MULTIPLE STAGE WELLBORE COMPLETION DESIGN

Description

TECHNICAL FIELD

The present application is related to subterranean field operations and, more particularly, to multiple stage wellbore completion design.

BACKGROUND

A strategy for increasing production of subterranean resources from a subterranean formation is implementation of various fracture designs, particularly in unconventional (e.g., shale, low permeability, tight) formations. Without sufficient amounts of fracturing of a subterranean formation, much of the subterranean resource (e.g., oil, natural gas) remains trapped in the subterranean formation without being produced. At the other extreme, fracturing too much may collapse a number of the available pathways for the subterranean resource within the subterranean formation, potentially resulting in underproduction of the subterranean resource. As a result, implementing an optimal fracturing design to balance these extremes is desired.

SUMMARY

In general, in one aspect, the disclosure relates to a method for completing a horizontal section of a wellbore. The method can include executing, at a first time, a first fracturing stage within a portion of the horizontal section of the wellbore, where the first fracturing stage includes a first plurality of fracture clusters at a first plurality of locations along the portion of the horizontal section of the wellbore, and where the first plurality of locations are spaced apart from each other by a distance. The method can also include executing, at a second time that proceeds the first time, a second fracturing stage within the portion of the horizontal section of the wellbore, where the second fracturing stage includes a second plurality of fracture clusters at a second plurality of locations along the portion of the horizontal section of the wellbore, where the second plurality of locations are spaced apart from each other by the distance, and where at least some of the second plurality of locations are positioned between the first plurality of locations.

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

BRIEF DESCRIPTION OF THE DRAWINGS

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, the same reference numerals used in different figures may designate like or corresponding but not necessarily identical elements.

FIG. 1 shows a schematic diagram of a field system with a subterranean wellbore in which example embodiments may be used.

FIGS. 2A and 2B show detailed views of part of the horizontal section of the wellbore of the field system of FIG. 1 in which example embodiments may be used.

FIG. 3 shows a sectional view of a general completion of a horizontal section of a wellbore according to certain example embodiments.

FIGS. 4 through 8 show sectional views of a completion sequence of a portion of the horizontal section of the wellbore of FIG. 3 according to certain example embodiments.

FIG. 9 shows a computing device in accordance with certain example embodiments.

FIG. 10 shows a flowchart of a method for completing a horizontal section of a wellbore according to certain example embodiments.

FIGS. 11 through 18 show schematic drawings of a completion sequence for a portion of a horizontal section of a wellbore according to certain example embodiments.

FIGS. 19 through 31 schematic drawings of other completion sequences for a horizontal section of a wellbore according to certain example embodiments.

FIGS. 32 through 35 show various completion sequences for a portion of a horizontal section of a wellbore according to certain example embodiments.

DETAILED DESCRIPTION

The example embodiments discussed herein are directed to systems, apparatus, methods, and devices for a multiple stage wellbore completion design. Example embodiments may be used in land-based or sea-based oil and gas projects, geothermal projects, carbon capture and sequestration utilization projects, water disposal projects, helium projects, lithium projects, solution mining projects, and hydrogen projects. Example embodiments may be used in any type of subterranean formation, including but not limited to unconventional formations (e.g., shale) and tight formations. As defined herein, a completion design includes fracturing a subterranean formation. According to example embodiments, the wellbore completion design is executed in multiple stages. Each stage of a completion design according to certain example embodiments includes fracturing a portion of a section (e.g., a horizontal section) of a wellbore.

The use of the terms “about”, “approximately”, and similar terms applies to all numeric values, whether or not explicitly indicated. These terms generally refer to a range of numbers that one of ordinary skill in the art would consider as a reasonable amount of deviation to the recited numeric values (i.e., having the equivalent function or result). For example, this term may be construed as including a deviation of +10 percent of the given numeric value provided such a deviation does not alter the end function or result of the value. Therefore, a value of about 1% may be construed to be a range from 0.9% to 1.1%. Furthermore, a range may be construed to include the start and the end of the range. For example, a range of 10% to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein. Similarly, a range of between 10% and 20% (i.e., range between 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein.

A “subterranean formation” refers to practically any volume under a surface. For example, it may be practically any volume under a terrestrial surface (e.g., a land surface), practically any volume under a seafloor, etc. Each subsurface volume of interest may have a variety of characteristics, such as petrophysical rock properties, reservoir fluid properties, reservoir conditions, hydrocarbon properties, or any combination thereof. For example, each subsurface volume of interest may be associated with one or more of: temperature, porosity, salinity, permeability, water composition, mineralogy, hydrocarbon type, hydrocarbon quantity, reservoir location, pressure, etc. Those of ordinary skill in the art will appreciate that the characteristics are many, including, but not limited to, shale gas, shale oil, tight gas, tight oil, tight carbonate, carbonate, vuggy carbonate, unconventional (e.g., a permeability of less than 25 millidarcy (mD) such as a permeability of from 0.000001 mD to 25 mD)), diatomite, geothermal, mineral, etc. The terms “formation”, “subsurface formation”, “hydrocarbon-bearing formation”, “reservoir”, “subsurface reservoir”, “subsurface area of interest”, “subsurface region of interest”, “subsurface volume of interest”, and the like may be used synonymously. The term “subterranean formation” is not limited to any description or configuration described herein.

A “well” or a “wellbore” refers to a single hole, usually cylindrical, that is drilled into a subsurface volume of interest. A well or a wellbore may be drilled in one or more directions. For example, a well or a wellbore may include a vertical well, a horizontal well, a deviated well, and/or other type of well. A well or a wellbore may be drilled in the subterranean formation for exploration and/or recovery of resources. A plurality of wells (e.g., tens to hundreds of wells) or a plurality of wellbores are often used in a field depending on the desired outcome.

A well or a wellbore may be drilled into a subsurface volume of interest using practically any drilling technique and equipment known in the art, such as geosteering, directional drilling, etc. Drilling the well may include using a tool, such as a drilling tool that includes a drill bit and a drill string. Drilling fluid, such as drilling mud, may be used while drilling in order to cool the drill tool and remove cuttings. Other tools may also be used while drilling or after drilling, such as measurement-while-drilling (MWD) tools, seismic-while-drilling tools, wireline tools, logging-while-drilling (LWD) tools, or other downhole tools. After drilling to a predetermined depth, the drill string and the drill bit may be removed, and then the casing, the tubing, and/or other equipment may be installed according to the design of the well. The equipment to be used in drilling the well may be dependent on the design of the well, the subterranean formation, the hydrocarbons, and/or other factors.

A well may include a plurality of components, such as, but not limited to, a casing, a liner, a tubing string, a sensor, a packer, a screen, a gravel pack, artificial lift equipment (e.g., an electric submersible pump (ESP)), and/or other components. If a well is drilled offshore, the well may include one or more of the previous components plus other offshore components, such as a riser. A well may also include equipment to control fluid flow into the well, control fluid flow out of the well, or any combination thereof. For example, a well may include a wellhead, a choke, a valve, and/or other control devices. These control devices may be located on the surface, in the subsurface (e.g., downhole in the well), or any combination thereof. In some embodiments, the same control devices may be used to control fluid flow into and out of the well. In some embodiments, different control devices may be used to control fluid flow into and out of a well. In some embodiments, the rate of flow of fluids through the well may depend on the fluid handling capacities of the surface facility that is in fluidic communication with the well. The equipment to be used in controlling fluid flow into and out of a well may be dependent on the well, the subsurface region, the surface facility, and/or other factors. Moreover, sand control equipment and/or sand monitoring equipment may also be installed (e.g., downhole and/or on the surface). A well may also include any completion hardware that is not discussed separately. The term “well” may be used synonymously with the terms “borehole,” “wellbore,” or “well bore.” The term “well” is not limited to any description or configuration described herein.

It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if an item is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components. For example, in some embodiments, the item described by this phrase could include only a component of type A.

In some embodiments, the item described by this phrase could include only a component of type B. In some embodiments, the item described by this phrase could include only a component of type C. In some embodiments, the item described by this phrase could include a component of type A and a component of type B. In some embodiments, the item described by this phrase could include a component of type A and a component of type C. In some embodiments, the item described by this phrase could include a component of type B and a component of type C. In some embodiments, the item described by this phrase could include a component of type A, a component of type B, and a component of type C.

In some embodiments, the item described by this phrase could include two or more components of type A (e.g., A1 and A2). In some embodiments, the item described by this phrase could include two or more components of type B (e.g., B1 and B2). In some embodiments, the item described by this phrase could include two or more components of type C (e.g., C1 and C2). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C).

In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type C (C1 and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).

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 may be inferred to that component. Conversely, if a component in a figure is labeled but not described, the description for such component may 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 number 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.

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.

Equipment used to implement example embodiments may be made of one or more of a number of suitable materials to reliably execute the completions set forth here. Examples of such materials can include, but are not limited to, aluminum, stainless steel, fiberglass, glass, plastic, thermoplastic, ceramic, composite materials, and rubber. In addition, equipment used to implement example embodiments, as well as the method for implementing example embodiments, may be designed to 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), the International Association of Classification Societies (IACS), and the Occupational Safety and Health Administration (OSHA).

Example embodiments of multiple stage wellbore completion designs will be described more fully hereinafter with reference to the accompanying drawings, in which example embodiments of multiple stage wellbore completion design are shown. Multiple stage wellbore completion design 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 multiple stage wellbore completion design 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.

Terms such as “first”, “second”, “primary,” “secondary,” “above”, “below”, “inner”, “outer”, “distal”, “proximal”, “end”, “top”, “bottom”, “upper”, “lower”, “side”, “width,”, “height”, “depth”, “length”, “left”, “right”, “front”, “rear”, and “within”, when present, are used merely to distinguish one component (or part of a component or state of a component or orientation 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 multiple stage wellbore completion design. 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.

FIG. 1 shows a schematic diagram of a land-based field system 199 with which example embodiments may be used. FIG. 2A shows a detail of a substantially horizontal section 103 of the wellbore 120 of FIG. 1. FIG. 2B shows a detail of a fracture 101 of FIG. 2A. The field system 199 of FIG. 1 includes a producing wellbore 120 disposed in a subterranean formation 110 using field equipment 109 (e.g., a derrick, a tool pusher, a clamp, a tong, drill pipe, casing pipe, a drill bit, a wireline tool or assembly, a fluid pumping system, a sensor device, a valve, a generator, a circulation system, a mud logging system, a mud processing system, a compressor) located above a surface 108 and/or within the wellbore 120.

The field system 199 also includes one or more controllers 170, a network manager 180, one or more sensor devices 160, one or more users 151, and one or more user systems 155. Some or all of the field equipment 109 may be controlled by a controller 170. The field system 199 may include a single controller 170 or multiple controllers 170. A controller 170 may be a stand-alone component. Alternatively, a controller 170 may be integrated with one or more other components (e.g., a motor, a wireline tool, a valve) of the field equipment 109. When there are multiple controllers 170 (e.g., one controller 170 for valves in the wellhead, another controller 170 for a wireline assembly, yet another controller for the motors that feed the circulation pumps), each controller 170 may operate independently of each other. Alternatively, one or more of the controllers 170 may work cooperatively with each other. In yet another alternative, one of the controllers 170 may control some or all of one or more other controllers 170 in the field system 199. Each controller 170 may be considered a type of computer device, as discussed below with respect to FIG. 9.

A controller 170 may perform a number of functions that may include obtaining and sending data, evaluating data, following protocols (e.g., methods), running algorithms (e.g., models, formulas), and sending commands. A controller 170 of FIG. 1 may include one or more of a number of components to perform its various functions. For example, components of a controller 170 may include, but are not limited to, a control engine, an analysis module, a communication module, a timer, a counter, a power module, a storage repository, a hardware processor, memory, a transceiver, an application interface, and a security module. If some or all of a controller 170 is remotely located from a component of the field equipment 109 that is controlled by the controller 170, the controller 170 may communicate with the component of the field equipment 109 using one or more communication links 105 (discussed below).

