resulting stage spacing can be some known distance (e.g., 47 ft). A primary trigger in each example fracturing sleeve is used for deploying a collapsible C-ring style or other suitable deployable ball seat by firing atmospheric chamber, releasing the kinetic energy of a wave spring, or using other means for releasing locally stored potential energy at the right time (at the correct stage) in the multi-stage fracturing operation. Each fracturing sleeve operates independently of the other fracturing sleeves in the casing string. Also, each fracturing sleeve is pre-programmed to deploy its ball seat (operate the ball seat assembly to the closed position) based on a different stage count which is tracked using proven wireless magnetic ball counting technology.

[0199] The first example fracturing sleeve to be used in a stage of a fracturing operation can be located anywhere within the lateral hole section. The fracturing sleeve will have been pre programmed to trigger its ball seat deployment (operate the ball seat assembly to the closed position) by detecting, using a sensor device, the passing of the first magnetized frac ball (stage count = 1) that is pumped down from the surface after confirming the open sleeves or shoe track at the toe of the lateral are capable of accepting the high fracture rates used during each stage of the fracturing operation. Pumping down the first magnetized ball to the ball spacer located near the toe of the well evidences the completion of the first stage of the fracturing operation at the toe of the well. The ball passing by each example fracturing sleeve also triggers the actual stage count being registered by the controller of each fracturing sleeve to be incremented by one.

[0200] The first magnetized ball pumped down to the toe of the well in this example is referred to as “Ball #1”. The example fracturing sleeve to be used in the first stage of the fracturing operation is referred to as “Sleeve #1”. Once the ball seat assembly of Sleeve #1 has been operated to the closed position based on the passing of Ball #1 through Sleeve #1, another ball (Ball #2) is pumped down and engages the ball seat assembly, in the closed position, of Sleeve #1. Force applied against Ball #2 and the ball seat assembly of Sleeve #1 by the pumped fluid causes the sliding mandrel of Sleeve #1 to move from the first closed position to the open position, which aligns the frac ports in the mandrel and outer wall of Sleeve #1 with each other. Ball #2, which is sealed against the deployed ball seat of the ball seat assembly of Sleeve #1, also provides hydraulic isolation from the open sleeve(s) near the toe or open shoe track if the “wet shoe” technique was used. As Ball #2 passes all the uphole undeployed fracturing sleeves, the stage count registered by each controller of those fracturing sleeves increments by one.

[0201] After completing the stage of the fracturing operation through Sleeve #1 with full displacement of the proppant slurry using clean fracturing fluid, the pumps are shut down. A secondary trigger is used for closing Sleeve #1 and is based on a pre-programmed duration from when the sleeve is first shifted to the open position (e.g., 45 minutes based on planned stage pump time). Once the pre-programmed duration with the mandrel of Sleeve #1 in the open position has been achieved and the pumps are shut down, a spring-loaded stop pin will release allowing the mandrel to rest on a shear pin (or other retention device). A relatively minor amount of applied hydraulic force against the ball and ball seat assembly causes the pin to shear, thus allowing the mandrel to continue moving down from the open position to the second closed position. The second closed position can be secured by another shear pin (or other form of retention device) that is designed to fail with sufficient upward pull from a coiled tubing or workstring-conveyed shifting tool or optionally by firing another atmospheric chamber via a time delay (e.g., after 2 weeks from when the sleeve was first opened) to re-open the sleeve (i.e., move the mandrel back to the open position) for production by moving the mandrel from the second closed position back to the open position. Yet another retention device can be used to keep the mandrel in the open position after the fracturing operation has been completed. [0202] As the mandrel of Sleeve #1 latches in the second closed position, the design of the Co ring or other style ball seat assembly will allow it to expand (re-open) to its original full-bore configuration, thus releasing Ball #2 while pumping into the open sleeves or open shoe track at the toe to clear the wellbore and move Ball #2 to the toe of the well. As Ball #2 passes the not- yet-actuated fracturing sleeves located below the most recent fracture injection point (stage), those fracturing sleeves will register an additional stage count. Sleeve #2, which has been pre programmed to actuate on stage count = 2 (as tracked by its onboard controller) deploys its ball seat (operates its ball seat assembly to the closed position) immediately after its controller registers the passing of Ball #2.

[0203] Frac ball spacer devices can be pumped down periodically during the multi-stage fracturing operation to ensure that high rate injectivity is maintained around any partially dissolved balls that accumulate near the toe of the well and to facilitate the dissolution of those balls. For example, acid may be used to quickly dissolve frac balls that have accumulated at the toe of the well to prevent plugging the flow path through the toe of the lateral. At this point, the mandrels of all example fracturing sleeves are in the closed position, and the flow path is out the toe of the well.