A user 151 may be any person that interacts, directly or indirectly, with a controller 170 and/or any other component (e.g., a valve among the field equipment 109) of the field system 199. Examples of a user 151 may include, but are not limited to, a business owner, an engineer, a company representative, a geologist, a consultant, a drilling engineer, a contractor, and a manufacturer's representative. A user 151 may use one or more user systems 155, which may include a display (e.g., a GUI). A user system 155 of a user 151 may interact with (e.g., send data to, obtain data from) a controller 170 via an application interface and using the communication links 105. The user 151 may also interact directly with a controller 170 through a user interface (e.g., keyboard, mouse, touchscreen).

Each sensor device 160 of the field system 199 may include one or more sensors that measure one or more parameters (e.g., pressure, flow rate, temperature, humidity, fluid content, voltage, current, permeability, porosity, rock characteristics, chemical elements in a fluid, chemical elements in a solid, concentrations, proximity, depth, location, etc.). Examples of a sensor of a sensor device 160 may include, but are not limited to, a temperature sensor, a flow sensor, a pressure sensor, a gas spectrometer, a voltmeter, an ammeter, a permeability meter, a spectrograph, a gas chromatograph, a porosimeter, a gyroscope, and a camera. A sensor device 160 may be a stand-alone device or integrated with another component (e.g., a wireline tool of the field equipment 109) of the field system 199. When a sensor device 160 includes a controller, the sensor device 160 may correspond to a computer system as described below with regard to FIG. 9.

The network manager 180 is a device or component that controls all or a portion (e.g., a communication network, the controller 170) of the field system 199. The network manager 180 may be substantially similar to some or all of the controller 170, as described above. For example, the network manager 180 may include a controller that has one or more components and/or similar functionality to some or all of the controller 170. Alternatively, the network manager 180 may include one or more of a number of features in addition to, or altered from, the features of the controller 170. As described herein, control and/or communication with the network manager 180 may include communicating with one or more other components of the same field system 199 and/or another system. In such a case, the network manager 180 may facilitate such control and/or communication. The network manager 180 may be called by other names, including but not limited to a master controller, a network controller, and an enterprise manager. The network manager 180 may be considered a type of computer device, as discussed below with respect to FIG. 9.

Interaction between each controller 170, the sensor devices 160, the field equipment 109, the users 151 (including any associated user systems 155), the network manager 180, and other components of the field system 199 may be conducted using communication links 105. Each communication link 105 may include wired (e.g., Class 1 electrical cables, Class 2 electrical cables, electrical connectors, Power Line Carrier, RS485) and/or wireless (e.g., Wi-Fi, Zigbec, visible light communication, cellular networking, Bluetooth, Bluetooth Low Energy (BLE), ultrawide band (UWB), WirelessHART, ISA100) technology. A communication link 105 may transmit signals (e.g., communication signals, control signals, data) between each controller 170, the sensor devices 160, the field equipment 109, the users 151 (including any associated user systems 155), the network manager 180, and the other components of the field system 199.

A user 151 (which may include an associated user system 155), the sensor devices 160, the field equipment 109, the network manager 180, and the other components of the field system 199 may interact with a controller 170 using an application interface of the controller 170. Specifically, the application interface of a controller 170 may obtain data (e.g., information, communications, instructions, updates to firmware) from and sends data (e.g., information, communications, instructions) to the user systems 155 of the users 151, the sensor devices 160, the field equipment 109, the network manager 180, and/or the other components of the field system 199. Examples of an application interface may be or include, but are not limited to, an application programming interface, a web service, a data protocol adapter, some other hardware and/or software, or any suitable combination thereof. Similarly, the user systems 155 of the users 151, the sensor devices 160, the field equipment 109, the network manager 180, and/or the other components of the field system 199 may include an interface (similar to the application interface of the controller 170) to obtain data from and send data to a controller 170 in certain example embodiments.

In addition, as discussed above with respect to a user system 155 of a user 151, one or more of the sensor devices 160, one or more of the other controllers 170 some or all of the field equipment 109, the network manager 180, and/or one or more of the other components (or portions thereof) of the field system 199 may include a user interface. Examples of such a user interface may include, but are not limited to, a graphical user interface, a touchscreen, a keyboard, a monitor, a mouse, some other hardware, or any suitable combination thereof.

The controller 170, the users 151 (including associated user systems 155), the sensor devices 160, the field equipment 109, the network manager 180, and the other components of the field system 199 may use their own system or share a system in certain example embodiments. Such a system may 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 a controller 170. Examples of such a system may include, but are not limited to, a desktop computer with a Local Area Network (LAN), a 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 may correspond to a computer system as described below with regard to FIG. 9.

Further, as discussed above, such a system may have corresponding software (e.g., user system software, sensor device software, controller software). The software may 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 may 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 may be a part of, or operate separately but in conjunction with, the software of another system within the field system 199.

With respect to the field system 199 of FIG. 1, 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., natural gas, oil, produced water) from the subterranean formation 110. Field equipment 109, located at the surface 108, is used to drill, encase, monitor, fracture, produce, and/or perform any other part of a field operation with respect to the wellbore 120. The wellbore 120 of FIG. 1 starts out with a substantially vertical section 104, and then has a substantially horizontal section 103. This configuration of the wellbore 120 is common for exploration and production of subterranean resources, such as oil and natural gas.

The surface 108 may be ground level for an onshore application and the sea floor (or other similar floor under a body of water) for an offshore application. A body of oil may include, but it not limited to, trapped oil in rock, movable oil in rock, or free flowing oil in a reservoir. For offshore applications, at least some of the field equipment may be located on a platform that sits above the water level. The point where the wellbore 120 begins at the surface 108 may be called the wellhead.

While not shown in FIG. 1, there may be multiple wellbores 120, each with its own wellhead but that is located close to the other wellheads, drilled into the subterranean formation 110 and having substantially vertical sections 104 and/or horizontal sections 103 that are close to each other. In such a case, the multiple wellbores 120 may be drilled at the same pad and/or at different pads. Example embodiments may be used to help determine, for example, the entry point of each wellbore (e.g., wellbore 120) in the surface (e.g., surface 108), the path of each wellbore in the subterranean formation (e.g., subterranean formation 110), the depth of each wellbore, and the relative location of one wellbore to one or more of the other wellbores.

During the process of drilling the wellbore 120 of FIG. 1, as detailed in FIGS. 2A and 2B, core samples, cuttings, produced oil, formation oil, water 146 (e.g., produced water, formation water), and/or other subterranean resources 111 (e.g., relatively small amounts of oil or natural gas) may be extracted (or otherwise obtained) from downhole to the surface 108, where some of the field equipment 109 separates out at least some of the cuttings and recirculates the at least some of the remainder back downhole. When the drilling process is complete, other operations, such as fracturing operations and production operations, may be performed. While the subterranean formation 110 may have naturally-occurring fractures 101 and some fractures 101 that may be created when drilling the wellbore 120, these fractures 101 may need to be enlarged and elongated, and additional fractures 101 may need to be created, in order to extract additional subterranean resources 111 (e.g., oil, natural gas) from the subsurface.

The fractures 101 are shown to be located in the horizontal section 103 of the wellbore 120 in FIG. 1 as part of fracture clusters 132. The fracture clusters 132 are created (e.g., using hydraulic fracturing) during a stage of a completion design according to certain example embodiments. In FIG. 2A, there are 15 fracture clusters 132. The fractures 101, whether created and/or naturally occurring, may additionally or alternatively be located in other sections (e.g., a substantially vertical section 104, a transition area between a vertical section 104 and a horizontal section 103) of the wellbore 120. In some cases, a wellbore has no substantially horizontal sections (e.g., horizontal section 103). Example embodiments may be used along any portion of a wellbore (e.g., wellbore 120) where fractures 101 are naturally located and/or where fracture clusters 132 may be created.

The subterranean formation 110 may include one or more of a number of formation types, including but not limited to shale, limestone, sandstone, clay, sand, and salt. Such formation types may be considered tight and/or unconventional. In certain embodiments, a subterranean formation 110 may include one or more reservoirs in which one or more resources (e.g., oil, natural gas, water) may be located. One or more of a number of field operations (e.g., fracturing (e.g., hydraulic fracturing), coring, tripping, drilling, setting casing, extracting downhole resources, production) may be performed to reach an objective of a user with respect to the subterranean formation 110.

The wellbore 120 may have one or more of a number of segments or hole sections, where each segment or hole section may have one or more of a number of dimensions. Examples of such dimensions may include, but are not limited to, a 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 may be multiple overlapping casing strings of various sizes (e.g., length, outer diameter) contained within and between these segments or hole sections to ensure the integrity of the wellbore construction. In this case, one or more of the segments of the subterranean wellbore 120 is the substantially horizontal section 103.

As discussed above, inserted into and disposed within the wellbore 120 of FIG. 1 are a number of casing pipes that are coupled to each other end-to-end to form the casing string 125. In these cases, each end of a casing pipe has mating threads (a type of coupling feature) disposed thereon, allowing a casing pipe to be directly or indirectly mechanically coupled to another casing pipe in an end-to-end configuration. The casing pipes of the casing string 125 may be indirectly mechanically coupled to each other using a coupling device, such as a coupling sleeve.

Each casing pipe of the casing string 125 may have a length and a width (e.g., outer diameter). The length of a casing pipe may vary. For example, a common length of a casing pipe is approximately 40 feet. The length of a casing pipe may be longer (e.g., 60 feet) or shorter (e.g., 10 feet) than 40 feet. The width of a casing pipe may also vary and may depend on the cross-sectional shape of the casing pipe. For example, when the shape of the casing pipe is cylindrical, the width may refer to an outer diameter, an inner diameter, or some other form of measurement of the casing pipe. Examples of a width in terms of an outer diameter may include, but are not limited to, 4½ inches, 7 inches, 7⅝ inches, 8⅝ inches, 10¾ inches, 13⅜ inches, and 14 inches.

The size (e.g., width, length) of the casing string 125 may 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 that traverses the length of the casing string 125. Each casing pipe may be made of one or more of a number of suitable materials, including but not limited to steel. Cement is poured into the wellbore 120 through the cavity and then forced upward 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.

Once the cement dries, a number of fracture clusters 132 are created in the subterranean formation 110 during a fracturing operation. The fracture clusters 132 may be created in any of a number of ways known in the industry, including but not limited to hydraulic fracturing and/or other methods of generating fractures. The hydraulic fracturing process involves the injection of large quantities of fluids containing water, chemical additives, and proppant 112 into the subterranean formation 110 from the wellbore 120 to create fracture networks. A subterranean formation 110 naturally has fractures 101, but these naturally occurring fractures 101 often have inconsistent characteristics (e.g., length, spacing) and so in some cases cannot be relied upon for extracting subterranean resources without having additional fractures 101 within fracture clusters 132, such as what is shown in FIG. 2A, created in the subterranean formation 110.

Operations that create fracture clusters 132 in the subterranean formation 110 use any of a number of fluids that include proppant 112 (e.g., sand, ceramic pellets). When proppant 112 is used, some of the fractures 101 (also sometimes called principal or primary fractures) in the fracture clusters 132 receive proppant 112, while a remainder of the fractures 101 (also sometimes called secondary fractures) in the fracture clusters 132 do not have any proppant 112 in them.

As shown in FIG. 2B, the proppant 112 is designed to become lodged inside at least some of the created fractures 101 in the fracture clusters 132 to keep those fractures 101 open after the fracturing operation is complete. The size of the proppant 112 is an important design consideration. Sizes (e.g., 40/70 mesh, 50/140 mesh) of the proppant 112 may vary. While the shape of the proppant 112 is shown as being uniformly spherical, and the size is substantially identical among the proppant 112, the actual sizes and shapes of the proppant 112 may vary. If the proppant 112 is too small, the proppant 112 will not be effective at keeping the fractures 101 in the fracture clusters 132 open enough to effectively allow water 146 and/or other subterranean resources 111 to flow through the fractures 101 from the rock matrices 162 in the subterranean formation 110 to the wellbore 120. If the proppant 112 is too large, the proppant 112 may plug up the fractures 101, blocking the flow of the water 146 and/or other subterranean resources 111 through the fractures 101.

The use of proppant 112 in certain types of subterranean formation 110, such as shale, may be important. Shale formations typically have permeabilities on the order of microdarcys (μD) to nanodarcys (nD). When fracture clusters 132 are created in such formations with low permeabilities, it is important to sustain the fractures 101 in the fracture clusters 132 and their permeability and conductivity for an extended period of time in order to extract more of the subterranean resource 111. Example embodiments may also be applied to fluids used in other types of field operations, including but not limited to fracturing operations and injection wells.

Regardless of the type (e.g., conventional, unconventional) of subterranean formation 110, when proppant 112 and/or other similar components of a fracturing fluid are used in a fracturing operation, the proppant 112 and/or other similar components may be designed to become lodged within fractures 101 of the fracture clusters 132 that result in principal fractures, which are designed to last (stay open) for a longer period of time as fluids (e.g., water 146, subterranean resources 111) flow therethrough. Fractures 101 among the fracture clusters 132 that do not have proppant 112 and/or other similar components lodged therein may be referred to as secondary fractures, which may not last as long (close or reduce in size more quickly) as principal fractures.

The various created fracture clusters 132 that originate at the wellbore 120 and extend outward into the rock matrices 162 in the subterranean formation 110 in this case have consistent penetration lengths perpendicular to the wellbore 120 and have consistent coverage along at least a portion of the lateral length (substantially horizontal section) of the wellbore 120. For example, created fracture clusters 132 may be 50 meters high and 200 meters long. Further, the created fracture clusters 132 may be spaced a distance 192 apart from each other. The distance 192 (e.g., 25 meters, 5 meters, 12 meters) may be optimized based on the permeability and the porosity of the rock matrix 162 of the subterranean formation 110. Example embodiments use stages of staggered sets of fracture clusters 132, as discussed below, to improve and/or otherwise optimize production of the subterranean resource 111 from the subterranean formation 110.

The fractures 101 in the created fracture clusters 132 create a volume 190 (also sometimes called a target volume 190) within the subterranean formation 110 where the rock matrix 162 of the subterranean formation 110 is connected to the high conductivity fractures 101 located a short distance away. In addition to different configurations of the fracture clusters 132 and associated fractures 101, other factors that may contribute to the viability of the subterranean formation 110 may include, but are not limited to, permeability of the rock matrix 162, capillary pressure, and the temperature and pressure of the subterranean formation 110. Each fracture 101, whether created (e.g., part of a fracture cluster 132) or naturally occurring, is defined by a wall, also called a frac face 102 herein. The frac face 102 provides a transition between the paths formed by the rock matrices 162 in the subterranean formation 110 and the fracture 101. The subterranean resources 111 flow through the paths formed by the rock matrices 162 in the subterranean formation 110 into the fracture 101.

The rock matrices 162, as well as the rest of the subterranean formation 110, both within and outside the volume 190, have a certain amount of water 146 therein. The water 146 may be or include, for example, formation water from the formation matrix within the volume 190, moveable free formation water, and “external” water from non-targeted formation/sources (e.g., outside the target volume 190). These external sources of water 146 may include water from a nearby SWD source(s), a nearby hydrocarbon producing source, and/or other sources.

The water 146 may have any of a number of different components (e.g., minerals, chemical additives, acids, completion brine) in addition to formation water. The contents of water 146 in one part (e.g., outside the volume 190) of the subterranean formation 110 may be the same as, or different than, the contents of the water 146 in other parts (e.g., in the rock matrices 162) of the subterranean formation 110. In some cases, such as during a stage (e.g., a hydraulic fracturing stage) of a field operation, the fluids (e.g., fracturing fluid) used in that stage may mix with or include the water 146, thereby changing the contents or composition of the in situ water chemistry in parts (e.g., at or near the fractures 101) of the subterranean formation 110. The water 146 may include one or more of a number of types of water, including but not limited to sea water, brackish water, flowback or produced water, wastewater (e.g., reclaimed or recycled), brine (e.g., reservoir or synthetic brine), fresh water (e.g., fresh water comprises <1,000 ppm TDS), any other type of water, or any combination thereof.

FIG. 3 shows a sectional view of a general completion of a horizontal section 303 of a wellbore according to certain example embodiments. Referring to the description with respect to FIGS. 1 through 2B above, the horizontal section 303 of FIG. 3 is substantially the same as the horizontal section 103 discussed above. In this example, the entire length 336 of the horizontal section 303 of FIG. 3 has casing 325 (also sometimes called a casing string 325 herein). In some cases, there is cement between the casing 325 and the subterranean formation 310. In alternative embodiments, there is no casing 325 in some or all of the horizontal section 303. Also, the horizontal section 303 is drilled through a target volume 390 within the subterranean formation 310.

In this case, the horizontal section 303 of the wellbore (e.g., similar to the wellbore 120 of FIG. 1) includes (e.g., is divided into) multiple (in this case, N) portions 335. Each portion 335 represents a completion stage according to example embodiments. Portion 335-1 is located toward the distal end (e.g., furthest downhole) of the horizontal section 303. Portion 335-2 is located adjacent to portion 335-1 toward the proximal end (e.g., uphole) of the horizontal section 303. Portion 335-N is located toward the proximal end (e.g., furthest uphole) of the horizontal section 303.

Each portion 335 of the horizontal section 303 has a length 338. In this case, portion 335-1 has a length 338-1, portion 335-2 has a length 338-2, and portion 335-N has a length 338-N. As in this case, the length 338 of one portion 335 may be substantially the same as the length 338 of the other portions 335 of the horizontal section 303. In alternative embodiments, the length 338 of one portion 335 may be different than the length 338 of one or more of the other portions 335 of the horizontal section 303. The sum of all of the portions 335 of the horizontal section 303 may be substantially the same as the overall length 336 of the horizontal section 303.

According to certain example embodiments, each portion 335 of a completion design is executed individually and without overlap with respect to executing another portion 335 of the completion design. For example, while the completion of portion 335-1 is being executed, there is no active completion of any of the other portion 335 (e.g., portion 335-2, portion 335-N) of the horizontal section 303. In certain example embodiments, portions 335 are completed serially along the length of the horizontal section 303 of the wellbore so that a portion 335 about to undergo completion is adjacent to a portion 335 that has just been completed. The completion stages may start with the portion 335 toward the distal end of the horizontal section 303 and work toward the proximal end. Alternatively, the completion stages may start with the portion 335 toward the proximal end of the horizontal section 303 and work toward the distal end.

In some cases, when the completion of a portion 335 is fully executed, an optional barrier 339 (e.g., a plug) may be placed within the cavity 371 of the horizontal section 303 between the portion 335 that was just completed and the adjacent portion about to undergo completion. In this example, optional barrier 339-1 is placed between portion 335-1 and portion 335-2. Optional barrier 339-2 is placed between portion 335-2 and the adjacent uphole portion 335. Optional barrier 339-N−1 is placed between portion 335-N and the adjacent downhole portion 335. Optional barrier 339-N is placed on the uphole side of portion 335-N.

At the point in time captured in FIG. 3, the completion design according to certain example embodiments has not yet begun. For example, there are no perforations or fracture clusters (e.g., fracture cluster 132) in any of the portions 335 of the horizontal section 303. Also, at the point in time captured in FIG. 3, there is no field equipment (e.g., field equipment 109) in the horizontal section 303. For example, there are no wireline tools or assemblies, no bottom hole assemblies integrated with a tubing string, no gun strings, no perforating tools, and no other related equipment in the cavity 371 of the horizontal section 303.

FIGS. 4 through 8 show sectional views of a completion sequence of a portion 335-1 of the horizontal section 303 of the wellbore of FIG. 3 according to certain example embodiments. Referring to the description with respect to FIGS. 1 through 3 above, the portion 335-1 of the horizontal section 303 of the wellbore of FIG. 4, as shown some time after the time captured in FIG. 3, includes a perforating tool 448 that is positioned in the cavity 371 formed by the casing string 325. The perforating tool 448 executes multiple (e.g., 2, 3, 6, 8, 11, X (in this case)) perforations 431 that span across most, if not all, of the length 338-1 of the portion 335-1 and that penetrate the casing string 325 and adjacent parts of the target volume 390 within the subterranean formation 310. In this case, perforation 431-1 is located toward the proximal end (e.g., uphole) of the portion 335-1 of the horizontal section 303. Perforation 431-2 is located downhole and adjacent to perforation 431-1. Perforation 431-3 is located downhole and adjacent to perforation 431-2. Perforation 431-X is located toward the distal end of the portion 335-1.

Adjacent perforations 431 for the portion 335-1 are separated from each other by a distance 437. For example, perforation 431-1 and perforation 431-2 are separated from each other by distance 437-1, and perforation 431-2 and perforation 431-3 are separated from each other by distance 437-2 (e.g., 20 feet, 24 feet, 30 feet, 40 feet). In this case, the perforations 431 of the portion 335-1 are spaced substantially equidistantly from each other, and so distance 437-1 and distance 437-2 are substantially the same. In alternative embodiments, one distance 437 (e.g., distance 437-1) may differ from at least one other distance 437 (e.g., distance 437-2) of the portion 335-1.

The perforating tool 448 may be configured to cause (e.g., execute) multiple perforations 431 at the same time or over a period of time (e.g., 5 seconds, a minute, 10 minutes). The perforating tool 448 may have any of a number of forms currently known in the art or developed in the future. The perforating tool 448 may be conveyed into the portion 335-1 of the horizontal section 303 by a wireline tool, as part of a bottom hole assembly integrated into a tubing string, or some other mode of conveyance.

The perforating tool 448 may be actuated using a controller (e.g., controller 170). One or more sensor devices (e.g., sensor devices 160) may be used to ensure that the perforating tool 448 is placed in the proper position within the cavity 371 of the portion 335-1 of the horizontal section 303 before the perforating tool 448 is actuated. The perforating tool 448 may be actuated automatically (e.g., by a controller 170), manually (e.g., by a user 151, by a user system 155), and/or some combination thereof. The distribution of each of the perforations 431 generated by the perforating tool 448 may be directional (e.g., upward), staggered radially, random, and/or based on some other factor. The distribution of one perforation 431 (or set of perforations 431) may be the same as, or different than, the distribution of one or more of the other perforations 431 for the portion 335-1.

FIG. 5 shows the portion 335-1 of the horizontal section 303 of the wellbore at some point in time (e.g., a few minutes, an hour, a day, a week) subsequent to the time shown in FIG. 4. In some cases, the point in time captured in FIG. 5 is after the fracturing pressure (e.g., 4300 psi) in the fracture clusters 532, driven by the pressure (e.g., 5000 psi) within the cavity 371 of the portion 335-1 of the horizontal section 303, exceeds the minimum horizontal stress (e.g., 4000 psi). The portion 335-1 at the point in time captured in FIG. 5 includes a fracturing tool 549 that is positioned in the cavity 371 formed by the casing string 325. The fracturing tool 549 executes a fracturing stage in which multiple (e.g., 2, 3, 6, 8, 11, X (in this case)) fracture clusters 532 that span across most, if not all, of the length 338-1 of the portion 335-1 are generated (sometimes referred to as executed herein). The fracture clusters 532 originate at the perforations 431 from FIG. 4. Specifically, fracture cluster 532-1 originates at perforation 431-1, fracture cluster 532-2 originates at perforation 431-2, fracture cluster 532-3 originates at perforation 431-3, and fracture cluster 532-X originates at perforation 431-X.

Each fracture cluster 532 penetrates further into the target volume 390 within the subterranean formation 310. In this case, fracture cluster 532-1 is located toward the proximal end (e.g., uphole) of the portion 335-1 of the horizontal section 303. Fracture cluster 532-2 is located downhole and adjacent to fracture cluster 532-1. Fracture cluster 532-3 is located downhole and adjacent to fracture cluster 532-2. Fracture cluster 532-X is located toward the distal end of the portion 335-1.

Adjacent fracture clusters 532 for the portion 335-1 are separated from each other by a distance 537 (e.g., 20 feet, 24 fect, 30 feet, 40 feet) as measured from their central vertical axis. For example, fracture cluster 532-1 and fracture cluster 532-2 are separated from each other by distance 537-1, and fracture cluster 532-2 and fracture cluster 532-3 are separated from each other by distance 537-2. In this case, the fracture clusters 532 of the portion 335-1 are spaced substantially equidistantly from each other, and so distance 537-1 and distance 537-2 are substantially the same. In alternative embodiments, one distance 537 (e.g., distance 537-1) may differ from at least one other distance 537 (e.g., distance 537-2) of the portion 335-1. Since the fracture clusters 532 coincide with the perforations 431 of FIG. 4, the distances 537 between adjacent fracture clusters 532 are the same as and overlap with the corresponding distances 437 between adjacent perforations 431 for the portion 335-1 of the horizontal section 303. For example, distance 537-1 is substantially the same as distance 437-1, and distance 537-2 is substantially the same as distance 437-2.