[0204] Ball #3 is then pumped down and engages the most recently collapsed ball seat (the ball seat assembly that has most recently been operated into the closed position), which in this example is now Sleeve #2. Sleeve #2 can be located either uphole or downhole from Sleeve #1. As Ball #3 passes all the uphole undeployed fracturing sleeves, the sensor device and controller of each of those fracturing sleeves register the increment to stage count = 3. If an uphole fracturing sleeve has been programmed to actuate on stage count = 3 (Sleeve #3), then its ball seat assembly will operate to the closed position (the ball seat will collapse) immediately after Ball #3 passes by it. If Sleeve #3 is located further downhole from Sleeve #2, then the ball seat assembly will not operate to the closed position until the current stage of the fracturing operation is completed through Sleeve #2, Sleeve #2 releases the Ball #3, and Ball #3 passes by Sleeve #3 on its way to the toe of the well.

[0205] The process to first open a fracturing sleeve (i.e., move the mandrel of the fracturing sleeve from the first closed position to the open position), then pump the stage of the fracturing operation, then close the fracturing sleeve (i.e., move the mandrel of the fracturing sleeve from the open position to the second closed position) used in that stage is repeated until all stages of the fracturing operation have been pumped (completed). To enable non-sequential staging, each example fracturing sleeve is programmed for ball seat actuation after a different number of actual stages of the fracturing operation have been pumped. After all stages of the fracture operations on the well have been completed, all example fracturing sleeves are in the closed position, but the toe sleeve(s) or open shoe track (if the wet shoe technique was used) remain open.

[0206] When relatively high proppant intensity slurries are used, a coiled tubing (CT) or jointed pipe intervention may be required to clean excess proppant out of the wellbore during flowback. In these cases, the example fracturing sleeve design contemplates re-opening the sleeves after fracturing operations conclude using a CT/workstring-conveyed sleeve shifting tool to engage the profile of the mandrel of each fracturing sleeve with straight pickup or using hydraulic means. Re-opening would be done in one continuous operation starting at the toe while circulating proppant out of the well. The re-opening process can begin at the toe-most located example fracturing sleeve while circulating excess proppant out of the casing. Then, each additional example fracturing sleeve can be re-opened sequentially while continuing fluid circulation and pulling out of the hole with the coiled tubing or jointed workstring until the last example fracturing sleeve nearest the heel of the well has been opened.

[0207] If proppant flowback is not a concern, the example fracturing sleeves can optionally include another atmospheric chamber (or alternative mechanical means for releasing locally stored potential energy) for automatically re-opening each example fracturing sleeve without a CT/workstring intervention based on a programmed duration after initial sleeve actuation (e.g., 2 weeks). To address proppant flowback issues after production operations commence, example fracturing sleeves can be configured with a proppant flowback control screen/filter on the mandrel and/or outer wall of the example fracturing sleeve that covers a set of “production ports”, which are different than the “injection ports” used during a stage of the fracturing operation. Degradable material may be used to protect the screen/filter material from plugging with cement and other debris prior to re-opening the example fracturing sleeves.

[0208] The example fracturing sleeves can include an energy storage device to provide power to its various components (e.g., controller, sensor device) during the fracturing operations and, in some cases, during some of the production operations. Energy management procedures and protocols can be followed in some cases to conserve power in the energy storage devices. For example, the controller in each example fracturing sleeve can remain in hibernation or sleep mode until fracturing operations are ready to begin. A pressure pulse of a certain magnitude or other means may be used to wake up the controllers in the example fracturing sleeves when multi-stage fracturing operations are ready to start. As another example, the magnetic ball counting circuitry and MEMS magnetometer (the sensor device and controller) can be optimized for minimal power consumption.

[0209] The specific conditions that are designed to trigger the various fracturing sleeve actuations (ball seat assembly deployment for getting the mandrel to the open position, sliding the mandrel to the second closed position, and optionally the final automatic re-opening actuation) can be pre-programmed (e.g., wirelessly) into the controller of each example fracturing sleeve on the rig floor during the casing running operation. This process can mitigate the risk that the example fracturing sleeves are run in the wrong order, such as if they are programmed offsite (e.g., in the shop) prior to delivery to the field location where they are run in the well.

[0210] In some cases, the energy storage devices in one or more of the example fracturing sleeves can be rechargeable. In such a case, the energy storage devices can be recharged and/or re-programmed when the example fracturing sleeves are positioned downhole by using e-coiled tubing and a bottomhole assembly (BHA) with wireless short-hop telemetry/inductive coupling. The energy storage device of an example fracturing sleeve can include a lithium battery pack that can be installed immediately before shipping the example fracturing sleeve to the location or that can be installed on location. The energy storage device is used to power the controller and sensor devices and to trigger wave spring, atmospheric chamber actuation mechanisms, and/or other means for releasing locally stored potential energy. The energy storage device can be designed to last 9+ months in sleep mode to accommodate multi-well batch operations.