The fracturing tool 549 may be configured to cause (e.g., execute) multiple fracture clusters 532 at the same time or over a period of time (e.g., 5 seconds, a minute, 10 minutes). The fracturing tool 549 may have any of a number of forms currently known in the art or developed in the future. For example, the fracturing tool 549 may be or include a high pressure pump and a mixer. The fracturing tool 549 may be conveyed into the portion 335-1 of the horizontal section 303 by a wireline tool, as part of a bottom hole assembly integrated into a tubing string, or some other mode of conveyance. Alternatively, the fracturing tool 549 may be located at the surface (e.g., surface 108).

The fracturing tool 549 may be actuated using a controller (e.g., controller 170). One or more sensor devices (e.g., sensor devices 160) may be used to ensure that the fracturing tool 549 is placed in the proper position within the cavity 371 of the portion 335-1 of the horizontal section 303 before the fracturing tool 549 is actuated. The fracturing tool 549 may be actuated automatically (e.g., by a controller 170), manually (e.g., by a user 151, by a user system 155), and/or some combination thereof. The distribution of each of the fracture clusters 532 generated by the fracturing tool 549 may be directional (e.g., upward), staggered radially, random, and/or based on some other factor. The distribution of one fracture cluster 532 (or set of fracture clusters 532) may be the same as, or different than, the distribution of one or more of the other perforations 431 for the portion 335-1.

The fracturing process shown in FIG. 5 may last for some amount of time (e.g., a few hours, a day, a week, a few weeks, a month). In some cases, the pressure within the cavity 371 of the portion 335-1 of the horizontal section 303 may be increased (e.g., using the field equipment 109) gradually (e.g., from 5000 psi to 5200 psi to 5300 psi), which results in an increase in the fracturing pressure (e.g., from 4300 psi to 4500 psi to 4600 psi) within the fracture clusters 532 during this time frame to expand the fracture clusters 532 further into the target volume 390 within the subterranean formation 310. This increase in pressure may be over a long or short period of time. This increase in pressure may be controlled automatically (e.g., by a controller 170, by the network manager 180), manually (e.g., by a user 151, which may include a user system 155), or by some combination thereof. In some cases, when the fracturing in FIG. 5 is complete, the net pressure (e.g., the closure stress) may be dissipated (e.g., slowly, quickly) so that the pressure within the fracture clusters 532 is at or slightly above the minimal horizontal stress.

FIG. 6 shows the portion 335-1 of the horizontal section 303 of the wellbore at some point in time (e.g., a few minutes, an hour, a day, a week) subsequent to the time shown in FIG. 5. At this point in time, the fracturing operation on the fracture clusters 532 is complete. At this point in time, the fracture clusters 532 are isolated at the casing 325 from within the cavity 371. For example, multiple (e.g., 2, 3, 6, 8, 11, X (in this case)) screen outs 633 (e.g., plugs, isolation devices) may be released into the cavity 371 with a low circulation speed so that the screen outs 633 become lodged in the openings of the fracture clusters 532 at the casing 325. For example, screen out 633-1 may become lodged at the casing 325 where fracture cluster 532-1 originates. As another example, screen out 633-2 may become lodged at the casing 325 where fracture cluster 532-2 originates. As yet another example, screen out 633-3 may become lodged at the casing 325 where fracture cluster 532-3 originates. As still another example, screen out 633-X may become lodged at the casing 325 where fracture cluster 532-X originates. The number of screen outs 633 may be the same as, or different than (e.g., greater than, less than) the number of fracture clusters 532 from the fracturing stage shown in FIG. 5.

When the screen outs 633 are in place relative to the originating points of the fracture clusters 532, the fracture clusters 532 maintain their position in the target volume 390 within the subterranean formation 310. The screen outs 633 may be released within the cavity 371 so that they migrate toward the originating points of the fracture clusters 532 by any suitable equipment (e.g., a wireline tool or assembly, at the surface by a user 151) that is currently used in the art or that may be developed in the future. The screen outs 633 may be released within the cavity 371 automatically (e.g., by a controller 170, by the network manager 180), manually (e.g., by a user 151, which may include a user system 155), or any combination thereof. As defined herein, a screen out generally refers to a barrier (e.g., a plug, a diverter, an isolation device) that substantially prevents or reduces fluidic and/or pressure communication therethrough.

The process of releasing the screen outs 633 so that the screen outs 633 migrate to and block the originating points of the fracture clusters 532 at the casing 325 may be referred to herein as executing the screen outs 633. In some cases, executing the screen outs 633 may isolate pressures within the associated fracture clusters 532 at approximately a minimum closure stress level (sometimes referred to as a minimum shadow stress level or, in some instances, a minimum horizontal stress level). In other words, the screen outs 633 may be executed after the net pressure dissipates. As defined herein, a minimum closure stress generally refers to the minimum in situ stress on a layer-basis because the pressure required to open a fracture is the same as the pressure required to overcome the stress in the rock perpendicular to the fracture.

When the fracture clusters 532 have been plugged with the screen outs 633, the next fracturing stage according to certain example embodiments is ready to begin. The portion 335-1 of the horizontal section 303 of the wellbore of FIG. 7, as shown some time after the time captured in FIG. 6, includes a perforating tool 748 that is positioned in the cavity 371 formed by the casing string 325. The perforating tool 748 executes multiple (e.g., 2, 3, 6, 8, 11, X (in this case)) perforations 731 that span across most, if not all, of the length 338-1 of the portion 335-1 and that penetrate the casing string 325 and adjacent parts of the target volume 390 within the subterranean formation 310. In this case, the number of perforations 731 is the same as the number of perforations 431. In alternative embodiments, the number of perforations 731 is different than the number of perforations 431.

In this case, perforation 731-1 is located toward the proximal end (e.g., uphole) of the portion 335-1 of the horizontal section 303 between the screen out 633-1 plugging the fracture cluster 532-1 and the screen out 633-2 plugging the fracture cluster 532-2. Perforation 731-2 is located downhole of perforation 731-1 between the screen out 633-2 plugging the fracture cluster 532-2 and the screen out 633-3 plugging the fracture cluster 532-3. Perforation 731-3 is located adjacent to and downhole from the screen out 633-3 plugging the fracture cluster 532-3. Perforation 731-X is located toward the distal end of the portion 335-1, adjacent to and downhole from the screen out 633-X plugging the fracture cluster 532-X.

Adjacent perforations 731 for the portion 335-1 are separated from each other by a distance 737. For example, perforation 731-1 and perforation 731-2 are separated from each other by distance 737-1, and perforation 731-2 and perforation 731-3 are separated from each other by distance 737-2 (e.g., 20 feet, 24 feet, 30 feet, 40 feet). In this case, the perforations 731 of the portion 335-1 are spaced substantially equidistantly from each other, and so distance 737-1 and distance 737-2 are substantially the same. In alternative embodiments, one distance 737 (e.g., distance 737-1) may differ from at least one other distance 737 (e.g., distance 737-2) of the portion 335-1.

Also, as in this example, the distances 737 between adjacent perforations 731 may be substantially the same as the distances 437 between adjacent perforations 431 (which in this case is also the same as the distances 537 between fracture clusters 532). In alternative embodiments, the distances 737 between adjacent perforations 731 may be different than the distances 437 between adjacent perforations 431. Further, the positioning of the perforations 731 relative to the fracture clusters 532 may vary. A perforation 731 is a distance 634 from an adjacent uphole fracture cluster 532 and a distance 734 from an adjacent downhole fracture cluster 532. For example, perforation 731-1 is distance 634-1 from fracture cluster 532-1 and distance 734-1 from fracture cluster 532-2. As another example, perforation 731-2 is distance 634-2 from fracture cluster 532-2 and distance 734-2 from fracture cluster 532-3. As yet other examples, perforation 731-3 is distance 634-3 from fracture cluster 532-3, and perforation 731-X is distance 634-X from fracture cluster 532-X.

In this example, the perforations 731 are substantially halfway between adjacent fracture clusters 532. Further, as discussed above, the perforations 731 are arranged substantially equidistantly from each other along the length 338-1 of the portion 335-1. As a result, each distance 634 is substantially the same as each distance 734. Further, the distances 634 are substantially the same as each other, and the distances 734 are substantially the same as each other. In alternative embodiments, as when the distribution of the perforations 731 varies along the length 338-1 of the portion 335-1, one or more of the distances 634 may vary from each other and/or from the distances 734, and one or more of the distances 734 may vary from each other and/or from the distances 634. In other alternative embodiments, as when the perforations 731 are evenly distributed but are not positioned substantially halfway between adjacent fracture clusters 532, the distances 634 are substantially the same as each other, and the distances 734 are substantially the same as each other. However, the distances 634 are different from the distances 734. Such a configuration may be used when there are more than 2 stages (e.g., 3 stages, 4 stages, 5 stages) for completing the portion 335-1. In certain example embodiments, completing any portion (e.g., portion 335-1) of a horizontal section (e.g., horizontal section 303) may be done in any number (e.g., 1, 2, 3, 4, 8, 14, 25) of stages, where each stage can have any number (e.g., 2, 3, 4, 9, 14, 21, 33) of clusters (e.g., clusters 532).

The perforating tool 748 of FIG. 7 may be substantially the same as the perforating tool 448 of FIG. 4. For example, the perforating tool 748 may be configured to cause (e.g., execute) multiple perforations 731 at the same time or over a period of time (e.g., 5 seconds, a minute, 10 minutes). The perforating tool 748 may have any of a number of forms currently known in the art or developed in the future. The perforating tool 748 may be conveyed into the portion 335-1 of the horizontal section 303 by a wireline tool, as part of a bottom hole assembly integrated into a tubing string, or some other mode of conveyance.

The perforating tool 748 may be actuated using a controller (e.g., controller 170). One or more sensor devices (e.g., sensor devices 160) may be used to ensure that the perforating tool 748 is placed in the proper position within the cavity 371 of the portion 335-1 of the horizontal section 303 before the perforating tool 748 is actuated. The perforating tool 748 may be actuated automatically (e.g., by a controller 170), manually (e.g., by a user 151, by a user system 155), and/or some combination thereof. The distribution of each of the perforations 731 generated by the perforating tool 748 may be directional (e.g., upward), staggered radially, random, and/or based on some other factor. The distribution of one perforation 731 (or set of perforations 731) may be the same as, or different than, the distribution of one or more of the other perforations 731 for the portion 335-1.

FIG. 8 shows the portion 335-1 of the horizontal section 303 of the wellbore at some point in time (e.g., a few minutes, an hour, a day, a week) subsequent to the time shown in FIG. 7. In some cases, the point in time captured in FIG. 8 is after the fracturing pressure (e.g., 4400 psi) in the fracture clusters 832, driven by the pressure (e.g., 5100 psi) within the cavity 371 of the portion 335-1 of the horizontal section 303, exceeds the minimum horizontal stress (e.g., 4000 psi). At this time, the fracturing pressure (e.g., 4200) in the fracture clusters 532 with the screen outs 633 (from the prior fracturing stage) may be less than the fracturing pressure in the fracture clusters 832 in the current fracturing stage.

The portion 335-1 at the point in time captured in FIG. 8 includes a fracturing tool 849 that may be positioned in the cavity 371 formed by the casing string 325 and/or at the surface (e.g., surface 108). The fracturing tool 849 executes another fracturing stage in which multiple (e.g., 2, 3, 6, 8, 11, X (in this case)) fracture clusters 832 that span across most, if not all, of the length 338-1 of the portion 335-1 are implemented. Specifically, the fracture clusters 832 in this fracturing stage originate at the perforations 731 from FIG. 7. As a result, fracture cluster 832-1 originates from perforation 731-1, fracture cluster 832-2 originates from perforation 731-2, fracture cluster 832-3 originates from perforation 731-3, and fracture cluster 832-X originates from perforation 731-X. In addition, the number of fracture clusters 832 in the current fracturing stage may be the same as (such as in this example) or different than the number of fracture clusters 532 from the previous fracturing stage.

Each fracture cluster 832 penetrates further into the target volume 390 within the subterranean formation 310. In this case, fracture cluster 832-1 is located toward the proximal end (e.g., uphole) of the portion 335-1 of the horizontal section 303 between the screen out 633-1 plugging the fracture cluster 532-1 and the screen out 633-2 plugging the fracture cluster 532-2. Fracture cluster 832-2 is located downhole and adjacent to fracture cluster 832-1 between the screen out 633-2 plugging the fracture cluster 532-2 and the screen out 633-3 plugging the fracture cluster 532-3. Fracture cluster 832-3 is located downhole and adjacent to fracture cluster 832-2 between the screen out 633-2 plugging the fracture cluster 532-2 and the screen out 633-3 plugging the fracture cluster 532-3. Fracture cluster 832-3 is located adjacent to and downhole from fracture cluster 532-3. Fracture cluster 832-X is located toward the distal end of the portion 335-1 adjacent to and downhole from fracture cluster 532-X.

Adjacent fracture clusters 832 for the portion 335-1 are separated from each other by a distance 837 (e.g., 20 feet, 24 feet, 30 feet, 40 fect) as measured from their central vertical axis. For example, fracture cluster 832-1 and fracture cluster 832-2 are separated from each other by distance 837-1, and fracture cluster 832-2 and fracture cluster 832-3 are separated from each other by distance 837-2. In this case, the fracture clusters 832 of the portion 335-1 are spaced substantially equidistantly from each other, and so distance 837-1 and distance 837-2 are substantially the same. In alternative embodiments, one distance 837 (e.g., distance 837-1) may differ from at least one other distance 837 (e.g., distance 837-2) of the portion 335-1. Since the fracture clusters 832 coincide with the perforations 731 of FIG. 7, the distances 837 between adjacent fracture clusters 832 are the same as and overlap with the corresponding distances 737 between adjacent perforations 731 for the portion 335-1 of the horizontal section 303.

The fracturing tool 849 may be substantially the same as the fracturing tool 549 of FIG. 5. For example, the fracturing tool 849 may be configured to cause (e.g., execute) multiple fracture clusters 832 at the same time or over a period of time (e.g., 5 seconds, a minute, 10 minutes). The fracturing tool 849 may have any of a number of forms currently known in the art or developed in the future. The fracturing tool 849 may be conveyed into the portion 335-1 of the horizontal section 303 by a wireline tool, as part of a bottom hole assembly integrated into a tubing string, or some other mode of conveyance.

The fracturing tool 849 may be actuated using a controller (e.g., controller 170). One or more sensor devices (e.g., sensor devices 160) may be used to ensure that the fracturing tool 849 is placed in the proper position within the cavity 371 of the portion 335-1 of the horizontal section 303 before the fracturing tool 849 is actuated. The fracturing tool 849 may be actuated automatically (e.g., by a controller 170), manually (e.g., by a user 151, by a user system 155), and/or some combination thereof. The distribution of each of the fracture clusters 832 generated by the fracturing tool 849 may be directional (e.g., upward), staggered radially, random, and/or based on some other factor. The distribution of one fracture cluster 832 (or set of fracture clusters 832) may be the same as, or different than, the distribution of one or more of the other perforations 731 for the portion 335-1.

The fracturing process shown in FIG. 8 may last for some amount of time (e.g., a few hours, a day, a week, a few weeks, a month). In some cases, the pressure within the cavity 371 of the portion 335-1 of the horizontal section 303 may be increased (e.g., using the field equipment 109) gradually (e.g., from 5000 psi to 5200 psi to 5300 psi to 5400 psi), which results in an increase in the fracturing pressure (e.g., from 4300 psi to 4500 psi to 4600 psi to 4700 psi) within the fracture clusters 832 during this time frame to expand the fracture clusters 832 further into the target volume 390 within the subterranean formation 310. This increase in pressure may be over a long or short period of time. This increase in pressure may be controlled automatically (e.g., by a controller 170, by the network manager 180), manually (e.g., by a user 151, which may include a user system 155), or by some combination thereof. In some cases, when the fracturing in FIG. 8 is complete, the net pressure (e.g., the closure stress) may be dissipated (e.g., slowly, quickly) so that the pressure within the fracture clusters 832 is at or slightly above the minimal horizontal stress.

When the fracturing stage captured in FIG. 8 is complete, the process with respect to completion of the portion 335-1 of the horizontal section 303 may be finished. A similar process (e.g., multiple perforations and multiple fracturing stages) may then commence with respect to an adjacent portion 335 (e.g., portion 335-2) of the horizontal section 303 of the wellbore. In such a case, a barrier 339 (e.g., barrier 339-1) may be inserted within the cavity 371 formed by the casing 325 to isolate the portion 335-1 of the horizontal section 303, and there is no need to execute additional screen outs (e.g., similar to the screen outs 633) to plug the fracture clusters 832 where they originate at the casing 325. Alternatively, in such a case, in lieu of inserting a barrier 339, additional screen outs may be released within the cavity 371 to plug the fracture clusters 832 where they originate at the casing 325 before the process encompassed in example embodiments begins on the subsequent portion 335 of the horizontal section 303. In yet another alternative, the portion 335-1 of the horizontal section 303 may be the only or final portion 335 of the horizontal section 303 that undergoes the process according to example embodiments.

Alternatively, as when the distances 634 are different from the distances 734, executing additional screen outs and one or more additional perforations and fracturing stages (e.g., generating additional fracture clusters) may take place before work is complete with respect to the portion 335-1 of the horizontal section 303 of the wellbore. For example, if the distances 634 are half of the distances 734, than additional screen outs (e.g., similar to the screen outs 633) may be released to plug the origination of the fracture clusters 832 at the casing 325. Subsequently, an additional set of perforations may be executed approximately halfway between the fracture clusters 832 and adjacent fracture clusters 532 covered by the distances 734.

FIG. 9 illustrates one embodiment of a computing device 918 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, a controller 94 (including components thereof, such as a control engine, an analysis module, a hardware processor, a storage repository, a power module, and a transceiver) may be considered a computing device 918 (also called a computer system 918 herein). Computing device 918 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 the computing device 918 be interpreted as having any dependency or requirement relating to any one or combination of components illustrated in the example computing device 918.

The computing device 918 includes one or more processors or processing units 914, one or more memory/storage components 915, one or more input/output (I/O) devices 916, and a bus 917 that allows the various components and devices to communicate with one another. The bus 917 represents one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. The bus 917 includes wired and/or wireless buses.

The memory/storage component 915 represents one or more computer storage media. The memory/storage component 915 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). The memory/storage component 915 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).

One or more I/O devices 916 allow a user 151 to enter commands and information to the computing device 918, and also allow information to be presented to the user 151 and/or other components or devices. Examples of input devices 916 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.

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”.

“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.

The computer device 918 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 918 includes at least the minimal processing, input, and/or output means necessary to practice one or more embodiments.

Further, those skilled in the art will appreciate that one or more elements of the aforementioned computer device 918 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., a controller 94, a sensor device 160, a wireline tool) 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.

FIG. 10 shows a flowchart 1089 of a method for completing a horizontal section 303 of a wellbore according to certain example embodiments. While the various steps in this flowchart 1089 are presented sequentially, one of ordinary skill will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Further, in one or more of the example embodiments, one or more of the steps shown in this example method may be omitted, repeated, and/or performed in a different order.

In addition, a person of ordinary skill in the art will appreciate that additional steps not shown in FIG. 10 may be included in performing this method. Accordingly, the specific arrangement of steps should not be construed as limiting the scope. Further, a particular computing device, such as the computing device 918 discussed below with respect to FIG. 9, may be used to facilitate (e.g., direct, control, provide instructions, provide recommendations, perform, execute) the performance of one or more of the steps for the methods shown in FIG. 10 in certain example embodiments. Any of the functions performed below by a controller may involve the use of one or more protocols, one or more algorithms, and/or stored data stored in a storage repository. In addition, or in the alternative, any of the functions in the method may be performed by a user (e.g., user 151), including an associated user system (e.g., user system 155).

The method shown in FIG. 10 is merely an example that may be performed by using an example system described herein. In other words, systems for completing a horizontal section of a wellbore may perform other functions using other methods in addition to and/or aside from those shown in FIG. 10. FIGS. 11 through 18 show schematic drawings of a completion sequence for a portion 1135 of a horizontal section of a wellbore according to certain example embodiments. Referring to the description above with respect to FIGS. 1A through 9, the method shown in the flowchart 1089 of FIG. 10 begins at the START step and proceeds to step 1081, where perforations 431 at locations along a portion 335 of the horizontal section 303 of a wellbore (e.g., wellbore 120) are executed. In some cases, some or all of the portion 335 of the horizontal section 303 is cased with casing 325. The perforations 431 may be executed using a perforating tool 448 that is positioned within the cavity 371 in the portion 335-1 of the horizontal section 303. The perforating tool 448 may be inserted into and positioned within the horizontal section 103 of the wellbore 120 by a user 151 and/or a controller 170 using field equipment 109 (e.g., a wireline tool, a bottom hole assembly) known in the art. In some cases, the perforating tool 448 may be inserted into the cavity 371 of the horizontal section 303 of the wellbore 120 until the perforating tool 448 is adjacent to the casing 325 within the portion 335-1 of the horizontal section 303.

There can be any number of perforations 431 that are executed along the portion 335 of the horizontal section 303. For example, in FIG. 4 above, there are X perforations (perforation 431-1, perforation 431-2, perforation 431-3, and perforation 431-X). Adjacent perforations 431 in this step 1081 may be separated by a distance 437. For example, perforation 431-1 and perforation 431-2 are separated from each other by distance 437-1. As another example, 431-2 and perforation 431-3 are separated from each other by distance 437-2. Each distance 437 may be substantially the same as, or different than, one or more of the other distances 437. The perforations 431 may be executed substantially simultaneously, iteratively, sequentially, or in some other fashion.

Another example of step 1081 is shown in FIG. 11, which shows a schematic view of a portion 1135 of a horizontal section (e.g., similar to the horizontal section 103) of a wellbore (e.g., similar to the wellbore 120). In FIG. 11, the portion 1135 of the horizontal section includes four perforations 1131 (perforation 1131-1, perforation 1131-2, perforation 1131-3, and perforation 1131-4) that extend through the casing 1125 and into the target volume 1190 within the subterranean formation 1110. The distal (downhole) end of the portion 1135 has a barrier 1139 (e.g., substantially similar to the barrier 339 discussed above) that fills the cavity 1171 and isolates portion 1135 from downhole portions of the horizontal section. The perforations 1131 are arranged equidistantly from each other along the length of the portion 1135, where each pair of adjacent perforations 1131 are separated by distance 1137 (e.g., 24 feet).

In step 1082, a fracturing stage is executed at the perforations 431 along the portion 335 of the horizontal section 303 of the wellbore (e.g., wellbore 120). As a result, fracture cluster 532-1 originates from perforation 431-1, fracture cluster 532-2 originates from perforation 431-2, fracture cluster 532-3 originates from perforation 431-3, and fracture cluster 532-4 originates from perforation 431-4. The fracture clusters 532 of the fracturing stage may be executed using a fracturing tool 549 that is positioned within the cavity 371 in the portion 335-1 of the horizontal section 303 and/or is located at the surface (e.g., surface 108). The fracturing tool 549 may be enabled to execute the fracturing stage by a user 151 and/or a controller 170 using field equipment 109 (e.g., a wireline tool, a bottom hole assembly) known in the art. In some cases, the fracturing tool 549 may be inserted into the cavity 371 of the horizontal section 303 of the wellbore 120 until the fracturing tool 549 is adjacent to the casing 325 within the portion 335-1 of the horizontal section 303.

Part of the fracturing stage that is executed in this step 1082 may also include pumping a fracturing fluid into the cavity 371 of the horizontal section 303 and forcing the fracturing fluid, under pressure, into the fracture clusters 532 within the target volume 390 within the subterranean formation 310. The fracture clusters 532 may be executed substantially simultaneously, iteratively, sequentially, or in some other fashion. FIGS. 12 through 15 show an example of how a fracturing stage is executed according to certain example embodiments. FIG. 12 shows the portion 1135 of the horizontal section of FIG. 11 at a subsequent point in time relative to the time captured in FIG. 11. FIG. 12 shows four fracture clusters 1232 (fracture cluster 1232-1, fracture cluster 1232-2, fracture cluster 1232-3, and fracture cluster 1232-4) have been initially executed coincident with the four perforations 1131 of FIG. 11. As a result, where each pair of adjacent fracture clusters 1232 are separated by distance 1237 as measured from their central vertical axis, where the distance is substantially the same as the distance 1137 (e.g., 24 feet) in FIG. 11.