[0211] The internal profile of each example fracturing sleeve can allow for the mandrel to subsequently be slidably moved to a different position using a coiled tubing or jointed workstring intervention with a suitable shifting tool in the BHA. This provides a significant advantage over P n’ P completions related to future enhanced oil recovery (EOR) huff n’ puff injections, refracturing work, and/or water conformance. An acoustic listening system can be used to confirm whether an example fracturing sleeve has been actuated during multi-well pad fracturing operations. A chip can be incorporated into each example fracturing sleeve to generate a surface detectable and unique sound “chirp” in order to provide evidence of ball seat deployment and/or sleeve open/close actuations. The initial opening of each example fracturing sleeve should be readily detectable due to the ball engaging the ball seat assembly and sliding the mandrel to the open position. The example fracturing sleeve re-opening actuation should also be readily detectable if an atmospheric chamber is used to slide the mandrel back to the open position and if the example fracturing sleeves are programmed to open at slightly different times relative to each other.

[0212] The example fracturing sleeve system leverages proven ball launcher technology and degradable frac balls (e.g., made of magnesium-alloy or polylactic acid) that can be designed for the low-temperature applications (e.g., in the Permian Basin). The deployable ball seat assemblies in all example fracturing sleeves can be designed to accept the same size frac ball (e.g., ~ 3” diameter) for all example fracturing sleeves.

[0213] Example fracturing sleeves and performing multi-stage fracturing operations using example fracturing sleeves provides a number of benefits. For example, example systems allow for single entry point, non-sequential staging and facilitates simul-fracs from multiple wells on a multi-well pad, potentially delivering step change improvements in fracture complexity and fracture geometry consistency. Stages can be fractured in any desired order. Also, example embodiments require less surface equipment and simply operations. For instance, using example embodiments in fracturing operations requires no wireline, no dedicated pump-down equipment, no overhead crane work, no lubricators, no zipper manifolds, no synchronized wireline/pump- down operation, no personnel in the high pressure “red zone”, and no coiled tubing/snubbing unit mill-out for plugs, frac balls, and/or ball seats. In some cases, if proppant is used in the fracturing treatments, a cleanout run using coiled tubing, a snubbing unit, or jointed tubing with a workover rig may still be necessary due to proppant flowback, in which case the solution can leverage coiled tubing or a jointed workstring with a HB-3 or other suitable shifting tool to re-open each example fracturing sleeve starting at the toe after fracturing operations conclude.

[0214] Using example embodiments in fracturing operations also reduces completion cycle time and NPT via relatively short fracturing stage transition time per stage, gives an option for significantly higher fracturing rates per ft of lateral (e.g., 100 BPM per 220’ stage or 0.45 BPM/ft for P n’ P versus 50 BPM per 47’ stage or 1.06 BPM/ft for example fracturing sleeve completion), eliminates “swinging iron”, and eliminates the risk of sticking/pulling live perforating guns. Several pad wells can be simultaneously fractured using example embodiments to further compress cycle time and to enhance fracture complexity by steering the fracturing with stress shadowing and promoting shear fracturing events (“torqueing” the rock). There is also an option for using far field diverters and non-continuous pumping schedules to further enhance fracture complexity when example embodiments are used. Example embodiments also require minimal overflush into each example fracturing sleeve at fracturing rates via no wireline/plug pump-down requirement.

[0215] Completions using example fracturing sleeves enable reduced casing size in lateral wellbore sections due to the lower injection rates needed for single entry point staging. For example, for an initial design with 6-3/4” lateral holes, either a 7-5/8” production string with a 4- 1/2” liner or a tapered 5-1/2” x 4-1/2” may be required to accommodate future lift requirements. There is also the possibility for reducing frac tree size to 4-1/16”. Because each example fracturing sleeve is closed immediately after fracturing, proppant influx into the casing while fracturing the next stage due to cross-stage pressure equalization is prevented. Also, less proppant will flowback if it is determined that less proppant is required after testing non- sequential pinpoint stimulation using simul-frac technique.

[0216] When example embodiments are used in a fracturing operation, selective re stimulation/improved oil recovery (IOR) injection or stage shut-off for conformance is enabled using HB-3 or other sleeve shifting tool and coiled tubing or a jointed workstring intervention to recycle sleeves (e.g., cyclic hydrocarbon gas injection, chemical IOR, refracs, and closing sleeves to shut-off intervals producing excessive water/gas/H2S or theft zone). Using example embodiments also facilitates longer laterals with 10K iron via no pump-down, no drillout, and less fluid friction loss at relatively low injection rates (e.g., < 50 BPM). Also, example fracturing sleeves can be designed to meet or exceed specifications of the host casing, including an ability to rotate during casing running operations.

[0217] Accordingly, many modifications and other embodiments set forth herein will come to mind to one skilled in the art to which example embodiments pertain having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. Therefore, it is to be understood that example embodiments are not to be limited to the specific embodiments disclosed and that modifications and other embodiments are intended to be included within the scope of this application. Although specific terms are employed herein, they are used in a generic and descriptive sense only and not for purposes of limitation.