These fracture clusters 1232 are relatively small at the point in time shown in FIG. 12. To develop (expand) the fracture clusters 1232, stimulation occurs. In this case, the fracture clusters 1232 are stimulated by injecting a fracturing fluid 1295 (e.g., proppant 112, water, acid) into the cavity 1171 formed by the casing 1125. The pressure of the fracturing fluid 1295 within the cavity 1171 is controlled (e.g., using field equipment 109). For example, when the perforations 1131 are executed (generated) in FIG. 11, the minimum horizontal stress (e.g., as measured by a sensor device 160) may be 4000 psi.

By controlling the pressure of the fracturing fluid 1295 (e.g., 5000 psi) to exceed the minimum horizontal stress, the fracturing fluid 1295 enters through the perforations 1131 to generate and expand the fracture clusters 1232. The fracturing fluid 1295 then flows into and dissipates in the target volume 1190 within the subterranean formation 1110. At the point in time shown in FIG. 12, the pressure within the fracture clusters 1232 (e.g., 4300 psi) is between the pressure within the cavity 1131 (e.g., 5000 psi) and the minimum horizontal stress (e.g., 4000 psi).

FIG. 13 shows the portion 1135 of the horizontal section of FIG. 12 at a subsequent point in time relative to the time captured in FIG. 12. FIG. 13 shows that the four fracture clusters 1232 (fracture cluster 1232-1, fracture cluster 1232-2, fracture cluster 1232-3, and fracture cluster 1232-4) of FIG. 12 have expanded, which is a result of increasing the pressure of the fracturing fluid 1295 (e.g., from 5000 psi to 5200 psi) pumped into the fracture clusters 1232. When this occurs, the pressure within the fracture clusters 1232 also increases (e.g., from 4300 psi to 4500 psi) but remains between the pressure within the cavity 1131 (e.g., 5200 psi) and the minimum horizontal stress (e.g., 4000 psi). Under the increased pressure, the fracturing fluid 1295 flows further into and dissipates further in the target volume 1190 within the subterranean formation 1110 after traveling through the fracture clusters 1232.

FIG. 14 shows the portion 1135 of the horizontal section of FIG. 13 at a subsequent point in time relative to the time captured in FIG. 13. Specifically, FIG. 14 shows that the four fracture clusters 1232 (fracture cluster 1232-1, fracture cluster 1232-2, fracture cluster 1232-3, and fracture cluster 1232-4) of FIG. 13 have further expanded, which is a result of further increasing the pressure of the fracturing fluid 1295 (e.g., from 5200 psi to 5300 psi) pumped into the fracture clusters 1232. When this occurs, the pressure within the fracture clusters 1232 also increases (e.g., from 4500 psi to 4600 psi) but remains between the pressure within the cavity 1131 (e.g., 5300 psi) and the minimum horizontal stress (e.g., 4000 psi). Under the further increased pressure, the fracturing fluid 1295 flows even further into and dissipates even further in the target volume 1190 within the subterranean formation 1110 after traveling through the fracture clusters 1232.

When the fracturing activity of FIGS. 12 through 14 is complete, the net pressure (the closure stress) is slowly dissipated, as shown in FIG. 15. Specifically, FIG. 15 shows the portion 1135 of the horizontal section of FIG. 14 at a subsequent point in time relative to the time captured in FIG. 14. As a result, FIG. 15 shows that the four fracture clusters 1232 (fracture cluster 1232-1, fracture cluster 1232-2, fracture cluster 1232-3, and fracture cluster 1232-4) of FIG. 14 have contracted dramatically. The fracture clusters 1232 are no longer active, and the pressure within the fracture clusters 1232 (e.g., 4200 psi) is only slightly higher than the minimum horizontal stress (e.g., 4000 psi).

Returning to the method of FIG. 10, when step 1082 is complete, the process proceeds to step 1083, where one or more screen outs 633 are executed at the perforations 431 along the portion 335-1 of the horizontal section 303 of the wellbore (e.g., wellbore 120). As a result, screen out 633-1 plugs fracture cluster 532-1 by lodging in perforation 431-1, screen out 633-2 plugs fracture cluster 532-2 by lodging in perforation 431-2, screen out 633-3 plugs fracture cluster 532-3 by lodging in perforation 431-3, and screen out 633-X plugs fracture cluster 532-X by lodging in perforation 431-X. The screen outs 633 may be executed (e.g., released) using a tool (e.g., a wireline tool) that is positioned within the cavity 371 in the portion 335-1 of the horizontal section 303 and/or by using other field equipment (e.g., field equipment 109) (e.g., a pump, a compressor) at the surface (e.g., surface 108). The screen outs 633 may be executed by a user 151 and/or a controller 170 using field equipment 109 (e.g., a wireline tool, a bottom hole assembly) known in the art.

FIG. 16 shows an example, continuing from the scenario captured in FIG. 15, where the screen outs 1633 have already been executed. As a result, screen out 1633-1 plugs fracture cluster 1232-1 by lodging in perforation 1131-1, screen out 1633-2 plugs fracture cluster 1232-2 by lodging in perforation 1131-2, screen out 1633-3 plugs fracture cluster 1232-3 by lodging in perforation 1131-3, and screen out 1633-4 plugs fracture cluster 1232-4 by lodging in perforation 1131-4. The screen outs 1633 may be executed (e.g., released) using a tool (e.g., a wireline tool) that is positioned within the cavity 1171 in the portion 1135 of the horizontal section and/or by using other field equipment (e.g., field equipment 109) (e.g., a pump, a compressor) at the surface (e.g., surface 108). The screen outs 1633 may be executed by a user 151 and/or a controller 170 using field equipment 109 (e.g., a wireline tool, a bottom hole assembly) known in the art.

In step 1084, perforations 731 at adjacent locations along the portion 335 of the horizontal section 303 of the wellbore (e.g., wellbore 120) are executed. The perforations 731 may be executed using a perforating tool 748 that is positioned within the cavity 371 in the portion 335-1 of the horizontal section 303. The perforating tool 748 may be the same as, or different than, the perforating tool 448 of step 1081 above. The perforating tool 748 may be inserted into and positioned within the horizontal section 103 of the wellbore 120 by a user 151 and/or a controller 170 using field equipment 109 (e.g., a wireline tool, a bottom hole assembly) known in the art. In some cases, the perforating tool 748 may be inserted into the cavity 371 of the horizontal section 303 of the wellbore 120 until the perforating tool 748 is adjacent to the casing 325 within the portion 335-1 of the horizontal section 303.

There can be any number of perforations 731 at locations that are adjacent to the previous perforations 431. For example, in FIG. 7 above, there are X perforations (perforation 731-1, perforation 731-2, perforation 731-3, and perforation 731-X). The number of perforations 731 for the upcoming fracturing stage may be the same as, or different than, the number of perforations 431 from the previous fracturing stage. Adjacent perforations 731 in this step 1084 may be separated by a distance 737. For example, perforation 731-1 and perforation 731-2 are separated from each other by distance 737-1. As another example, 731-2 and perforation 731-3 are separated from each other by distance 737-2. Each distance 737 may be substantially the same as, or different than, one or more of the other distances 737. In addition, a distance 737 may be the same as, or different than, the distance 437 between adjacent perforations 431 from step 1081. The perforations 731 may be executed substantially simultaneously, iteratively, sequentially, or in some other fashion.

Another example of step 1084 is shown in FIG. 16, which shows a schematic view of the portion 1135 of the horizontal section of the wellbore at a time subsequent to what is captured in FIG. 15. In FIG. 16, in addition to the screen outs 1633 plugging the perforations 1131 as discussed with respect to step 1083, the portion 1135 of the horizontal section includes four new perforations 1631 (perforation 1631-1, perforation 1631-2, perforation 1631-3, and perforation 1631-4) that extend through the casing 1125 and into the target volume 1190 within the subterranean formation 1110. The barrier 1139 at the distal (downhole) end of the portion 1135 remains in place to isolate portion 1135 from downhole portions of the horizontal section. The perforations 1631 are arranged equidistantly from each other along the length of the portion 1135, where each pair of adjacent perforations 1631 are separated by distance 1637 (e.g., 24 feet). In this example, the distances 1637 are substantially equal to the distances 1237 (and so also the distances 1137 of FIG. 11).

Also, in this case, the perforations 1631 are located approximately in the middle of adjacent pairs of perforations 1131. For example, perforation 1631-2 is located approximately halfway between perforation 1131-1 (and so also screen out 1633-1) and perforation 1131-2 (and so also screen out 1633-2). As another example, perforation 1631-3 is located approximately halfway between perforation 1131-2 (and so also screen out 1633-2) and perforation 1131-3 (and so also screen out 1633-3). As yet another example, perforation 1631-4 is located approximately halfway between perforation 1131-3 (and so also screen out 1633-3) and perforation 1131-4 (and so also screen out 1633-4).

In step 1085, a fracturing stage is executed at the perforations 731 along the portion 335 of the horizontal section 303 of the wellbore (e.g., wellbore 120). As a result, fracture cluster 832-1 originates from perforation 731-1, fracture cluster 832-2 originates from perforation 731-2, fracture cluster 832-3 originates from perforation 731-3, and fracture cluster 832-4 originates from perforation 731-4. The fracture clusters 832 of the fracturing stage may be executed using a fracturing tool 849 that is positioned within the cavity 371 in the portion 335-1 of the horizontal section 303 and/or is located at the surface (e.g., surface 108). The fracturing tool 849 may be the same as, or different than, the fracturing tool 549 of FIG. 5 above. The fracturing tool 849 may be enabled to execute the fracturing stage by a user 151 and/or a controller 170 using field equipment 109 (e.g., a wireline tool, a bottom hole assembly) known in the art. In some cases, the fracturing tool 849 may be inserted into the cavity 371 of the horizontal section 303 of the wellbore 120 until the fracturing tool 849 is adjacent to the casing 325 within the portion 335-1 of the horizontal section 303.

Part of the fracturing stage that is executed in this step 1085 may also include pumping a fracturing fluid into the cavity 371 of the horizontal section 303 and forcing the fracturing fluid, under pressure, into the fracture clusters 832 within the target volume 390 within the subterranean formation 310. The fracture clusters 832 may be executed substantially simultaneously, iteratively, sequentially, or in some other fashion. FIGS. 17 and 18 show an example of how a fracturing stage is executed according to certain example embodiments. FIG. 17 shows the portion 1135 of the horizontal section of FIG. 16 at a subsequent point in time relative to the time captured in FIG. 16. FIG. 17 shows four fracture clusters 1732 (fracture cluster 1732-1, fracture cluster 1732-2, fracture cluster 1732-3, and fracture cluster 1732-4) have been initially executed coincident with the four perforations 1631 of FIG. 16. As a result, where each pair of adjacent fracture clusters 1732 are separated by distance 1737 as measured from their central vertical axis, where the distance 1737 is substantially the same as the distance 1637 (e.g., 24 feet) in FIG. 16.

These fracture clusters 1732 are relatively small at the point in time shown in FIG. 17. To develop (expand) the fracture clusters 1732, stimulation occurs. In this case, the fracture clusters 1732 are stimulated by injecting a fracturing fluid 1795 (e.g., proppant 112, water, acid) into the cavity 1171 formed by the casing 1125. The pressure of the fracturing fluid 1795 within the cavity 1171 is controlled (e.g., using field equipment 109). For example, when the perforations 1631 are executed (generated) in FIG. 16, the minimum horizontal stress (e.g., as measured by a sensor device 160) may continue to be 4000 psi.

By controlling the pressure of the fracturing fluid 1795 (e.g., 5100 psi) to exceed the minimum horizontal stress, the fracturing fluid 1795 enters through the perforations 1631 to generate and expand the fracture clusters 1732. The fracturing fluid 1795 then flows into and dissipates in the target volume 1190 within the subterranean formation 1110. At the point in time shown in FIG. 17, the pressure within the fracture clusters 1732 (e.g., 4400 psi) is between the pressure within the cavity 1131 (e.g., 5100 psi) and the minimum horizontal stress (e.g., 4000 psi). Also, since the screen outs 1633 remain in place to plug the fracture clusters 1232 at the perforations 1131, the pressure of the fracture clusters 1232 remains unchanged (e.g., 4200 psi) at a level that exceeds the minimum horizontal stress but is less than the pressure of the fracture clusters 1732.

FIG. 18 shows the portion 1135 of the horizontal section of FIG. 17 at a subsequent point in time relative to the time captured in FIG. 17. FIG. 18 shows that the four fracture clusters 1732 (fracture cluster 1732-1, fracture cluster 1732-2, fracture cluster 1732-3, and fracture cluster 1732-4) of FIG. 17 have expanded, which is a result of increasing the pressure of the fracturing fluid 1795 (e.g., from 5100 psi to 5500 psi) pumped into the fracture clusters 1732. When this occurs, the pressure within the fracture clusters 1732 also increases (e.g., from 4400 psi to 4800 psi) but remains between the pressure within the cavity 1131 (e.g., 5500 psi) and the minimum horizontal stress (e.g., 4000 psi). Under the increased pressure, the fracturing fluid 1795 flows further into and dissipates further in the target volume 1190 within the subterranean formation 1110 after traveling through the fracture clusters 1732.

Also, as stated above, since the screen outs 1633 remain in place to plug the fracture clusters 1232 at the perforations 1131, the pressure of the fracture clusters 1232 remains unchanged (e.g., 4200 psi) at a level that exceeds the minimum horizontal stress but is less than the pressure of the fracture clusters 1732. When the fracturing activity of FIGS. 17 and 18 is complete, the net pressure (the closure stress) is slowly dissipated, repeating the process shown in FIG. 15 for the previous fracturing stage. As a result, the four fracture clusters 1732 contract dramatically over some period of time. The fracture clusters 1732 eventually are no longer active, and the pressure within the fracture clusters 1732 (e.g., 4200 psi) is only slightly higher than the minimum horizontal stress (e.g., 4000 psi).

In step 1086, a determination is made as to whether there are one or more adjacent locations along the portion 1135 remaining to develop. In other words, a determination is made as to whether another round of perforating and fracturing needs to be performed on the portion 1135. The determination may be made by a user 151, including an associated user system 155. In addition, or in the alternative, the determination may be made by a controller 170 using one or more protocols, one or more algorithms, a communication module, an application interface, and/or stored data. The determination may be based on an original plan or a modification to an original plan with respect to completing the horizontal section 303 of the wellbore. If there are one or more adjacent locations along the portion 1135 remaining to develop, then the process may revert to step 1083. If there no other adjacent locations along the portion 1135 remaining to develop, then the process proceeds to step 1087.

In step 1087, a determination is made as to whether another portion 1135 of the horizontal section 303 of the wellbore is being developed. In other words, a determination is made as to whether another round of perforating and fracturing needs to be performed on another portion 1135 of the horizontal section 303. The determination may be made by a user 151, including an associated user system 155. In addition, or in the alternative, the determination may be made by a controller 170 using one or more protocols, one or more algorithms, a communication module, an application interface, and/or stored data. The determination may be based on an original plan or a modification to an original plan with respect to completing the horizontal section 303 of the wellbore. If there another portion 1135 of the horizontal section 303 remaining to develop, then the process may revert indirectly to step 1081 or indirectly to step 1081 through optional step 1088. If there no other portions 1135 of the horizontal section 303 remaining to develop, then the process proceeds to the END step.

In optional step 1088, the portion 1135 of the horizontal section (e.g., horizontal section 303) of the wellbore that has just been completed is sealed off from the adjacent portion 1135 of the horizontal section 303 that is about to undergo completion. In some cases, a barrier 1139 or other type of barrier that creates a substantially fluidic seal with the casing 1125 may be used to seal off a completed portion 1135 from a portion 1135 about to undergo completion. An example of this is shown below with respect to FIGS. 26 and 27. The barrier 1139 may be placed within the cavity 1171 inside the casing 1125 using field equipment 109 (e.g., a wireline tool). In such a case, the field equipment 109 may be controlled by a user 151 (including an associated user system 155) and/or a controller 170 using one or more protocols, one or more algorithms, a communication module, an application interface, and/or stored data.

As an alternative to inserting a physical barrier 1139 to seal one portion 1135 of the horizontal section from another before completing the adjacent portion 1135, step 1083 may be performed on the perforations 1631 of the portion 1135 that was just completed (where the final fracturing stage for the portion 1135 has ended). In such a case, when step 1083 is complete, the process may revert to step 1081 to start completing the adjacent portion 1135 of the horizontal section of the wellbore. An example of this alternative embodiment is discussed below with respect to FIGS. 28 through 31.

FIGS. 19 through 31 show schematic drawings of other completion sequences for a horizontal section 1903 of a wellbore according to certain example embodiments. Referring to the description above with respect to FIGS. 1 through 18, FIG. 19 shows a horizontal section 1903 of a wellbore (e.g., similar to the wellbore 120) that has two portions 1935 (portion 1935-1 and portion 1935-2). The portion 1935-1 of the horizontal section 1903 includes four perforations 1931 (perforation 1931-1, perforation 1931-2, perforation 1931-3, and perforation 1931-4) that originate from within the cavity 1971 and extend through the casing 1925 into the target volume 1990 within the subterranean formation 1910. The perforations 1931 are arranged equidistantly from each other along the length of the portion 1935-1, where each pair of adjacent perforations 1931 are separated by distance 1937 (e.g., 24 feet). Portion 1935-2 has no perforations, fracture clusters, or other features at this time.

FIG. 20 shows the horizontal section 1903 of FIG. 19 at a subsequent time relative to the time captured in FIG. 19. In this case, FIG. 20 shows four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910. At this point in time, the fracture clusters 2032 have already been executed using a gradual increase and subsequent decrease in the flow rate/pressure of fracturing fluid, similar to what was described above with respect to FIGS. 12 through 15. The fracture clusters 2032 of FIG. 20 are no longer active, and the pressure within the fracture clusters 1232 (e.g., 4200 psi) is only slightly higher than the minimum horizontal stress (e.g., 4000 psi). The fracture clusters 2032 are evenly spaced with respect to each other, where adjacent fracture clusters 2032 are separated from each other by a distance 2037 (e.g., 24 feet). Portion 1935-2 continues to have no perforations, fracture clusters, or other features at this time. In some cases, the cavity 1971 may be overflushed to help ensure that the cavity 1971 is relatively clean and free of debris.

FIG. 21 shows the horizontal section 1903 of FIG. 20 at a subsequent time relative to the time captured in FIG. 20. In this case, FIG. 21 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive. While portion 1935-2 continues to have no perforations, fracture clusters, or other features, a bottom hole assembly that includes a perforating tool 2148 is inserted into the cavity 1971 formed by the casing 1925 within portion 1935-2.

FIG. 22 shows the horizontal section 1903 of FIG. 21 at a subsequent time relative to the time captured in FIG. 21. In this case, FIG. 22 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive.

Portion 1935-2 continues to have no perforations, fracture clusters, or other features, and the bottom hole assembly that includes a perforating tool 2148 remains in the cavity 1971 formed by the casing 1925 within portion 1935-2. In addition, four screen outs 2233 have been executed (e.g., released from the surface 108, released from a tool in the bottom hole assembly) to plug the perforations 1931 in portion 1935-1 as set forth in step 1083 of FIG. 10 above. Specifically, screen out 2233-1 plugs perforation 1931-1, screen out 2233-2 plugs perforation 1931-2, screen out 2233-3 plugs perforation 1931-3, and screen out 2233-4 plugs perforation 1931-4.

FIG. 23 shows the horizontal section 1903 of FIG. 22 at a subsequent time relative to the time captured in FIG. 22. In this case, FIG. 23 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive. In addition, the four screen outs 2233 (screen out 2233-1, screen out 2233-2, screen out 2233-3, and screen out 2233-4) continue to plug their respective perforations 1931 in portion 1935-1. Portion 1935-2 continues to have no perforations, fracture clusters, or other features, and the bottom hole assembly that includes a perforating tool 2148 is moved within the cavity 1971 formed by the casing 1925 portion 1935-1 in preparation of executing additional perforations in portion 1935-1.

FIG. 24 shows the horizontal section 1903 of FIG. 23 at a subsequent time relative to the time captured in FIG. 23. In this case, FIG. 24 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive. In addition, the four screen outs 2233 (screen out 2233-1, screen out 2233-2, screen out 2233-3, and screen out 2233-4) continue to plug their respective perforations 1931 in portion 1935-1. Portion 1935-2 continues to have no perforations, fracture clusters, or other features.

The perforating tool 2148 of the bottom hole assembly, positioned in the cavity 1971 in portion 1935-1, has executed four additional perforations 2431 (perforation 2431-1, perforation 2431-2, perforation 2431-3, and perforation 2431-4) that extend through the casing 1925 into the target volume 1990 within the subterranean formation 1910. The perforations 2431 are arranged equidistantly from each other along the length of the portion 1935-1, where each pair of adjacent perforations 2431 are separated by a distance 2437 (e.g., 24 feet). In this case, the perforations 2431 are positioned substantially halfway between the adjacent perforations 1931, and so the distances 2437 are substantially the same as the distances 1937.

FIG. 25 shows the horizontal section 1903 of FIG. 24 at a subsequent time relative to the time captured in FIG. 24. In this case, FIG. 25 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive. In addition, the four screen outs 2233 (screen out 2233-1, screen out 2233-2, screen out 2233-3, and screen out 2233-4) continue to plug their respective perforations 1931 in portion 1935-1. Portion 1935-2 continues to have no perforations, fracture clusters, or other features, and the bottom hole assembly that includes the perforating tool 2148 has been removed from the cavity 1971.

In addition, four fracture clusters 2532 (fracture cluster 2532-1 originating from perforation 2431-1, fracture cluster 2532-2 originating from perforation 2431-2, fracture cluster 2532-3 originating from perforation 2431-3, and fracture cluster 2532-4 originating from perforation 2431-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910. At this point in time, the fracture clusters 2532 have already been executed using a gradual increase and subsequent decrease in the flow rate/pressure of fracturing fluid, similar to what was described above with respect to FIGS. 12 through 15. Adjacent fracture clusters 2532 are separated from each other by a distance 2537 that is substantially the same as the distance 2037 between adjacent fracture clusters 2032.

FIG. 26 shows the horizontal section 1903 of FIG. 25 at a subsequent time relative to the time captured in FIG. 25. In this case, FIG. 26 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) and the four fracture clusters 2532 (fracture cluster 2532-1 originating from perforation 2431-1, fracture cluster 2532-2 originating from perforation 2431-2, fracture cluster 2532-3 originating from perforation 2431-3, and fracture cluster 2532-4 originating from perforation 2431-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 are inactive.

In addition, the four screen outs 2233 (screen out 2233-1, screen out 2233-2, screen out 2233-3, and screen out 2233-4) continue to plug their respective perforations 1931 in portion 1935-1. Further, the four perforations 2431 remain unplugged by screen outs. A barrier 2639 has been installed within the cavity 1971 just uphole from perforation 2431-1 in a manner discussed in step 1088 of FIG. 10 above. The barrier 2639 divides portion 1935-1 and portion 1935-2. Further, four perforations 2631 (perforation 2431-1, perforation 2431-2, perforation 2431-3, and perforation 2431-4) have been executed in portion 1935-2. Each perforation 2431 extends through the casing 1925 into the target volume 1990 within the subterranean formation 1910. The perforations 2631 are arranged equidistantly from each other along the length of the portion 1935-2, where each pair of adjacent perforations 2631 are separated by a distance 2637 (e.g., 24 feet).

FIG. 27 shows the horizontal section 1903 of FIG. 26 at a subsequent time relative to the time captured in FIG. 26. In this case, FIG. 27 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) and the four fracture clusters 2532 (fracture cluster 2532-1 originating from perforation 2431-1, fracture cluster 2532-2 originating from perforation 2431-2, fracture cluster 2532-3 originating from perforation 2431-3, and fracture cluster 2532-4 originating from perforation 2431-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 are inactive.

In addition, portion 1935-2 is now fully completed. Specifically, four fracture clusters 2732 (fracture cluster 2732-1 originating from perforation 2631-1, fracture cluster 2732-2 originating from perforation 2631-2, fracture cluster 2732-3 originating from perforation 2631-3, and fracture cluster 2732-4 originating from perforation 2631-4) have been fully executed, and the four perforations 2631 have been plugged with four screen outs 2733 (screen out 2733-1 plugs perforation 2631-1, screen out 2733-2 plugs perforation 2631-2, screen out 2733-3 plugs perforation 2631-3, and screen out 2733-4 plugs perforation 2631-4). Each pair of adjacent fracture clusters 2732 are separated by a distance 2737 (e.g., 24 feet).

Further, four additional perforations 3731 have been executed in portion 1935-2, and four fracture clusters 3732 (fracture cluster 3732-1 originating from perforation 3731-1, fracture cluster 3732-2 originating from perforation 3731-2, fracture cluster 3732-3 originating from perforation 3731-3, and fracture cluster 3732-4 originating from perforation 3731-4) of portion 1935-2 have been executed to extend into the target volume 1990 within the subterranean formation 1910. The perforations 3731 are unplugged by screen outs. Each pair of adjacent fracture clusters 2732 are separated by a distance 2737 (e.g., 24 feet), and each pair of adjacent fracture clusters 3732 are separated by a distance 3737 that is substantially the same as the distance 2737.

As discussed above with respect to FIG. 10, transitioning from completing one portion of a horizontal section of a wellbore to another portion may be performed without a barrier (e.g., barrier 2639). FIGS. 28 through 31 show an example of such an alternative. Resuming from the horizontal section 1903 shown in FIG. 25 above, FIG. 28 shows a subsequent point in time from what is shown in FIG. 25. Specifically, FIG. 28 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive, and the perforations 1931 remain plugged by the four screen outs 2233 (screen out 2233-1, screen out 2233-2, screen out 2233-3, and screen out 2233-4).

In addition, the four fracture clusters 2532 (fracture cluster 2532-1 originating from perforation 2431-1, fracture cluster 2532-2 originating from perforation 2431-2, fracture cluster 2532-3 originating from perforation 2431-3, and fracture cluster 2532-4 originating from perforation 2431-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 are unplugged by screen outs. Portion 1935-2 continues to have no perforations, fracture clusters, or other features, but a new bottom hole assembly that includes a perforating tool 2848 has been positioned within the cavity 1971 in portion 1935-2.

FIG. 29 shows the horizontal section 1903 of FIG. 28 at a subsequent time relative to the time captured in FIG. 28. In this case, FIG. 29 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive, and the perforations 1931 remain plugged by the four screen outs 2233 (screen out 2233-1, screen out 2233-2, screen out 2233-3, and screen out 2233-4).

In addition, the four fracture clusters 2532 (fracture cluster 2532-1 originating from perforation 2431-1, fracture cluster 2532-2 originating from perforation 2431-2, fracture cluster 2532-3 originating from perforation 2431-3, and fracture cluster 2532-4 originating from perforation 2431-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 are now inactive and plugged by four screen outs (screen out 2933-1, screen out 2933-2, screen out 2933-3, and screen out 2933-4). Plugging all of the fracture clusters in portion 1935-1 with screen outs becomes an alternative to installing a barrier (e.g., barrier 2639) to separate portion 1935-1 and portion 1935-2 from each other. Portion 1935-2 continues to have no perforations, fracture clusters, or other features, and the bottom hole assembly that includes a perforating tool 2848 remains positioned within the cavity 1971 in portion 1935-2.

FIG. 30 shows the horizontal section 1903 of FIG. 29 at a subsequent time relative to the time captured in FIG. 29. In this case, FIG. 30 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive, and the perforations 1931 remain plugged by the four screen outs 2233 (screen out 2233-1, screen out 2233-2, screen out 2233-3, and screen out 2233-4).

In addition, the four fracture clusters 2532 (fracture cluster 2532-1 originating from perforation 2431-1, fracture cluster 2532-2 originating from perforation 2431-2, fracture cluster 2532-3 originating from perforation 2431-3, and fracture cluster 2532-4 originating from perforation 2431-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive and plugged by four screen outs (screen out 2933-1, screen out 2933-2, screen out 2933-3, and screen out 2933-4).

Further, four perforations 3031 (perforation 3031-1, perforation 3031-2, perforation 3031-3, and perforation 3031-4) have been executed in portion 1935-2. Each perforation 3031 extends through the casing 1925 into the target volume 1990 within the subterranean formation 1910. The perforations 3031 are arranged equidistantly from each other along the length of the portion 1935-2, where each pair of adjacent perforations 3031 are separated by a distance 3037 (e.g., 24 feet). The bottom hole assembly that includes a perforating tool 2848 has been removed from the cavity 1971.

FIG. 31 shows the horizontal section 1903 of FIG. 30 at a subsequent time relative to the time captured in FIG. 30. In this case, FIG. 31 shows that the four fracture clusters 2032 (fracture cluster 2032-1 originating from perforation 1931-1, fracture cluster 2032-2 originating from perforation 1931-2, fracture cluster 2032-3 originating from perforation 1931-3, and fracture cluster 2032-4 originating from perforation 1931-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive, and the perforations 1931 remain plugged by the four screen outs 2233 (screen out 2233-1, screen out 2233-2, screen out 2233-3, and screen out 2233-4).

In addition, the four fracture clusters 2532 (fracture cluster 2532-1 originating from perforation 2431-1, fracture cluster 2532-2 originating from perforation 2431-2, fracture cluster 2532-3 originating from perforation 2431-3, and fracture cluster 2532-4 originating from perforation 2431-4) of portion 1935-1 extending into the target volume 1990 within the subterranean formation 1910 remain inactive and plugged by four screen outs (screen out 2933-1, screen out 2933-2, screen out 2933-3, and screen out 2933-4).

In addition, portion 1935-2 is now fully completed. Specifically, four fracture clusters 3132 (fracture cluster 3132-1 originating from perforation 3031-1, fracture cluster 3132-2 originating from perforation 3031-2, fracture cluster 3132-3 originating from perforation 3031-3, and fracture cluster 3132-4 originating from perforation 3031-4) have been fully executed, and the four perforations 3031 have been plugged with four screen outs 3133 (screen out 3133-1 plugs perforation 3031-1, screen out 3133-2 plugs perforation 3031-2, screen out 3133-3 plugs perforation 3031-3, and screen out 3133-4 plugs perforation 3031-4). Each pair of adjacent fracture clusters 3132 are separated by a distance 3137 (e.g., 24 feet).

Further, four additional perforations 4131 have been executed in portion 1935-2, and four fracture clusters 4132 (fracture cluster 4132-1 originating from perforation 4131-1, fracture cluster 4132-2 originating from perforation 4131-2, fracture cluster 4132-3 originating from perforation 4131-3, and fracture cluster 4132-4 originating from perforation 4131-4) of portion 1935-2 have been executed to extend into the target volume 1990 within the subterranean formation 1910. Each pair of adjacent fracture clusters 4131 are separated by a distance 4137 (e.g., 24 feet) that is substantially the same as the distance 3137. The perforations 4131 are plugged by four screen outs 4133 (screen out 4133-1, screen out 4133-2, screen out 4133-3, and screen out 4133-4). This allows another portion of the horizontal section 1903 to be completed without the use of a barrier (e.g., barrier 2639).

As discussed above, a completion design for a portion of a horizontal section of a wellbore may have any number of multiple stages, forming any pattern, spacing, and other characteristics. FIGS. 32 through 35 show schematic views of various example completion sequences for a portion of a horizontal section of a wellbore according to certain example embodiments. Referring to the description above with respect to FIGS. 1 through 31, FIG. 32 shows a schematic view of a portion 3235 of a horizontal section of a wellbore that has three fracturing stages in its completion cycle. The first stage is designated by the letter “A” and includes 6 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532). The second stage is designated by the letter “B” and includes 5 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532), where each “B” grouping is located approximately ⅓ between adjacent “A” groupings. The third stage is designated by the letter “C” and includes 5 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532), where each “C” grouping is located approximately halfway between “A” and “B” groupings. At the end of the completion design for the portion 3235, each pair of adjacent groupings is separated approximately by a distance 3237.

FIG. 33 shows a schematic view of a portion 3335 of a horizontal section of a wellbore that has two fracturing stages in its completion cycle. The first stage is designated by the letter “A” and includes 6 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532). The second stage is designated by the letter “B” and includes 5 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532), where each “B” grouping is located approximately ⅓ between adjacent “A” groupings. At the end of the completion design for the portion 3335, each “A” to “B” pair of adjacent groupings is separated approximately by a distance 3337-1, and each “B” to “A” pair of adjacent groupings is separated approximately by a distance 3337-2.

FIG. 34 shows a schematic view of a portion 3435 of a horizontal section of a wellbore that has four fracturing stages in its completion cycle. The first stage is designated by the letter “A” and includes 5 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532). The second stage is designated by the letter “B” and includes 4 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532), where each “B” grouping is located approximately halfway between adjacent “A” groupings. The third stage is designated by the letter “C” and includes 4 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532), where each “C” grouping is located approximately halfway between “A” to “B” groupings. The fourth stage is designated by the letter “D” and includes 4 equally spaced perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532), where each “C” grouping is located approximately halfway between “B” to “A” groupings. At the end of the completion design for the portion 3435, each pair of adjacent groupings is separated approximately by a distance 3437.

FIG. 35 shows a schematic view of a portion 3535 of a horizontal section of a wellbore that has three fracturing stages in its completion cycle. The first stage is designated by the letter “A” and includes 5 perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532). In this case, four of the “A” perforations toward the distal end of the horizontal section are substantially equally spaced, separated from each other by a distance 5137, while the most proximal “A” perforation is separated from the second “A” perforation by a distance 5037 that is greater (e.g., two times) than the distance 5137. Essentially, the approximate midpoint between the first and second “A” perforations (location P1) has a fault or some other issue within the formation, and performing a perforation at that location P1 may have a negative effect. As a result, the first stage is designed to avoid perforating at location P1

The second stage is designated by the letter “B” and includes 4 perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532). In this case, three of the “B” perforations toward the proximal end of the horizontal section are substantially equally spaced, separated from each other by the distance 5137, while the most distal “B” perforation is separated from the third “B” perforation by the distance 5037 that is greater (e.g., two times) than the distance 5137. Essentially, the approximate midpoint between the third and fourth “B” perforations (location P2) has a fault or some other issue within the formation, and performing a perforation at that location P2 may have a negative effect. As a result, the second stage is designed to avoid perforating at location P2 The second stage is unaffected by the issue at location P1, just as the first stage is unaffected by the issue at location P2. Except for the gap allowed for locations P1 and P2, each “B” grouping is located approximately ⅓ between adjacent “A” groupings.

The third stage is designated by the letter “C” and includes 4 perforations (e.g., perforations 431) and subsequent fracture clusters (e.g., fracture clusters 532). In this case, three of the “C” perforations toward the proximal end of the horizontal section are substantially equally spaced, separated from each other by the distance 5137, while the most distal “C” perforation is separated from the third “C” perforation by the distance 5037 that is greater (e.g., two times) than the distance 5137. Essentially, the approximate midpoint between the third and fourth “C” perforations (location P2) has a fault or some other issue within the formation, and performing a perforation at that location P2 may have a negative effect. As a result, the third stage is designed to avoid perforating at location P2 The third stage is unaffected by the issue at location P1. Except for the gap allowed for locations P1 and P2, each “C” grouping is located approximately halfway between “A” and “B” groupings.

Example embodiments may be used to provide systems and methods for implementing a completion design for a horizontal section of a wellbore. Example embodiments result in higher production rates and yield of subterranean resources from a subterranean formation. Example embodiments may be implemented with any type of subterranean formation, including shale, tight formations, and other types of unconventional formations. Example embodiments may be used with active production wellbores or with previously abandoned wellbores. Example embodiments may provide a number of benefits. Such benefits may include, but are not limited to, more reliable field operations, case of use, reduced downtime, increased flexibility, configurability, and compliance with applicable industry standards and regulations.

Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein.