DOWNHOLE DEVICES FOR PROVIDING SEALING COMPONENTS WITHIN A WELLBORE, WELLS THAT INCLUDE SUCH DOWNHOLE DEVICES, AND METHODS OF UTILIZING THE SAME

Abstract

Downhole devices, wells that include the downhole devices, and methods of utilizing the same are disclosed herein. The downhole devices include a core; a sealing component holder positioned within the core including an opening to an external surface of the core; a plurality of sealing components positioned within the sealing component holder; a metering device; and a cover positioned over the opening. The metering device is constructed and arranged to displace an internal volume of the sealing component holder and discharge through the opening a portion of the plurality of sealing components contained within the sealing component holder. The cover is constructed and arranged to allow the portion of the sealing components to exit the opening upon displacement of the internal volume of the sealing component holder.

Description

FIELD OF THE DISCLOSURE

The present disclosure is directed to downhole devices for providing sealing components proximal a section of the well to be sealed, to wells that include such downhole devices, and to methods of utilizing such downhole devices and/or wells.

BACKGROUND OF THE DISCLOSURE

Hydrocarbon wells generally include a wellbore that extends from a surface region through a subterranean formation to a reservoir within the subterranean formation containing reservoir fluid, such as liquid and/or gaseous hydrocarbons. Often, it may be desirable to stimulate the subterranean formation to enhance production of the reservoir fluid therefrom. Stimulation of the subterranean formation may be accomplished in a variety of ways and generally includes supplying a stimulant fluid to the subterranean formation to increase reservoir contact. As an example, the stimulation may include supplying an acid as the stimulant fluid to the subterranean formation to acid-treat the subterranean formation to dissolve at least a portion of the subterranean formation and/or remove cement materials placed between the casing tubular conduit and the subterranean formation. As another example, the stimulation may include fracturing the subterranean formation, such as by supplying a fracturing fluid as the stimulant fluid, which is pumped at a high pressure, into the subterranean formation. The fracturing fluid may include particulate material, such as a proppant, which may at least partially fill fractures that are generated during the fracturing, thereby facilitating fluid flow within the fractures after supply of the fracturing fluid has ceased.

A variety of systems and methods have been developed to facilitate stimulation of subterranean formations. Such systems and methods utilize a shape-charge perforation gun to create perforations within a section of the tubular casing string extending within the wellbore, and the stimulant fluid then is provided to the subterranean formation via the perforations. Once stimulation is complete in the particular region of the subterranean formation proximal to the perforated section of the tubular casing string, ball sealers are introduced into the perforated section of the tubular casing string to seal the perforations and an additional section of the tubular casing string is perforated proximal an additional region of the subterranean formation to stimulate the additional region of the subterranean formation. This process is repeated until stimulation of the subterranean formation is complete.

With respect to sealing the perforations after stimulation within a region is complete, ball sealers may be introduced from the surface region via a ball injector, transported down into the tubular casing string via a high velocity carrier fluid having a suitable density, and allowed to engage with the perforations within the section. However, the flow profile in the tubular casing string, changing pump rates, and the fluid properties of the high velocity carrier fluid tend to distribute the ball sealers along the axial length of the tubular casing string and, thus, delivers the ball sealers at the desired location within the tubular casing string at different times. Ball sealers can sometimes be distributed within as much as ten percent (10%) of the calculated arrival volume of the wellbore fluid and, thus, arrive at the desired location either too early or too late.

Alternatively, the ball sealers may be introduced locally to the section of the tubular casing string to be sealed. U.S. Patent Application Publication No. 2016/0168962 to Tolman et al. is directed to multizone fracture stimulation of a reservoir which utilizes a plurality of perforation gun assemblies made of a friable material. A first perforation gun assembly is deployed into the wellbore to perforate a first selected zone of interest. A second perforating gun assembly is subsequently deployed into the wellbore to perforate a second selected zone of interest; however, the second perforating gun assembly additionally includes a ball container including a sufficient amount of ball sealers to seal the perforations of the first selected zone of interest. The ball sealers may be released from the ball container prior to or simultaneously with the firing of the second perforating gun assembly. A single container containing an amount of ball sealers to seal only the first selected zone of interest is used because the friable perforating gun assemblies are destroyed upon firing the explosive shape-charges contained therein.

U.S. Pat. No. 8,561,696 to Trummer et al. is also directed to multizone fracture stimulation of a reservoir which either utilizes tags within the ball sealers or high velocity carrier fluid to determine the location of the ball sealers as they are transported from the surface to the desired section of the well or containers positioned locally within the well at axially spaced apart locations to release the ball sealers contained therein to seal perforations within a desired section of the well. The containers may be coupled to the tubular casing string or may be provided with the perforating gun assembly below an associated perforating gun section on the assembly. Each container is configured for a single release of ball sealers, therefore, only an amount of ball sealers required to seal perforations within a particular perforated zone are included within a container. When the containers are included within the perforating gun assembly, a container located below the fired perforating gun section and/or the connections thereto will be destroyed upon firing. Further, when containers are coupled to the tubular casing string, the placement of such containers must be determined prior to coupling to the tubular casing string limiting the flexibility in deployment of the ball sealers.

Such methods of introducing ball sealers to seal perforations of multiple, axially spaced-apart sections of the tubular casing string introduce ball sealers from the surface or use multiple local sources of ball sealers to separately seal each particular perforated zone and do not provide an individual local source capable of delivering ball sealers to perforations within multiple, axially spaced-apart sections of the tubular casing string at different time periods.

Thus, there exists a desire to provide a downhole device to deliver specific and varying amounts of sealing components, as needed during operations, into multiple, axially spaced-apart sections of a well from a single local source capable of being positioned at variable depths within a wellbore providing variable depth control.

SUMMARY OF THE DISCLOSURE

Downhole devices, wells that include the downhole devices, and methods of utilizing the same are disclosed herein. The downhole devices are configured to provide sealing components within a well to a plurality of axially spaced-apart sections of the well. The downhole devices include a core, a sealing component holder, a plurality of sealing components, a metering device, and a cover. The sealing component holder is positioned within the core and includes an opening to an external surface of the core. The plurality of sealing components are positioned within the sealing component holder. The metering device is constructed and arranged to displace an internal volume of the sealing component holder and discharge through the opening a portion of the plurality of sealing components contained within the sealing component holder. The cover is positioned over the opening and constructed and arranged to allow the portion of the sealing components to exit the opening upon displacement of the internal volume of the sealing component holder.

As an example, the downhole device may be a shockwave generation device additionally configured to generate a shockwave within a wellbore fluid that extends within a tubular conduit of a wellbore tubular. The shockwave generation devices may additionally include a plurality of explosive charges arranged on an external surface of the core and a plurality of triggering devices. Each of the plurality of triggering devices is associated with a selected portion of the plurality of explosive charges and is configured to selectively initiate explosion of the selected portion of the plurality of explosive charges.

Also described in the present disclosure are methods for providing sealing components within a well. The well includes a wellbore and a wellbore tubular extending within the wellbore, the wellbore tubular defining a tubular conduit. The method includes positioning a downhole device proximal to or within a first region within the tubular conduit radially interior of a first section of the wellbore tubular. The downhole device includes a core, a sealing component holder, a plurality of sealing components, a metering device, and a cover. The sealing component holder is positioned within the core and includes an opening to an external surface of the core. The plurality of sealing components are positioned within the sealing component holder. The metering device is constructed and arranged to displace an internal volume of the sealing component holder and discharge through the opening a portion of the plurality of sealing components contained within the sealing component holder. The cover is positioned over the opening and constructed and arranged to allow the portion of the sealing components to exit the opening upon displacement of the internal volume of the sealing component holder. The method also includes actuating the metering device to displace a first internal volume of the sealing component holder to discharge a first portion of the plurality of sealing components through the opening into the tubular conduit; positioning the downhole device proximal to or within a second region within the tubular conduit radially interior of a second section of the wellbore tubular, the second region spaced apart from the first region along the length of the wellbore tubular; and actuating the metering device to displace a second internal volume of the sealing component holder to discharge a second portion of the plurality of sealing components through the opening into the tubular conduit.

As an example, the methods may additionally include positioning the downhole device, such as a shockwave generation device, within the first region of the tubular conduit and actuating a first triggering device. The first triggering device initiates explosion of a first explosive charge and generates a first shockwave within the first region of the tubular conduit. The first shockwave causes one or more selective stimulation ports (SSPs) present in the wellbore tubular to transition from a closed state to an open state. The methods may further include positioning the shockwave generation device within the second region of the tubular conduit and actuating a second triggering device simultaneously with or subsequently to the first region of the tubular conduit being sealed. The second triggering device initiates explosion of a second explosive charge and generates a second shockwave within the second region of the tubular conduit. The second shockwave causes one or more SSPs present in the wellbore tubular to transition from a closed state to an open state. Once an SSP is opened by a shockwave from the shockwave generation device, the SSPs may permit fluid flow between the wellbore tubular and the subterranean formation until subsequently sealed with sealing components.

Also described herein are wells including such downhole devices; methods for fracturing a subterranean formation which includes the methods for providing sealing components within a hydrocarbon well; and methods for diverting injection fluid within an injection well which includes the methods for providing sealing components within the injection well.

BRIEF DESCRIPTION OF THE DRAWINGS

While the present disclosure is susceptible to various modifications and alternative forms, specific exemplary implementations thereof have been shown in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific exemplary implementations is not intended to limit the disclosure to the particular forms disclosed herein. This disclosure is to cover all modifications and equivalents as defined by the appended claims. It should also be understood that the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating principles of exemplary embodiments of the present disclosure. Moreover, certain dimensions may be exaggerated to help visually convey such principles. Further where considered appropriate, reference numerals may be repeated among the drawings to indicate corresponding or analogous elements. Moreover, two or more blocks or elements depicted as distinct or separate in the drawings may be combined into a single functional block or element and blocks or elements may be arranged in any suitable manner. Similarly, a single block or element illustrated in the drawings may be implemented as multiple steps or by multiple elements in cooperation and may be implemented in any suitable order or sequence.

FIG. 1 is a schematic representation of a side (axial cross-sectional) view of a hydrocarbon well that may include and/or utilize a downhole device according to the present disclosure.

FIG. 2 is a schematic representation of a side (axial cross-sectional) view of a downhole device according to the present disclosure.

FIG. 3 is a more detailed but still schematic representation of a front view of a cover for the downhole device of FIG. 2.

FIG. 4 is a more detailed but still schematic representation of a front view of a cover for the downhole device according to the present disclosure.

FIG. 5 is a more detailed but still schematic representation of a front view of a cover for the downhole device of FIG. 2.

FIG. 6 is a more detailed but still schematic representation of a front view of a cover for the downhole device of FIG. 2.

FIG. 7 is schematic representation of a partial side (axial cross-sectional) view of a downhole device.

FIG. 8 is a schematic representation of a partial side (axial cross-sectional) view of a downhole device according to the present disclosure.

FIG. 9 is a schematic representation of a partial side (axial cross-sectional) view of a downhole device according to the present disclosure.

FIG. 10 is a schematic representation of a partial side (axial cross-sectional) view of a downhole device according to the present disclosure.

FIG. 11 is a schematic representation of a partial side (axial cross-sectional) view of a downhole device according to the present disclosure.

FIG. 12 is a schematic representation of a side (axial cross-sectional) view of a hydrocarbon well that may include and/or utilize a shockwave generation device according to the present disclosure.

FIG. 13 is a schematic representation of a side (axial cross-sectional) view of a shockwave generation device according to the present disclosure.

FIG. 14 is a more detailed but still schematic representation of a side (axial cross-sectional) view of a selective stimulation port according to the present disclosure.

FIG. 15 is a more detailed but still schematic representation of a side view of a portion of the shockwave generation device of FIG. 13.

FIG. 16 is a less detailed schematic side view of a shockwave generation device according to the present disclosure.

FIG. 17 is a transverse (radial cross-sectional) view of a shockwave generation device showing examples of flutes and protective barriers that may be included in shockwave generation device according to the present disclosure.

FIG. 18 is a less detailed schematic side view of a shockwave generation device according to the present disclosure.

FIG. 19 is a transverse (radial cross-sectional) view of the shockwave generation device of FIG. 18 taken along line 7-7 of FIG. 18.

FIG. 20 illustrates examples of various transverse (radial cross-sectional) views of shapes for flutes that may be defined by a core of a shockwave generation device according to the present disclosure.

FIG. 21 is a flowchart depicting a method, according to the present disclosure, of metering sealing components within a tubular conduit.

FIG. 22 is a schematic side (axial cross-sectional) view of a portion of a process flow for generating a plurality of shockwaves within a subterranean formation.

FIG. 23 is a schematic side (axial cross-sectional) view of a portion of a process flow for generating a plurality of shockwaves within a subterranean formation.

FIG. 24 is a schematic side (axial cross-sectional) view of a portion of a process flow for generating a plurality of shockwaves within a subterranean formation.

FIG. 25 is a schematic side (axial cross-sectional) view of a portion of a process flow for generating a plurality of shockwaves within a subterranean formation.

FIG. 26 is a schematic side (axial cross-sectional) view of a portion of a process flow for generating a plurality of shockwaves within a subterranean formation.

FIG. 27 is a schematic side (axial cross-sectional) view of a portion of a process flow for generating a plurality of shockwaves within a subterranean formation.

FIG. 28 is a schematic side (axial cross-sectional) view of a portion of a process flow for generating a plurality of shockwaves within a subterranean formation.

FIG. 29 is a flowchart depicting a method, according to the present disclosure, of metering sealing components within a tubular conduit.

FIG. 30 is a schematic side (axial cross-sectional) view of a portion of a process flow for metering sealing components within a tubular conduit during refracturing operations.

FIG. 31 is a flowchart depicting a method, according to the present disclosure, of metering sealing components within a tubular conduit of an injection well.

FIG. 32 is a schematic side (axial cross-sectional) view of a portion of a process flow for metering sealing components within a tubular conduit during injection operations.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

The present disclosure is directed to a downhole device constructed and arranged to provide multiple, metered amounts of sealing components (sealing devices) from an individual sealing component holder contained within the downhole device. The metered amounts of sealing components are discharged from the downhole device proximal the section of the wellbore tubular or subterranean formation to be sealed. Such a downhole device releases the sealing components locally over a short period of time which provides the sealing components to the targeted section of the wellbore tubular in a concentrated manner. As discussed above, releasing sealing components into the wellbore tubular from the surface results in the axial distribution or dispersion of the sealing components within the carrier fluid used to transport the sealing components to the targeted section of the wellbore tubular. Distribution or dispersion of the sealing components occurs due to the flow profile within the wellbore tubular and the fluid properties of the carrier fluid. Further, in order to minimize or prevent contact of the sealing components with stimulant fluid or fracturing fluid traveling ahead of the carrier fluid while the sealing components are transported to the target section of the wellbore tubular, a significant amount of carrier fluid is introduced into the wellbore prior to the release of the sealing components from the surface. The introduction of the excess carrier fluid can lead to over displacement of proppant in the fracture which can in turn negatively affect well performance.

As discussed above, including a container within a perforation gun can limit the ability to use an individual source of ball sealers to provide multiple, metered amounts of ball sealers to perforations within multiple, axially spaced-apart sections of the tubular casing string at different time periods. This results from the fact that the area near the detonated portion of the perforation gun and below, including any container and connections thereto, is significantly damaged upon firing of the shape-charges. The downhole device of the present disclosure overcomes such limitations and provides the ability to locally release multiple, metered amounts of sealing components from an individual sealing component holder within the downhole device which can provide the sealing component to the target section of the wellbore tubular in a concentrated manner without significant axial displacement or dispersion, eliminate introducing excess stimulant fluid or fracturing fluid into the fracture, allow the use of sealing components that are oversized or undersized, provide multiple, precise placements of the sealing components contained within a sealing component holder of a downhole device in a single trip downhole, precise placement of multiple portions of a plurality of sealing components contained within a sealing component holder wherein the portions of sealing components can have different properties or different amounts, and/or provide sealing components that may be oversized or undersized.

Elements that serve a similar, or at least substantially similar, purpose may be labeled with like numbers in each of FIGS. 1-32, and these elements may not be discussed in detail herein with reference to each of FIGS. 1-32. Similarly, all elements may not be labeled in each of FIGS. 1-32, but reference numerals associated therewith may be utilized herein for consistency. Elements, components, and/or features that are discussed herein with reference to one or more of FIGS. 1-32 may be included in and/or utilized with any of FIGS. 1-32 without departing from the scope of the present disclosure. In general, elements that are likely to be included in a particular embodiment are illustrated in solid lines, while elements that are optional may be illustrated in dashed lines. However, elements that are shown in solid lines may not be essential and, in some embodiments, may be omitted without departing from the scope of the present disclosure.

FIG. 1 is a schematic representation of a hydrocarbon well 10 that may include and/or utilize a downhole device 190 according to the present disclosure. Hydrocarbon well 10 may include a wellbore 20 that extends from a surface region 30 to subterranean formation 34 through subsurface region 32. Subterranean formation 34 includes a reservoir fluid 36, such as a liquid hydrocarbon and/or a gaseous hydrocarbon, and hydrocarbon well 10 may be utilized to produce, pump, and/or convey the reservoir fluid 36 from the subterranean formation 34 to the surface region 30. Wellbore 20 may include a vertical section 20A, as illustrated in FIG. 1. Wellbore 20 may also include a horizontal section 20B. Wellbore 20 may also include a deviated section 20C located between vertical section 20A and horizontal section 20B. Hydrocarbon well 10 may further include wellbore tubular 40, which extends within wellbore 20 and defines a tubular conduit 42. Wellbore fluid 22 extends within the tubular conduit 42.

As shown in FIG. 1, downhole device 190 may be an umbilical-attached downhole device 190 that may be operatively attached to and may be positioned within tubular conduit 42 via, an umbilical 192, such as a wireline, a tether, tubing, jointed tubing, and/or coiled tubing. The umbilical 192 may permit and/or facilitate positioning of the downhole device 190 within the tubular conduit 42 and/or may permit and/or facilitate communication with and/or power to the downhole device 190 from surface region 30. Umbilical 192 may convey one or more status signals from downhole device 190 to a control system (not shown) located at surface region 30 and/or may convey one or more control signals from the control system located at surface region 30 to downhole device 190. Such an umbilical-attached downhole device 190 may include an anchor 193 that may be configured to receive and/or to be operatively attached to the umbilical 192, as illustrated in FIG. 2.

As another example, the downhole device 190 may be an autonomous downhole device that may be flowed into and/or within tubular conduit 42 without an attached umbilical. When downhole device 190 is an autonomous downhole device, hydrocarbon well 10 may further include a wireless downhole communication network 39, which may be configured to wirelessly communicate with the downhole device 190, such as to convey one or more status signals from the downhole device 190 to a control system located at surface region 30 and/or to convey one or more control signals from the control system located at surface region 30 to the downhole device 190. One or more batteries may be included within the autonomous downhole device to provide electrical power to the components of the downhole device 190.

FIG. 2 is a schematic representation of a downhole device 190 according to the present disclosure. Downhole device 190 includes a core 102, a sealing component holder 180, sealing components 182, and a metering device 186. The sealing components 182 are positioned within the sealing component holder 180. Member 184 may also be positioned within the interior of the sealing component holder 180. Sealing component holder 180 includes an opening 189 which is configured, shaped and sized such that the sealing components contained therein may be released from the interior of the sealing component holder 180 upon displacement of an internal volume of the sealing component holder 180. A cover 187 is positioned over opening 189.

The core of the downhole device may include any suitable structure and/or material that may have, form, and/or define at least a portion of the external surface of the downhole device. As examples, the core may include and/or be an elongate core, a rigid core, a metallic core, a partially solid core, a hollow core, and/or an elongate rigid core. The external surfaces of the core may be substantially solid except for an opening to a sealing component holder and openings to accommodate connections to the downhole device such as an umbilical connection. It is within the scope of the present disclosure that the core may or may not be an enclosed tubular. The core may be a single-piece and/or monolithic structure. Alternatively, the core may be a multi-piece core that includes a plurality of core segments. Each core segment may be operatively attached to one or more adjacent core segments to form and/or define the core. As an example, the core segments may be hermetically sealed to one another to form and/or define the core.

The downhole device includes a sealing component holder. The downhole device may include more than one sealing component holder, such as a plurality of sealing component holders. Each sealing component holder includes an opening to an external surface of the core. As an example, the opening may be in a bottom surface of the downhole device such that the sealing components do not pass between a side surface of the downhole device and an inner surface of the wellbore tubular. A cover is positioned over each sealing component holder opening and is constructed and arranged to allow a portion of the sealing components to exit the opening upon displacement of an internal volume of the sealing component holder. The cover may be any suitable structure and/or material that allows the sealing components to exit the holder upon displacement of an internal volume and otherwise retains the sealing components within the sealing component holder. As an example, FIG. 3 illustrates cover 187 may be a spring loaded cover including a spring 187A disposed about a rod 187 B which is disposed through openings 187C in the cover 187 providing suitable tension to hold the cover tight against an external surface of the core proximal the opening (not shown) except when an internal volume is being displaced. As another example, FIG. 4 illustrates cover 187 may be a rotating cover which overlaps the opening (not shown) of the core and is constructed and arranged to rotate the cover to align an opening 187D with the opening 189 (not shown) of the core to release sealing components. The rotating mechanism (not shown) may be operatively connected to the cover 187 in any suitable manner. As another example, FIGS. 5 and 6 illustrate cover 187 may be a flexible cover made of a flexible material overlapping the opening (not shown) in the surface of the core and including an opening 1871 or slit 187H proximate the center of the flexible cover. The slit may be constructed and arranged to allow the sealing components to pass through the slit upon actuation of the metering device. The cover opening 1871 of FIG. 6 may be constructed and arranged to retain the sealing components until the metering device is actuated to push the sealing components through the cover opening 1871.

A sealing component holder may have any suitable shaped interior which is able to contain the sealing components and release the sealing components upon displacement of an internal volume of the sealing component holder. The sealing component holder may form a portion of the internal volume of the core. As an example, the sealing component holder may form a majority of the internal volume of the core. As an example, the radial cross-section of the sealing component holder may be circular or elliptical. As an example, the radial cross-sectional dimension or diameter of the interior of the sealing component holder may be constructed and arranged to be of similar dimension or diameter of the sealing component or may be constructed and arranged to house sealing components two, three, or more radially across. As an example, the internal volume of the sealing component holder may include a plurality of members that extend radially inward of an inner surface of the sealing component holder to form slots to hold the sealing components within the sealing component holder.

The internal volume of the sealing component holder may include a plurality of axially spaced apart regions. Each region including a portion of the plurality of sealing components. As illustrated in FIG. 7, a sealing component holder 180 may include a first region 180A containing a first portion of the plurality of sealing components 182A, a second region 180B containing a second portion of the plurality of sealing components 182B, a third region 180C containing a third portion of the plurality of sealing components 182C, etc. As an example, the different portions of the plurality of sealing components may have different properties from the sealing components in adjacent regions within the sealing component holder. As another example, each region within a sealing component holder may contain a portion of the plurality of sealing components with different properties from each of the other portions of the plurality of sealing components. The properties may include composition, size, specific gravity, rate of degradation, non-degradability, and any combinations thereof. Size of the sealing components includes the maximum outer dimension and/or diameter of the sealing component.

As an example, each region within a sealing component holder contains a plurality of sealing components, such as ball sealers, the rate of degradation being different from the plurality of sealing components of each of the other regions within the sealing component holder. The rate of degradation being the greatest for the first region within the sealing component holder proximal the opening and being the least for the last region within the sealing component holder distal the opening. Additionally or alternatively, the size and/or specific gravity being different from the plurality of sealing components of each of the other regions within the sealing component holder.

The downhole device may include a plurality of sealing component holders. The sealing components within each sealing component holder may be the same or may be different. As an example, the downhole device may include a first sealing component holder containing a plurality of ball sealers as the sealing components and a second sealing component holder containing a plurality of chemical diverters as the sealing components. This arrangement allows the same downhole device to be used to seal the wellbore tubular with ball sealers and to seal the subterranean formation exterior of openings in a wellbore tubular with chemical diverters which may be performed in a single trip from the surface downhole.

As another example, the downhole device may include a first sealing component holder including a plurality of degradable ball sealers as the sealing components and a second sealing component holder including a plurality of non-degradable ball sealers as the sealing components. The first sealing component holder may include a plurality of regions, each region within the first sealing component holder may contain a plurality of sealing components, such as ball sealers, having a substantially different rate of degradation, as discussed in more detail herein. This arrangement allows the same downhole device to be used to temporarily seal sections of the wellbore tubular with degradable ball sealers and to subsequently seal sections of the wellbore tubular with non-degradable ball sealers.

The plurality of sealing components may be any suitable structure and/or material to seal a wellbore tubular or subterranean formation exterior of the wellbore tubular. The plurality of sealing components may be selected from ball sealers, chemical diverters, other physical components sized and dimensioned to physically seal a wellbore tubular or subterranean formation, and any combinations thereof. An example of a suitable sealing component may be a PERF PODS″ sealing component that is available from Thru Tubing Solutions, Inc. of Oklahoma City, Okla. A PERF PODS' sealing component includes a primary sealing core from which a plurality of secondary tendrils extends to form secondary seals, such as of one or more leakage pathways between the primary sealing core and the sealing device seat.

The term “ball sealers” as used herein is meant to include any solid, semi-rigid, deformable object having suitable dimensions to individually seal an opening, such as a perforation or a SSP, within the wall of the wellbore tubular. Ball sealers may be made of a single material or a composite material, either material suitable for deforming into a shape sufficient of sealing, but not extruding through, the opening onto which it is seated. The composite material for the ball sealers may include two or more regions or layers of different composition. As an example, ball sealers may be formed having a hard inner core region and a soft outer region sufficiently compliant to sealingly engage an opening within the wellbore tubular. The material for the inner core may be selected from nylon, phenolic resin, neoprene rubber, syntactic foam, and metallic materials such as aluminum. The material for the outer region may be selected from elastomers and soft rubbers, such as ethylene propylene diene monomer (EPDM), nitrile butadiene rubber (NBR), hydrogenated nitrile butadiene rubber (HNBR), and the like.

Ball sealers may be made of degradable or non-degradable materials. “Degradable” as used herein is meant to include materials that decompose over a period of time and/or at least partially dissolve upon contact with a fluid. Degradation may be characterized by time, temperature, and/or fluid type (e.g., oil, water, acidity). The fluid may be a water-based fluid or an oil-based fluid. The water-based fluid may be an acidic fluid. “Non-degradable” as used herein is meant to include materials that are stable and do not decompose over a reasonable period of time for intended operations.

Ball sealers may be made of degradable materials which degrade in the presence of water and may be selected from polyglycolic acid polymer materials, such as polyglycolic acid semicrystalline polyester, polylactic acid polymer materials, and the like. Ball sealers may be made of degradable materials which degrade in the presence of oil, such as alpha-olefins. Ball sealers may be made of degradable materials which degrade in the presence of acid such as nylon.

All or a portion of a ball sealer may be made of a degradable material. As an example, a ball sealer may have an inner core formed of a non-degradable material and one or more outer regions of degradable material.

Other materials which may be used to form ball sealers may be selected from poly-L-lactic acid, polyetheretherketone, epoxy resin, polystyrene, poly-methylmethacrylate, high density polyethylene, polypropylene, polyamide, polycarbonate, poly-phenylene sulfide, and any combinations thereof.

Ball sealers may be buoyant, neutrally buoyant, and/or non-buoyant with respect to the wellbore fluid in which the ball sealers are disposed. Ball sealers may be of any suitable size and shape to sealingly engage with an opening within the wall of the wellbore tubular. Ball sealers may be spherical or polygonal. Ball sealers may have a maximum outer dimension and/or diameter in the range of from 5 millimeters (mm) to 76 mm or from 10 mm to 50 mm. Ball sealer may have a maximum outer dimension and/or diameter in the range of from 15 mm to 30 mm or from 22 mm to 25.5 mm. Ball sealers may be oversized or undersized. “Undersized” is meant to include ball sealers having a maximum outer dimension and/or diameter that is less than what could typically be delivered downhole from the surface. Undersized ball sealers may have a maximum outer dimension and/or diameter of less than 15 mm or less than 12 mm. Undersized ball sealers may have a maximum outer dimension and/or diameter in the range of from 5 mm to less than 15 mm or from 5 mm to less than 12 mm. “Oversized” is meant to include ball sealers having a maximum outer dimension and/or diameter that is greater than what could typically be delivered downhole having to pass between the inner surface of the wellbore tubular and the outer surface of the downhole device. Oversized ball sealers may have a maximum outer dimension and/or diameter of greater than 25.5 mm, or greater than 32 mm or greater than 50 mm. Oversized ball sealers may have a maximum outer dimension and/or diameter in the range of from greater than 25.5 mm to 76 mm or from greater than 32 mm to 76 mm or from greater than 50 mm to 76 mm.

The plurality of sealing components may include chemical diverters. Chemical diverters may be solid particles of chemical components, viscoelastic surfactants, polymer gels, foams, and any combinations thereof used to seal porous and permeable portions of the subterranean formation and/or fractures formed within the subterranean formation. The chemical diverters may be contained within a package or pod using a layer, membrane, film, and the like so that the chemical diverter contained therein is released upon the package or pod dissolving or otherwise rupturing within the wellbore. Chemical diverters may be used in linear, crosslinked, slick water, or acid hydraulic fracturing operations.

The chemical components may be selected from benzoic acid, polyglycolic acid polymer, polylactic acid polymer, sodium chloride, oil-soluble resins, waxes, polyesters, poly carbonates, polyacetals, polyvinyl chlorides, polyvinyl acetates, nylon, polytetrafluoroethylene, and any combinations thereof. The chemical diverter particles may have any suitable particle size effective to seal portions of the subterranean formation. As an example, the chemical diverter particles may have a particle size in the range of from 0.1 mm to less than 5 mm or from 0.1 mm to 4 mm or from 0.5 mm to 2 mm. The particles may be flakes, pellets, beads, and the like.

Viscoelastic surfactants may be selected from cetyltrimethylammonium bromide, cationic/anionic surfactant blends with a nonaqueous solvent, salicylic acid or phthalic acid with cationic or amphoteric surfactants, cationic surfactants such as erucyl methyl bis(2-hydroxyethyl) ammonium chloride, 4-erucamidopropyl-1,1,1,-trimethyl ammonium chloride, zwitterionic/amphoteric surfactants such as oleylamidopropyl betaine, erucylamidepropy betaine, and anionic surfactants such as alkyl taurate surfactants, methyl ester sulfonates, sulfosuccinates. Polymer gels may be selected from hydroxyethylcellulose, acrylamide, polysaccharides such as guar, xanthan, scleroglucan, and succinoglycan, and any combinations thereof.

The metering device may include a pump, a motor, a source of stored energy, and combinations thereof. The pump may be selected from a solid state, piezoelectric pump, a positive displacement pump, or a hydraulic pump. As an example, the pump may be a solid state, piezoelectric pump. An example of a solid state, piezoelectric pump is described in U.S. Patent Publication No. 2015/0060083, titled “Systems and Methods for Artificial Lift Via a Downhole Piezoelectric Pump”, which description of a piezoelectric pump is incorporated herein by reference. As another example, the pump may be selected from a positive displacement pump or a hydraulic pump. It is understood that a positive displacement pump or a hydraulic pump may include an associated motor for the operation of the pump which is different from a motor acting as the primary component for the metering device.

The motor as the primary component of the metering device may be an electric motor. The electric motor may be powered by an alternating current (AC) voltage or a direct current (DC) voltage. As an example, the primary component of the metering device may be a brushless DC motor.

The source of stored energy may include a stored energy device, such as a spring or pre-charged cylinder of a fluid, that may be operatively coupled to the member within the sealing component holder, thus replacing the need for a motor or a pump. The stored energy devices may be operatively coupled to the member within the sealing component holder similar to a motor or pump, as further described herein.

Electrical power to the components of the metering device and other components of the downhole device may be supplied locally or remotely from the surface. A local source of electrical power may include one or more batteries. The batteries may be positioned within the core and operatively connected to the components of the metering device. The remote source of power may be operatively connected to the downhole device via an umbilical, as discussed in more detail herein, and/or a separate electrical cable. Electrical connections from the batteries, the umbilical and/or the separate electrical cable may be provided within the core to connect the components of the metering device and other components of the downhole device requiring electricity to the source of electrical power.

The metering device may be operatively connected to a member positioned within a sealing component holder such that, upon actuation of the metering device, the member displaces an internal volume of the sealing component holder. As an example, FIG. 2 illustrates the member 184 may be a bellow 175 having substantially the same cross-sectional dimension as the sealing component holder 180 in which bellow 175 is positioned. The metering device 186 may be operatively connected to the bellow 175 using a connection 179 constructed and arranged to deliver a displacement fluid 183 from the displacement fluid storage 181 to an inlet 171 of the bellow 175 via the metering device 186 which may be a pump 177, such as a solid state, piezoelectric pump. As illustrated in FIG. 2, the pump 177 is arranged transverse to the longitudinal axis of the downhole device 190; however, the pump 177 may have any suitable orientation within the core, such as parallel to the longitudinal axis of the downhole device. The displacement fluid 183 entering the inlet 171 expands the bellow 175 to displace an internal volume of the sealing component holder 180. The displacement fluid 183 may be any fluid having a sufficient density capable of displacing an internal volume of a sealing component holder.

As another example, the member may be a moveable bulkhead having substantially the same cross-sectional dimensions as the sealing component holder in which it is positioned forming a barrier between the backside of the member and the sealing components. As an example, the metering device may be operatively connected to the member using a connection including a mechanical actuator that may be longitudinally displaced to move the member within the sealing component holder to displace an internal volume. The mechanical actuator may include a piston, a hydraulic cylinder, and any combinations thereof. As illustrated in FIG. 8, member 184 is a moveable bulkhead 173 operatively connected to the metering device 186, which is pump 177, via connection 188. Connection 188 may be attached to the back side 173B of bulkhead 173. Connection 188 may include a piston 188A. Although not shown, a hydraulic cylinder may alternatively be included in connection 188. The sealing components 182 may be positioned within the interior of the sealing component holder 180 between the opening 189 and the front side 173A of bulkhead 173.

As another example, the metering device may be operatively connected to the member using a conduit between a displacement fluid storage and an inlet port into the sealing component holder proximate the backside of the member and using the metering device to introduce the displacement fluid into the sealing component holder to move the member within the sealing component holder to displace an internal volume. FIG. 9 is a schematic representation of an operative connection between pump 177 as the metering device 186 and an inlet port 185 which is in fluid communication with the back side 184B of member 184. Sealing components are not shown for clarity purposes. Connection 188 may include a conduit 188B connecting a supply of displacement fluid 183 within the displacement fluid storage 181, pump 177 and inlet port 185. Member 184 may include a sealing material 184C disposed on the outer surface of member 184 in contact with an inner surface of the sealing component holder 180. The sealing components (not shown) may be positioned within the interior of the sealing component holder between the opening and the front side 184A of the member 184.

As another example, the metering device may be operatively connected to a member which may be an auger. The metering device may be attached to the auger in any suitable manner to be able to rotate the auger within the sealing component holder to displace an internal volume of the sealing component holder. FIG. 10 is a schematic representation of an operative connection between a motor 174 as the metering device 186 and an auger 172 as member 184. Connection 188 includes a gear box 188C to rotate and control the speed and torque of the rotation of auger 172 to displace an internal volume of the sealing component holder 180 to release sealing components (not shown) through the opening (not shown) in a surface of the core.

As another example, the metering device may be operatively connected to a member which may be moveable bulkhead. The metering device may be a motor and a ratcheting arrangement may be positioned between the motor and the bulkhead to displace an internal volume of the sealing component holder. FIG. 11 is a schematic representation of an operative connection between a motor 174 as the metering device 186 and moveable bulkhead 173 as member 184. Connection 188 includes a ratcheting arrangement 188D which provides longitudinal movement to connection 188 to displace an internal volume of the sealing component holder 180 to release sealing components through the opening. Although not shown in detail, the ratcheting arrangement may include a ratchet wheel and a pawl and the motor is operatively coupled to the ratchet wheel and the ratchet wheel is operatively coupled with the pawl. The pawl is operatively coupled with the connection rod to longitudinally move the rod forward to displace the member within the sealing component holder.

As illustrated in FIG. 2, opening 189 may be positioned proximal the distal (lower) end 109 of core 102. Alternatively, an opening 189 may be positioned proximal the upper end 115 of the core. Alternatively, opening 189 may be positioned at any location along the length of the core. If two or more sealing component holders are to be included with the downhole device 190, the associated openings may be located at substantially the same axial length of the core but circumferentially offset from each other or the associated openings may be located at substantially different axial lengths of the core and may or may not be circumferentially offset.

Referring to FIG. 2, the downhole device 190 may further include a detector 191. Detector 191 may be configured to detect any suitable property and/or parameter of downhole device 190, of fluid within tubular conduit 42, of wellbore tubular 40, and/or of tubular conduit 42 (as illustrated in FIG. 1). As an example, detector 191 may be configured to detect a location of the downhole device 190 within the wellbore tubular 40.

An example of detector 191 includes a casing collar locator that is configured to detect, or count, casing collars of the wellbore tubular and monitor the relative length and relationship to one another. The casing collar locator may also be configured to locate any substantial variation in casing components which may disturb magnetic lines flux coming from the casing components. Another example of detector 191 includes a depth detector that is configured to detect a depth of the downhole device within the tubular conduit. Yet another example of detector 191 includes a speed detector that is configured to detect a speed of the downhole device within the tubular conduit. Another example of detector 191 includes a timer that is configured to measure a time associated with motion of the downhole device within the tubular conduit. Yet another example of detector 191 includes a downhole pressure sensor that is configured to detect a pressure within the fluid that is proximal thereto. Another example of detector 191 includes a downhole temperature sensor that is configured to detect a temperature within the fluid that is proximal thereto.

Referring to FIG. 2, the downhole device 190 may further include a controller 150 programmed to control the operation of the downhole device, such as the metering device. The controller may include any suitable structure. As an example, a controller may include and/or be a special-purpose controller, an analog controller, a digital controller, and/or a logic device. Communication linkage 108 may be included between the metering device and the controller to provide a signal to the metering device to actuate the metering device and displace a given internal volume of the sealing component holder. Communication linkage 108 may also be included between the controller 150 and a control system (not shown) located remotely at the surface. Communication linkage 108 positioned within core 102 may be positioned within pass-through holes 106, as illustrated in FIG. 2. The communications linkage 108 may be provided via the umbilical, as discussed in more detail herein. The controller may be programmed to receive actuation signals via the umbilical and provide actuation signals to the metering device. Alternatively, the controller may communicate with the metering device or the surface control system via a wireless communication network. Alternatively, the metering device may be controlled directly by the surface control system via the umbilical and communications linkage or wireless communication network.

As an example, detector 191 may be configured to generate a location signal that is indicative of the location of the downhole device within the wellbore tubular and to convey the location signal to the controller via communication linkage. In addition, the controller may be programmed to control the operation of the downhole device based, at least in part, on the location signal.

As another example, detector 191 may be configured to detect a shockwave generated within the wellbore conduit. Under these conditions, detector 191 may generate a signal responsive to receipt of the shockwave and may provide the shockwave signal, via the communications linkage, to the controller or surface control system which in turn may generate a signal to actuate the metering device in response to the detected shockwave.

As another example, detector 191 may be configured to detect a pressure pulse within the wellbore fluid, such as may be deliberately and/or purposefully generated within the wellbore fluid by an operator of the hydrocarbon well. Under these conditions, detector 191 may generate a pressure pulse signal responsive to receipt of the pressure pulse and may provide the pressure pulse signal, via the communications linkage, to the controller or surface control system.

In some embodiments, the downhole device may include additional components such that it may be used as a shockwave generation device. Shockwave generation devices may be used with systems and methods for stimulating a subterranean formation which include placing selective stimulation ports (SSPs) within the wellbore tubular. Each SSP includes an isolation device that is configured to selectively transition from a closed state to an open state responsive to the receipt of a shockwave having an intensity upon contact with the isolation device greater than a threshold shockwave intensity for the isolation device. The shockwave generation device may be utilized to provide the shockwaves to selectively transition the SSPs from a closed state to an open state to permit stimulation of a subterranean formation, such as subterranean formation 34, and/or to permit an inrush of reservoir fluid into the wellbore tubular from the subterranean formation. Unlike perforation guns which detonate high energy shape-charges to form perforations within the wellbore tubular and the subterranean formation proximate thereto, the shockwave generation device requires much less energy since the device only has to generate the required shockwave intensity to transition the isolation device within the SSP to an open state. Unlike the irregular perforations formed using a perforation gun, the SPPs provide preformed openings of a controlled shape and may be made of a material that has a greater erosion-resistance, abrasion-resistance, and/or corrosion-resistance as compared to the material forming the majority of the wellbore tubular.

FIG. 12 is a schematic representation of a hydrocarbon well 10 that may include and/or utilize a downhole device, in particular a shockwave generation device 190A, according to the present disclosure, to generate a shockwave 194 within a wellbore fluid 22 that extends within the tubular conduit 42. Wellbore tubular 40 of hydrocarbon well 10 includes a plurality of SSPs 100. SSPs 100 may be operatively attached to and/or may form a portion of any suitable component of wellbore tubular 40. SSPs 100 may be configured to be operatively attached to and/or formed into a portion of wellbore tubular 40 prior to the wellbore tubular 40 being located, placed, and/or installed within wellbore 20.

SSPs 100 may be operatively attached to wellbore tubular 40 in any suitable manner. As examples, SSPs 100 may be operatively attached to wellbore tubular 40 via one or more of a threaded connection, a glued connection, a press-fit connection, a quarter turn latch connection, a welded connection, and/or a brazed connection.

Referring to FIGS. 12 and 13, shockwave generation device 190A may be configured to generate a shockwave 194 within a wellbore fluid 22 that extends within tubular conduit 42. The shockwave propagates within the wellbore fluid and/or propagates from the shockwave generation device to the SSP within and/or via the wellbore fluid. The shockwave may be attenuated by the wellbore fluid, and this attenuation may include attenuation by at least a threshold attenuation rate. As an example, the shockwave may have a peak shockwave intensity proximal the shockwave generation device and may decay, or decrease in intensity, with distance from the shockwave generation device. Under these conditions, the threshold shockwave intensity for an isolation device may be less than a threshold fraction of the peak shockwave intensity proximal the shockwave generation device. Examples of the threshold attenuation rate include attenuation rates of at least 1 megapascal per meter (MPa/m), at least 2 MPa/m, at least 4 MPa/m, at least 6 MPa/m, at least 8 MPa/m, at least 10 MPa/m, at least 12 MPa/m, at least 14 MPa/m, at least 16 MPa/m, at least 18 MPa/m, at least 20 MPa/m, and/or at least 30 MPa/m.

SSPs 100 are configured to selectively transition from a closed state, in which fluid flow there through (i.e., between the tubular conduit and the subterranean formation) is blocked, restricted, and/or occluded, to an open state, in which fluid flow there through is permitted, responsive to receipt of, or responsive to experiencing, a shockwave of greater than a threshold shockwave intensity for the associated isolation device of the SSP.

As an example, and as illustrated in FIGS. 12 and 14, SSPs 100 may include an SSP body 110 that defines an SSP conduit 116 forming an opening within the wall of the wellbore tubular. SSP conduit 116 may extend between tubular conduit 42 and subterranean formation 34. SSP body 110 has a tubular conduit facing region 112 and an opposed, formation-facing region 114. SSP body 110 also has a projecting region 113, which projects from SSP body 110 in a direction that is away from or perpendicular to, a central axis 118 of SSP conduit 116. SSP may include a tool-receiving portion 176, which may be configured to receive a tool during operative attachment of the SSP 100 to a wellbore tubular (not shown) and an attachment region 178, which may be configured to interface with the wellbore tubular when the SSP 100 is operatively attached to the wellbore tubular. As an example, attachment region 178 may include threads (not shown), and SSP 100 may be configured to be rotated, via receipt of the tool (not shown) within the tool-receiving portion 176, to permit threading of the SSP 100 into the wellbore tubular. SSP 100 may further include a sealing component seat 140, which may be configured to receive a sealing component 182 when SSP is transitioned to an open state. Sealing component seat 140 may be shaped to form a fluid seal 144 with external surface 143 of sealing component 182 when sealing component 182 is in sealing engagement with sealing component seat 140 and SSP 100 is transitioned to an open state.

Sealing component seat 140 interfaces with tubular conduit 42 and may be shaped to form a fluid seal 144 with a sealing component 182, such as a ball sealer, that flows into engagement with the sealing component seat 140. Formation of the fluid seal 144 may selectively restrict fluid flow from tubular conduit 42 and into wellbore and/or subterranean formation 34 via SSP conduit 116. Sealing component seat 140 may be a preformed sealing component seat that has a predetermined geometry prior to wellbore tubular being located, placed, and/or installed within wellbore. Sealing component seat 140 may be selected from a corrosion-resistant sealing component seat, an erosion-resistant sealing component seat, an abrasion-resistant sealing component seat, and any combinations thereof.

Referring to FIG. 14, SSPs 100 may further include an isolation device 120 which is illustrated in a closed state 121. SSP 100 may also include retention device 130. Retention device 130 may be configured to couple, or operatively couple, isolation device 120 to SSP body 110, such as to retain the isolation device 120 in the closed state 121 prior to receipt of a shockwave having an intensity greater than a threshold shockwave intensity for the isolation device 120 transitioning SSP 100 to an open state (not shown).

As an example, isolation device 120 may include an isolation disk that extends across SSP conduit 116 when the SSP 100 is in the closed state and that separates from SSP body 110 responsive to receipt of the shockwave with greater than the threshold shockwave intensity, such as to permit fluid flow through SSP conduit 116 when the SSP 100 is in the open state. As another example, isolation device 120 may include a frangible isolation disk that extends across SSP conduit 116 when the SSP 100 is in the closed state and that breaks apart responsive to receipt of the shockwave with greater than the threshold shockwave intensity, such as to permit fluid flow through SSP conduit 116 when the SSP 100 is transitioned to the open state.

Since shockwave 194 is attenuated by wellbore fluid 22, the shockwave may have sufficient energy (i.e., may have greater than the threshold shockwave intensity for an isolation device) to transition a first SSP 100, which is less than a threshold distance from the shockwave generation device 190A when the shockwave generation device 190A generates the shockwave 194, from the closed state to the open state. However, the shockwave 194 may have insufficient energy to transition a second SSP 100, which is greater than the threshold distance from the shockwave generation device when the shockwave generation device generates the shockwave, and remains in the closed state.

Stated another way, the plurality of explosive charges may be sized such that the shockwave selectively transitions the first SSP from the closed state to the open state but does not transition the second SSP from the closed state to the open state. The threshold distance also may be referred to herein as a maximum effective distance of the shockwave and/or of the shockwave generation device 190A from which the shockwave was generated. Examples of the threshold distance include threshold distances of less than 1 meter, less than 2 meters, less than 3 meters, less than 4 meters, less than 5 meters, less than 6 meters, less than 7 meters, less than 8 meters, less than 10 meters, less than 15 meters, less than 20 meters, or less than 30 meters along an axial length of the tubular conduit.

Shockwave generation device 190A may include and/or be any suitable structure that may, or may be utilized to, generate a shockwave 194 within wellbore fluid 22. The shockwave generation device 190A may be an umbilical-attached downhole device or an autonomous downhole device, as discussed in more detail herein.

FIG. 13 is a schematic representation of a shockwave generation device 190A for deployment within hydrocarbon well 10 according to the present disclosure, while FIG. 15 is a more detailed but still schematic representation of a portion of the shockwave generation device 190A of FIG. 13. FIG. 16 is a less detailed schematic side view of a shockwave generation device 190A according to the present disclosure, while FIG. 17 is a cross-sectional view of a shockwave generation device 190A illustrating various relative shapes and orientations for flutes, explosive charges, and protective barriers that may be utilized in shockwave generation devices 190A. FIG. 18 is a less detailed schematic side view of a shockwave generation device 190A according to the present disclosure, while FIG. 19 is a cross-sectional view of the shockwave generation device 190A of FIG. 18 taken along line 7-7 of FIG. 18. FIG. 20 illustrates various transverse cross-sectional shapes for flutes that may be defined by the core of a shockwave generation device 190A according to the present disclosure.

Any of the structures, functions, and/or features that are discussed herein with reference to shockwave generation devices 190A of FIGS. 13 and 15-20 may be included in and/or utilized with downhole device 190A and/or hydrocarbon well 10 of FIG. 12 without departing from the scope of the present disclosure. Similarly, any of the structures, functions, and/or features that are discussed herein with reference to downhole device 190 and/or hydrocarbon well 10 of FIG. 1 may be included in and/or utilized with shockwave generation devices 190A of FIGS. 13 and 15-20 without departing from the scope of the present disclosure.

As illustrated in FIG. 23, shockwave generation device 190A is configured to generate shockwave 194 within wellbore fluid 22 that extends within tubular conduit 42 of wellbore tubular 40. As illustrated in FIG. 13, shockwave generation device 190A includes core 500 and a plurality of explosive charges 520. Shockwave generation device 190A further includes a plurality of triggering devices 530.

Explosive charges 520 are arranged on an external surface 502 of core 500, and each triggering device 530 is configured to initiate explosion of a selected one of the plurality of explosive charges 520. Stated another way, shockwave generation device 190A may be configured such that a selected triggering device 530 may initiate explosion of a selected explosive charge 520 without initiating explosion of other explosive charges 520 that may be associated with other triggering devices 530. As such, shockwave generation device 190A also may be referred to herein as, or may be, a select-fire, shockwave generation device 190A, a selective-fire, downhole shockwave generation device 190A, and/or a shockwave generation device 190A that is configured to selectively explode a plurality of explosive charges 520 and to generate a plurality of shockwaves that are spaced-apart in time.

It is within the scope of the present disclosure that the phrase “selected one of the plurality of explosive charges” may refer to a single explosive charge 520. Alternatively, it is also within the scope of the present disclosure that the phrase “selected one of the plurality of explosive charges” may refer to two or more spaced-apart, separate, and/or distinct explosive charges 520 and also may be referred to herein as a selected portion of the plurality of explosive charges. Thus, a given triggering device 530 may initiate explosion of a single explosive charge 520 or two or more of the plurality of explosive charges 520 within a selected portion of the plurality of explosive charges 520. Regardless of the exact configuration, each triggering device 530 may initiate explosion of one or more selected and/or predetermined explosive charges 520 but may not initiate explosion of each, or every, explosive charge that is included within shockwave generation device 190A.

Shockwave generation device 190A may be configured such that the shockwave emanates symmetrically, at least substantially symmetrically, isotropically, and/or at least substantially isotropically, therefrom. Stated another way, the shockwave generation device may be configured such that the shockwave is symmetric, at least substantially symmetric, isotropic, and/or at least substantially isotropic within a given transverse cross-section of the wellbore tubular in which the shockwave in generated. This symmetric and/or isotropic behavior of the shockwave may be accomplished in any suitable manner. As an example, and as discussed in more detail herein, explosive charges 520 may be circumferentially wrapped around, or at least substantially around, an external surface 502 of core 500.

Core 500 of shockwave generation device 190A may be a core as discussed in more detail herein with respect to a downhole device and may include any suitable structure and/or material that may have, form, and/or define external surface 502, which may also support explosive charges 520, and/or triggering devices 530. It is also within the scope of the present disclosure that core 500 may have and/or define one or more pass-through holes 506, as illustrated in FIG. 13. Pass-through holes 506 may extend along a longitudinal length of core 500, and communication linkage 508 may extend therein, as illustrated in FIGS. 13 and 15. Communication linkage 508 may permit and/or provide communication between one or more components of shockwave generation device 190A and/or between umbilical 192 and one or more components of shockwave generation device 190A and/or between wireless communication network 39 (as illustrated in FIG. 12) and one or more components of the shockwave generation device 190A. Although not shown, pass-through holes 506 may also be provided along a longitudinal length of core 500 to accommodate electrical connections between one or more components of the shockwave generation device 190A and the source of electrical power and/or between components of the shockwave generation device 190A. It is understood that pass-through holes, communications linkage and electrical connections may also be included with downhole device 190.

As illustrated in FIG. 13, core 500 may further have, include, and/or define one or more flutes 504. Flutes 504 may be defined by external surface 502. In addition, flutes 504 may be shaped and/or configured to receive and/or contain one or more explosive charges 520. As an example, each flute 504 may receive and/or contain at least a portion, a majority, or even an entirety, of a respective one of the plurality of explosive charges 520.

As illustrated in FIGS. 17 and 20, each flute 504 includes a respective recess 512 and a respective opening 514. Both the opening and the recess are defined by core 500, and the opening provides, or is sized to provide, access to the recess by a given explosive charge 520. Recesses 512 may include and/or be elongate recesses that may extend along the longitudinal length of core 500, that may extend about and/or around core 500, that may spiral around core 500, and/or that may extend circumferentially around a transverse cross-section of core 500. Similarly, openings 514 may include and/or be elongate openings that may extend along the longitudinal length of core 500, that may extend about and/or around core 500, that may spiral around core 500, and/or that may extend circumferentially around a transverse cross-section of core 500.

As an example, and as illustrated in FIGS. 13 and 15 flutes 504 may extend longitudinally along the longitudinal length of core 500. As another example, and as illustrated in FIG. 16, flutes 504 may include a plurality of spiraling flutes that wrap around external surface 502 and/or that spirals along a longitudinal axis of core 500. As yet another example, and as illustrated in FIGS. 18 and 19, flutes 504 may include a plurality of circumferential flutes that extends at least partially, or even completely, around the transverse cross-section of the core and may include corresponding circumferential explosive charges 520.

It is within the scope of the present disclosure that flutes 504 may at least partially, or even completely, house and/or contain respective explosive charges 520. As an example, and as illustrated in FIG. 17 at 515, a respective explosive charge 520 may extend within recess 512 and may not extend and/or project through and/or across opening 514. Stated another way, a given explosive charge may have and/or define a respective transverse cross-sectional area, a given flute, which receives the given explosive charge, may have and/or define a respective transverse cross-sectional area, and the respective transverse cross-sectional area of the given explosive charge may be less than the respective transverse cross-sectional area of the given flute.

Such a configuration may be utilized to protect the explosive charge from damage due to motion of the shockwave generation device within the tubular conduit and/or due to flow of an abrasive material past the shockwave generation device while the shockwave generation device is present within the tubular conduit. Additionally or alternatively, such a configuration may provide a desired level of focusing, a desired intensity, and/or a desired directionality of the shockwave that is generated responsive to explosion of the given explosive charge.

A given flute 504 additionally or alternatively may be shaped and/or otherwise configured to protect a given explosive charge 520 such that initiation of explosion of another, or an adjacent, explosive charge 520 does not initiate explosion of the given explosive charge 520. As examples, the given flute 504 may direct the shockwave that is generated by given explosive charge 520 away from core 500, may direct the shockwave away from the other flutes 504, and/or may direct the shockwave away from other explosive charges 520 that are associated with the other flutes 504. As additional examples, the given flute 504 and/or the adjacent flute(s) may be configured to sufficiently shield and/or isolate the adjacent explosive charges from the shockwave produced by the given explosive charge 520 to prevent the shockwave from the given explosive charge initiating explosion of the adjacent explosive charges. Such configurations may permit and/or facilitate each triggering device 520 to initiate explosion of one or more selected explosive charges 520 without initiating explosion of each, or every, explosive charge that is included within shockwave generation device 190A.

As another example, and as illustrated in FIG. 17 at 516, a respective explosive charge 520 may extend within recess 512 and also may extend and/or project through and/or across opening 514. Stated another way, the respective transverse cross-sectional area of the given charge may be less than the respective transverse cross-sectional area of the given flute. Such a configuration may provide a desired level of focusing, a desired intensity, and/or a desired directionality of the shockwave that is generated responsive to explosion of the given explosive charge.

It is within the scope of the present disclosure that flutes 504 may have and/or define any suitable cross-sectional, or transverse cross-sectional, shape. As an example, and as illustrated in FIG. 20 at 590, flutes 504 may have and/or define a circular, or at least partially circular, transverse cross-sectional shape. As another example, and as illustrated in FIG. 20 at 592, flutes 504 may have and/or define an arcuate, or at least partially arcuate, transverse cross-sectional shape. As yet another example, and as illustrated in FIG. 20 at 594, flutes 504 may have and/or define a triangular, at least partially triangular, V-shaped, or at least partially V-shaped, transverse cross-sectional shape. As another example, and as illustrated in FIG. 20 at 596, flutes 504 may have and/or define a square, at least partially square, rectangular, or at least partially rectangular, transverse cross-sectional shape. Flutes with other regular and/or irregular geometric transverse cross-sectional shapes also may be utilized. As illustrated in FIG. 20 at 598, one or more explosive charges 520 may extend across a portion of external surface 502 that does not include a flute.

As discussed in more detail herein, core 500 may be a single-piece and/or monolithic structure or, alternatively, a multi-piece core that includes a plurality of core segments 510 as illustrated in FIG. 18. Each core segment 510 may be operatively attached to one or more adjacent core segments to form and/or define core 500. It is understood such arrangements of core 500 may also be utilized with core 102 of downhole device 190. When shockwave generation device 190A includes core segments 510, it is within the scope of the present disclosure that each core segment 510 may have any suitable number of explosive charges 520 and/or corresponding triggering devices 530 associated therewith and/or attached thereto. As examples, each core segment may have 1, 2, 3, 4, 5, 6, 7, 8, or more than 8 explosive charges and/or corresponding triggering devices associated therewith and/or attached thereto. When shockwave generation device 190A includes core segments 510, it is within the scope of the present disclosure that a core segment at the distal end of the core may form the sealing component holder. Additionally or alternatively, one or more of the core segments 510 may include an internal void such that when such core segments 510 are operatively attached, a sealing component holder 180 may be formed within the interior of the defined core 500; at least one of the core segments 510 may include an opening 189 to the so formed sealing component holder 180 with an associated cover (not shown); and at least one of the core segments 510 includes all or a portion of the metering device (not shown). If a plurality of sealing component holders are to be included within core 500, additional sealing component holders may be similarly formed.

Explosive charges 520 may include and/or be any suitable structure that may be adapted, configured, formulated, synthesized, and/or constructed to selectively explode and/or to selectively generate the shockwave within the wellbore fluid without causing substantial damage to the shockwave generation device during intended operations. Stated another way, at most only insubstantial damage may be experienced by the shockwave generation device upon exploding explosive charges 520 during intended operation of the device.

An example of explosive charges 520 include a primer cord (or detonation cord) 522. As an example, shockwave generation device 190A may include a plurality of lengths of primer cord 522, with each explosive charge 520 including at least one length of primer cord as the source of explosive on the shockwave generation device 190A. Primer cord 522 also may be referred to as detonation cord or detonating cord and configured to explode and/or detonate. The primer cord may be any suitable length. As examples, the length of the primer cord may be at least 0.1 meter (m), at least 0.2 m, at least 0.3 m, at least 0.4 m, at least 0.5 m, at least 0.6 m, at least 0.7 m, at least 0.8 m, at least 0.9 m, at least 1 m, at least 1.25 m, at least 1.5 m, at least 1.75 m, or at least 2 m. Additionally or alternatively, the length of the primer cord may be less than 5 m, less than 4.5 m, less than 4 m, less than 3.5 m, less than 3 m, less than 2.5 m, less than 2 m, less than 1.5 m, or less than 1 m.

Primer cord 522 also may include any suitable amount of an explosive, such as research department formula X (RDX), high melting explosive (HMX), or hexanitrostilbene (HNS). HMX may also be referred to as octogen, her majesty's explosive, high velocity military explosive, or high molecular weight RDX. As examples, the primer cord may include at least 10 grains of explosive per foot of length (grains/ft) (or 2 grams per meter (g/m)), at least 20 grains/ft (or 4 g/m), at least 25 grains/ft (or 5 grams per meter (g/m)), at least 40 grains/ft (or 8 grams per meter (g/m)), at least 80 grains/ft (or 17 g/m), at least 100 grains/ft (or 21 grams per meter (g/m)), at least 160 grains/ft (or 34 grams per meter (g/m)), or at least 240 grains/ft (or 51 grams per meter (g/m)). Additionally or alternatively, the primer cord may include less than 1000 grains/ft (212 g/m), less than 720 grains/ft (153 g/m), less than 560 grains/ft (or 119 grams per meter (g/m)), less than 500 grains/ft (or 106 grams per meter (g/m)), less than 450 grains/ft (or 96 grams per meter (g/m)), less than 480 grains/ft (or 102 grams per meter (g/m)), less than 400 grains/ft (85 g/m), or less than 320 grains/ft (68 g/m). The amount of explosive may be in the range of from 20 grains/ft (4 g/m) to 1000 grains/ft (212 g/m), or from 25 grains/ft (5 g/m) to 560 grains/ft (119 g/m) or from 50 grains/ft (10 g/m) to 480 grains/ft (102 g/m). It is also understood that isolation devices may be used within the SSPs which may be made of stronger materials and may require larger explosive charges to open the SSP and/or Such SSPs may be installed within a wellbore tubular that has a greater pipe weight and/or is made of a stronger metal than typical wellbore tubulars in which case explosive concentrations may be in excess of 1000 grains/ft (212 g/m), of 2000 grains/ft (425 g/m), or of 3000 grains/ft (638 g/m).

In general, the length of the primer cord and/or the amount of explosive per unit length of the primer cord may be selected to provide a desired intensity, or a desired maximum intensity, for the shockwave when the primer cord explodes within the wellbore fluid. As an example, the length of the primer cord and/or the amount of explosive per unit length of the primer cord may be selected such that the maximum intensity of the shockwave is greater than the threshold shockwave intensity necessary to transition an SSP from the closed state to the open state. As another example, the length of the primer cord and/or the amount of explosive charge per unit length of the primer cord may be selected such that maximum intensity of the shockwave is less than an intensity that would damage, or rupture, a wellbore tubular that defines a tubular conduit within which the shockwave is generated and/or such that the shockwave has insufficient energy, or intensity, to rupture or damage the wellbore tubular.

Stated another way, each explosive charge 520 may be sized such that the shockwave has a maximum pressure of at least 100 megapascals (MPa), at least 110 MPa, at least 120 MPa, at least 130 MPa, at least 140 MPa, at least 150 MPa, at least 160 MPa, at least 170 MPa, at least 180 MPa, at least 190 MPa, at least 200 MPa, at least 250 MPa, at least 300 MPa, at least 400 MPa, or at least 500 MPa. Additionally or alternatively, each explosive charge 520 may be sized such that the shockwave has a maximum duration of less than 1 second, less than 0.9 seconds, less than 0.8 seconds, less than 0.7 seconds, less than 0.6 seconds, less than 0.5 seconds, less than 0.4 seconds, less than 0.3 seconds, less than 0.2 seconds, less than 0.1 seconds, less than 0.05 seconds, or less than 0.01 seconds. The maximum duration may be a maximum period of time during which the shockwave within the wellbore tubular has greater than the threshold shockwave intensity for the isolation device. Additionally or alternatively, the maximum duration may be a maximum period of time during which the shockwave has a shockwave intensity of greater than 68.9 MPa (10,000 pounds per square inch) within the portion of the wellbore tubular proximal the SSP to be transitioned from the closed state to the open state.

Each explosive charge 520 may be sized such that the shockwave within the tubular conduit exhibits a shockwave intensity greater than the threshold shockwave intensity for an isolation device over a maximum effective distance or length along the tubular conduit. Examples of the maximum effective distance are as discussed in more detail herein.

Shockwave generation device 190A may include any suitable number of explosive charges 520. As examples, the shockwave generation device may include at least 2, at least 3, at least 4, at least 5, at least 6, at least 7, or at least 8 explosive charges. Additionally or alternatively, the shockwave generation device may include 20 or fewer, 18 or fewer, 16 or fewer, 14 or fewer, 12 or fewer, 10 or fewer, 8 or fewer, 6 or fewer, or 4 or fewer explosive charges.

Triggering devices 530 may include and/or be any suitable structure that may be configured to selectively initiate explosion of a selected portion of the plurality of explosive charges independent from a remainder of the explosive charges. As an example, triggering devices 530 may include and/or be electrically actuated triggering devices, separately addressable switches, and/or detonators 532, as illustrated in FIG. 15. Detonators may include blasting caps. As a more specific example, each triggering device 530 may include a uniquely addressable switch that may be configured to initiate explosion of a selected one of the plurality of explosive charges responsive to receipt of a unique code. The unique code of each triggering device may be different from the unique code of each of the other triggering devices, thereby permitting selective actuation of a given triggering device.

As illustrated in FIGS. 13, 15-16, and 18, triggering devices 530 may form a portion of a triggering assembly 528. Triggering assembly 528 may be operatively attached to core 500 and/or may form a portion of core 500. In addition, and when shockwave generation device 190A is submerged within the wellbore fluid, triggering assembly 528 may at least partially, or even completely, isolate at least a portion, or even all, of each triggering device 530 from the wellbore fluid. As an example, and as illustrated in FIGS. 13 and 15, triggering assembly 528 may include and/or define an enclosed volume 529 within the core 500 that is fluidly isolated from the wellbore fluid and/or that contains and/or houses the triggering devices.

As illustrated in FIGS. 13, 15, 17, and 19, shockwave generation device 190A and/or explosive charge 520 thereof may further include a protective barrier 524. Protective barrier 524 may be configured to at least partially, or even completely, isolate, or fluidly isolate, explosive charges 520 from the wellbore fluid when the shockwave generation device is submerged within the wellbore fluid. Such isolation may prevent contamination of the explosive charge by the wellbore fluid, may prevent degradation of the explosive charge by the wellbore fluid, may resist permeation of the wellbore fluid into the explosive charge, and/or may resist abrasion of the explosive charge from movement within the wellbore or by an abrasive material, such as a proppant, that may be present within the wellbore fluid and/or by wellbore tubular when the shockwave generation device is present within tubular conduit.

As illustrated in FIG. 13, protective barrier 524 may extend along a length, or even an entire length, of explosive charge 520. As illustrated in FIG. 17 at 525, protective barrier 524 may extend completely around a transverse cross-section of a given explosive charge 520. Additionally or alternatively, and as illustrated in FIG. 17 at 526, protective barrier 524 may extend at least partially around a transverse cross-section of core 500 and/or of external surface 502 thereof and of a given explosive charge 520.

It is within the scope of the present disclosure that shockwave generation device 190A may include a plurality of protective barriers 524 and that each protective barrier 524 may extend around a corresponding explosive charge 520, may extend along a length of the corresponding explosive charge, may extend along an entirety of the length of the corresponding explosive charge, and/or may extend across a respective portion of external surface 502 of core 500 to protect the explosive charge 520 from damage during movement within the wellbore or particle flow around the shockwave generation device 190A. Additionally or alternatively, it is also within the scope of the present disclosure that a single protective barrier 524 may extend at least partially around two or more of the explosive charges and/or may extend across a majority, or even all, of external surface 502 of core 500. Protective barrier 524 may include and/or be formed from any suitable material. As examples, the protective barrier may include and/or be a non-metallic protective barrier and/or may be formed from a polymeric material, an elastomeric material, and/or a resilient material.

As illustrated in FIGS. 13 and 15, shockwave generation device 190A may include a first plurality of explosive charges 520 and a corresponding first plurality of triggering devices 530. In addition, and as illustrated in FIGS. 13 and 15, shockwave generation device 190A also may include a second plurality of explosive charges 520 and a corresponding second plurality of triggering devices 530. The first plurality of explosive charges and the first plurality of triggering devices together may define a first shockwave generation unit 198 (as indicated in solid lines), and the second plurality of explosive charges and the second plurality of triggering devices together may define a second shockwave generation unit 198 (as indicated in dashed lines). An additional section 199 is included at the distal end of the shockwave generation device 190A and includes the sealing component holder and metering device.

The first shockwave generation unit and the second shockwave generation unit may be operatively attached to one another, in an end-to-end fashion, to form and/or define shockwave generation device 190A. As an example, an end region of the first shockwave generation unit may be operatively attached to an end region of the second shockwave generation unit, such as via a coupling structure 562 and/or such that a longitudinal axis of the first shockwave generation unit is aligned, or at least substantially aligned, with a longitudinal axis of the second shockwave generation unit. Shockwave generation device 190A may include any suitable number of shockwave generation units 198 and each shockwave generation unit 198 may include any suitable number of explosive charges 520 and corresponding triggering devices 530. As examples, shockwave generation device 190A may include at least 2, at least 3, at least 4, at least 5, at least 6, at least 8, or at least 10 shockwave generation units. At least the lowermost (downhole direction) portion of shockwave generation device 190A may include a sealing component holder section 199. Section 199 may form a portion of the lowermost shockwave generation unit 198 or may form a separate unit such that an end region of the first shockwave generation unit may be operatively attached to an end region of the sealing component holder unit, such as via a coupling structure (not shown) and/or such that a longitudinal axis of the first shockwave generation unit is aligned, or at least substantially aligned, with a longitudinal axis of the sealing component holder unit.

Shockwave generation device 190A may be adapted, configured, designed, constructed, and/or sized to remain in the tubular conduit during stimulation of the subterranean formation, during flow of a stimulant fluid through and/or within the tubular conduit and past the shockwave generation device 190A, and/or during the inrush of reservoir fluid into the wellbore tubular. Shockwave generation device 190A may have any suitable length or overall length. As examples, the overall length of the shockwave generation device may be less than 40 meters, less than 35 meters, less than 30 meters, less than 25 meters, or less than 20 meters. The shockwave generation device 190A also may have any suitable maximum transverse cross-sectional extent, dimension, and/or diameter suitable for deployment within a wellbore tubular. As examples, the maximum transverse cross-sectional extent, dimension, and/or diameter may be less than 0.2 meters (m), less than 0.15 m, less than 0.1 m, less than 0.8 m, less than 0.09 m or less than 0.06 m. It is understood that a downhole device without the shockwave generation features may have similar dimensions.

The maximum transverse cross-sectional inner diameter of the tubular conduit and/or wellbore tubular may be any suitable diameter capable of accommodating the downhole device and any other downhole equipment and/or downhole components. As an example, the maximum transverse cross-sectional inner diameter of the tubular conduit and/or wellbore tubular may be in the range of from 70 mm to 178 mm or from 90 mm to 105 mm or from 94 mm to 102 mm. In such example, opening 189 may be provided proximal the distal end 109 of the shockwave generation device 190A and/or downhole device 190 and the sealing components 182 may include oversized ball sealers as discussed in more detail herein. As an example, the opening 189 may be provided in a bottom surface of the shockwave generation device 190A and/or downhole device 190. As another example, the opening 189 may be provided in a side surface having a lesser transverse cross-section dimension or diameter than the average transverse cross-sectional dimension or diameter of the shockwave generation device 190A and/or downhole device 190, as determined along its length, such that the sealing components (e.g., ball sealers) do not have to pass between the wellbore tubular and the maximum transverse cross-section extent, dimension and/or diameter of device 190, 190A. This arrangement provides the ability to locally release oversized ball sealers at different spaced-apart sections of the wellbore, oversized ball sealers having a maximum outer dimension larger than the gap formed between the wellbore tubular and the maximum outer dimension of the shockwave generation device or downhole device. Additionally or alternatively, when an opening 189 is positioned at other side surface locations along the length of the shockwave generation device 190A or downhole device 190, the maximum transverse cross-sectional dimension of the shockwave generation device 190A or downhole device 190 may be less than a cross-sectional diameter of the tubular conduit such that a gap formed there between may have a sufficient radial dimension to provide clearance for flow of the sealing components past the shockwave generation device 190A or downhole device 190.

As illustrated in FIGS. 13 and 15, shockwave generation device 190A may further include a detector 540. Detector 540 may be similar to detector 191 as discussed in more detail herein. Another example of detector 540 includes a magnetic field detector that is configured to detect a magnetic field that emanates from a magnetic material that defines a portion of the wellbore tubular and/or a SSP of the wellbore tubular. Yet another example of detector 540 includes a radioactivity detector that is configured to detect a radioactive material that forms and/or defines a portion of the wellbore tubular and/or a SSP 100 of the wellbore tubular. Yet another example of detector 540 includes a downhole pressure sensor that is configured to detect a pressure within the wellbore fluid that is proximal thereto. Another example of detector 540 includes a downhole temperature sensor that is configured to detect a temperature within the wellbore fluid.

As illustrated in FIGS. 13 and 15, shockwave generation device 190A may further include a controller 550. Controller 550 may be adapted, configured, designed, constructed, and/or programmed to control the operation of at least a portion of the shockwave generation device 190A. Controller 550 may include any suitable structure, as discussed in more detail herein with respect to controller 150. As an example, controller 150 may be used to actuate metering device 186 and controller 550 may be used to actuate a triggering device 530. Control by controller 550 may be based, at least in part, on a property and/or parameter detected by detector 540. Control by controller 150 may be based, at least in part, on a property and/or parameter detected by detector 191. As an example, and as illustrated in FIG. 15, shockwave generation device 190A may include communication linkage 552 between controller 550 and detector 540.

As an example, detector 540 may be configured to generate a location signal that is indicative of the location of the shockwave generation device 190A within the wellbore tubular 40 and to convey the location signal to the controller 550 via the communication linkage 552. In addition, controller 550 may be programmed to actuate the metering device (instead of using a separate controller 150) and/or a selected one of the plurality of triggering devices 530 based, at least in part, on the location signal and/or responsive to receipt of the location signal. Metering device 186 may displace an internal volume of the sealing component holder or triggering device 530 then may initiate explosion of a corresponding one of the plurality of explosive charges 520. Detector 540 may be used alternatively or in addition to detector 191.

As another example, detector 540 may be configured to detect a pressure pulse within the wellbore fluid, such as may be deliberately and/or purposefully generated within the wellbore fluid by an operator of the hydrocarbon well. Under these conditions, detector 540 may generate a pressure pulse signal responsive to receipt of the pressure pulse and may provide the pressure pulse signal, via the communication linkage, to controller 550. Controller 550 then may be programmed to actuate the metering device and/or the selected one of the plurality of triggering devices 530 based, at least in part, on the pressure pulse signal and/or responsive to receipt of the pressure pulse signal.

Additionally or alternatively, controller 550 may be configured to actuate the metering device and/or the selected one of the plurality of triggering devices responsive to receipt of an actuation signal and/or a triggering signal. The signal may be provided to the controller in any suitable manner. As an example, the signal may be provided to controller 550 using downhole wireless communication network 39, and controller 550 may be adapted, configured, designed, constructed, and/or programmed to receive the signal from the downhole wireless communication network. As another example, the signal may be provided to controller 550 using umbilical 192. Under these conditions, controller 550 may be adapted, configured, designed, constructed, and/or programmed to receive the signal from the umbilical, and it is within the scope of the present disclosure that the umbilical may be configured to provide serial communication between the controller and surface region 30. Alternatively, the devices may be controlled directly by the surface control system via the umbilical and communications linkage or wireless communication network.

The shockwave generation device 190A may further include a guide structure (not shown). The guide structure may be adapted, configured, sized, and/or shaped to passively guide and/or direct the shockwave generation device when the shockwave generation device moves and/or translates within the tubular conduit. It is understood that such guide structure may be used with a downhole device without the shockwave generation features.

Shockwave generation device 190A may include a bridge plug setting structure (not shown) in embodiments where the opening to the sealing component holder is positioned at a surface location other than the bottom surface of the shockwave generation device. A bridge plug setting structure may be configured to set, or to selectively set, a bridge plug within the tubular conduit. It is understood that such plug setting structure may be used with a downhole device without the shockwave generation features.

As also illustrated in FIG. 13, shockwave generation device 190A includes the components of the downhole device 190. Such components are depicted in the figures with the same reference numbers as for downhole devices 190. Sealing component holder 180 and metering device 186 may be configured to selectively release at least one sealing component, such as a ball sealer, for each explosive charge 520 that is associated with shockwave generation device 190A and/or for each SSP that is opened by each explosive charge. This may include releasing the at least one sealing component 182 responsive to explosion of a corresponding explosive charge 520, prior to explosion of the corresponding explosive charge, and/or subsequent to explosion of the corresponding explosive charge. It is intended that the description contained herein with respect to sealing component holders, sealing components, metering devices, and arrangements including such for downhole device 190 may also be utilized with shockwave generation device 190A.

As illustrated in FIG. 13, shockwave generation device 190A may further include and/or have operatively attached thereto one or more weights 564. Weights 564 may be configured to increase an average density of the shockwave generation device, to increase a weight of the shockwave generation device, and/or to regulate an orientation of the shockwave generation device when the shockwave generation device is present within the tubular conduit. As an example, and as illustrated in FIG. 13, weight 564 may be oriented off-center with respect to (parallel to) the longitudinal axis of shockwave generation device 190A and thereby may cause the shockwave generation device to orient within the tubular conduit in a predetermined, or desired, manner. It is understood that such weights may be used with a downhole device without the shockwave generation features.

It is within the scope of the present disclosure that, subsequent to actuation of all the explosive charges 520, shockwave generation device 190A may be adapted, configured, designed, and/or constructed to break apart and/or to dissolve within the tubular conduit. As an example, shockwave generation device 190A may be formed from a frangible material that breaks apart responsive to explosion of a last, or final, explosive charge 520. It is understood that a downhole device without the shockwave generation features may be similarly constructed.

As another example, shockwave generation device 190A may be formed from a degradable material that degrades within the wellbore fluid. This may include degrading within a timeframe that is shorter than a timeframe for other components of the hydrocarbon well, such as wellbore tubular 40. As an example, the shockwave generation device 190A may be configured to remain intact during generation of the shockwaves and to partially degrade, completely degrade, and/or break apart between completion of stimulation operations that utilize the shockwave generation device and production of reservoir fluid from the hydrocarbon well. It is understood that a downhole device without the shockwave generation features may be similarly constructed.

As yet another example, shockwave generation device 190A may be formed from a soluble material that is soluble within the wellbore fluid. This soluble material may be selected to dissolve within a timeframe that is shorter than the timeframe for other components of the hydrocarbon well, such as wellbore tubular 40, to degrade and/or break apart. As an example, the shockwave generation device may be configured to remain intact during generation of the shockwaves and to dissolve, completely dissolve, and/or break apart between completion of stimulation operations that utilize the shockwave generation device and production of reservoir fluid from the hydrocarbon well. It is understood that a downhole device without the shockwave generation features may be similarly constructed.

FIG. 21 is a flowchart depicting method 800, according to the present disclosure, which includes providing sealing components within a tubular conduit and optionally also generating a plurality of shockwaves within a wellbore fluid that extends within the tubular conduit, while FIGS. 22-26 are schematic cross-sectional views of a portion of a process flow 340 for providing sealing components and optionally generating a plurality of shockwaves 194 within a tubular conduit 40. As illustrated in process flow 340 of FIGS. 22-26, a shockwave generation device 190A may be positioned within a wellbore tubular 40 that defines a tubular conduit 42 and extends within subterranean formation 34. The wellbore tubular may include a plurality of SSPs 100 that initially may be in a closed state. The plurality of SSPs 100 may be spaced apart along the wellbore tubular, such as along the longitudinal length of the wellbore tubular and/or radially around the circumference of the wellbore tubular.

Method 800 may include pressurizing the tubular conduit by introducing a wellbore fluid, such as a stimulant fluid, at 805 and includes positioning a downhole device, such as a shockwave generation device, proximal to or within a first region of the tubular conduit radially interior of a first section of the wellbore tubular at 810. Method 800 may further include detecting that the downhole device is within the first region of the tubular conduit at 815 and include actuating a first triggering device at 820. Method 800 may further include transitioning at least a first SSP at 825, stimulating a first region of the subterranean formation at 830, and actuating a metering device to displace a first internal volume of a sealing component holder to discharge a first portion of the plurality of sealing components, such as at least one ball sealer, at 835 to seal SSPs in the open state within the first section of the wellbore tubular. Method 800 may or may not include repositioning the downhole device during the stimulation of the particular region (e.g., the first region or the second region) of the subterranean formation and/or repositioning the downhole device for actuating the metering device to displace an internal volume (e.g., the first internal volume or the second internal volume) of the sealing component holder. As an example, the downhole device may be positioned proximal to but outside of the first region of the tubular conduit for the displacement of the first internal volume of the sealing component holder. As an example, the proximal positioning to the first region of the tubular conduit may include positioning the downhole device within an adjacent region of the tubular conduit, uphole or downhole from the first region of the tubular conduit. It is understood the position downhole may be achieved due to the axial location of the sealing component holder within the downhole device relative to the section to be sealed or the movement of the downhole device downhole occurs with at least one section of the subterranean formation receiving wellbore fluid.

Method 800 includes positioning the downhole device proximal to or within a second region of the tubular conduit radially interior of a second section of the wellbore at 840, the second region spaced apart from the first region along the length of the wellbore tubular. Method 800 may include repressurizing the tubular conduit at 845 and/or detecting that the downhole device is in the second region of the tubular conduit at 850. Method 800 may include actuating a second triggering device at 855. Method 800 may include transitioning at least a second SSP at 860, stimulating a second region of the subterranean formation at 865, and actuating the metering device to displace a second internal volume of a sealing component holder to discharge a second portion of the plurality of sealing components, such as at least one ball sealer, at 870 to seal SSPs in the open state within the second section of the wellbore tubular. Method 800 may or may not include repositioning the downhole device during the stimulation of the second region of the subterranean formation and/or repositioning the downhole device for the actuation of the metering device and displacement of the second internal volume of the sealing component holder. It is understood that the downhole device may be positioned proximal to but outside of the second region of the tubular conduit for the displacement of the second internal volume of sealing component holder. As an example, the proximal positioning to the second region of the tubular conduit may include positioning the downhole device within an adjacent region of the tubular conduit, uphole or downhole from the second region of the tubular conduit. These processes may be repeated for additional regions within the tubular conduit and additional sections of the wellbore to seal areas of interest.

Pressurizing the tubular conduit at 805 may include pressurizing the tubular conduit in any suitable manner. As an example, the pressurizing at 805 may include pressurizing with a stimulant fluid, such as by flowing the stimulant fluid into the tubular conduit and/or providing the stimulant fluid to the tubular conduit. The pressurizing at 805 may be prior to the positioning at 810, concurrently with the positioning at 810, subsequent to the positioning at 810, prior to the detecting at 815, concurrently with the detecting at 815, subsequent to the detecting at 815, and/or prior to the actuating at 820. The pressurizing at 805 is illustrated in FIG. 22, wherein a stimulant fluid 70 is provided to tubular conduit 42 of wellbore tubular 40. As also illustrated in FIG. 22, and during the pressurizing at 805, SSPs 100 associated with wellbore tubular 40 may be in closed state 121, thereby permitting pressurization of the tubular conduit.

Positioning the downhole device may include positioning the downhole device within the tubular conduit. The positioning of the downhole device may be accomplished in any suitable manner and/or in any suitable direction such as in the uphole direction or in the downhole direction. As an example, the positioning may include flowing and/or conveying the downhole device in a downhole direction, such as downhole direction 29 of FIG. 22, within a flow of the wellbore fluid 22, such as stimulant fluid 70. Alternatively, the downhole device may be conveyed on jointed pipe tubing, continuous jointless tubing or other means, such as a wireline, and/or using a tractor. The wellbore fluid 22 may also include fracturing fluid with insubstantial amounts of proppant fluid (clean fracturing fluid). The clean fracturing fluid may follow a proppant-laden wellbore fluid to displace the proppant-laden fluid into the subterranean formation. As another example, the positioning may include positioning with an umbilical, such as a wireline, as illustrated in FIG. 22 at 192. As yet another example, the positioning may include autonomously positioning the downhole device. As another example, the positioning may include landing, resting, stopping, and/or receiving the downhole device on and/or with any suitable latch, catch, receiver, and/or platform that may form a portion of the wellbore tubular and/or of the SSP, and/or that may extend within the tubular conduit. FIG. 22 illustrates positioning the downhole device 190A within a first region 105 of the tubular conduit 42 radially interior of a first section 40A of the wellbore tubular 40.

Detecting the location of the downhole device may include detecting in any suitable manner. As an example, the detecting may include detecting via and/or utilizing a detector, as discussed in more detail herein. The detecting may include one or more of detecting a casing collar of the wellbore tubular, detecting a component associated with the wellbore tubular that has the potential to disturb magnetic lines of flux, detecting a velocity of the shockwave generation device within the wellbore tubular, detecting a residence time of the shockwave generation device within the wellbore tubular, detecting a distance of flow of the shockwave generation device along the length of the wellbore tubular, detecting a depth of the shockwave generation device within the wellbore tubular, detecting a magnetic material that forms a portion of the wellbore tubular and/or SSP, and/or detecting a radioactive material that forms a portion of the wellbore tubular and/or SSP.

Actuating at 820 may include actuating the first triggering device to initiate explosion of a first explosive charge of a plurality of explosive charges of the downhole device. The actuating of the first triggering device may include actuating to generate a first shockwave within the first region of the tubular conduit. This is illustrated in FIG. 23, where a shockwave 194 is illustrated within first region 105 of tubular conduit 42.

The actuating at 820 may include actuating responsive to any suitable criteria. As an example, the actuating at 820 may be initiated responsive to the detecting the position of the downhole device (i.e., responsive to detecting that the downhole device is within the first region of the tubular conduit). As another example, the actuating at 820 may include actuating subsequent to the positioning in a region of the tubular conduit and/or responsive to completion of the positioning within the tubular conduit. The actuating at 820 may include electrically actuating, mechanically actuating, chemically actuating, wirelessly actuating, and/or actuating responsive to receipt of a pressure pulse.

Transitioning the first SSP at 825 may include transitioning one or more first SSPs from respective closed states to respective open states responsive to receipt of the first shockwave with greater than the threshold shockwave intensity by the one or more first SSPs. This is illustrated in FIG. 23, with SSPs 100 that are present within first region 105 of tubular conduit 42 being transitioned to open state 122 responsive to receipt of shockwave 194. As also illustrated in FIG. 23, the transitioning at 825 may further include transitioning the SSPs 100 to open state 122 while maintaining one or more SSPs 100 that are uphole from the first SSP in respective closed states 121. The first SSPs and the second SSPs also may be referred to herein as being spaced-apart, or longitudinally spaced-apart, along a length of the wellbore tubular, and this selective transitioning of the SSPs within the first region 105 of the tubular conduit 42 and not the other SSPs may be due to the limited, or maximum, effective distance, or propagation distance, of the shockwave within a wellbore fluid 22 that extends within tubular conduit 42, as is discussed herein. Examples of the maximum effective distance of the shockwave are disclosed herein, and the one or more closed SSPs may be spaced-apart from the downhole device by greater than the maximum effective distance of the shockwave.

Stimulating the first region of the subterranean formation at 830 may include stimulating any suitable first region of the subterranean formation that may be proximal to and/or associated with the first region of the tubular conduit. The stimulating at 830 may include stimulating responsive to, or directly responsive to, the actuating at 820 and/or the transitioning at 825. As an example, and as illustrated in FIG. 23, transitioning the one or more first SSPs 100 to open state 122 may permit stimulant fluid 70 to flow from tubular conduit 42 and into subterranean formation 34, thereby permitting stimulation of the subterranean formation.

Actuating the metering device at 835 includes actuating the metering device to displace a first internal volume of a sealing component holder to discharge a first portion of the plurality of sealing components, such as at least one ball sealer, to seal SSPs in the open state within the first region of the tubular conduit. Actuating at 835 may include releasing the first portion of the plurality of sealing components from the downhole device and flowing the first portion of the plurality of sealing components, via the tubular conduit, to and/or into engagement with the one or more first SSPs. As illustrated in FIG. 24, sealing components 182 have been released into tubular conduit 42. As illustrated in FIG. 25, engagement between the first portion of the plurality of sealing components 182 and the one or more first SSPs 100 in the first region 105 of the tubular conduit 42 within the first section 40A of the wellbore tubular 40 may restrict fluid flow 70 from the tubular conduit 42 via the one or more first SSPs 100.

It is within the scope of the present disclosure that the actuating at 835 may include actuating the metering device in any suitable manner. As examples, the actuating at 835 may include electrically actuating, mechanically actuating, and/or wirelessly actuating.

This is illustrated in FIGS. 24-25. In FIG. 24, sealing components 182 in the form of ball sealers are depicted as flowing within a flow of stimulant fluid 70 in downhole direction 29 within tubular conduit 42. In FIG. 25, the ball sealers 182 have engaged with the one or more first SSPs 100 that are present within first region 105 of the tubular conduit and restrict fluid flow there through. The actuating at 835 may be performed with any suitable timing and/or sequence within method 800 to deliver the first portion of the plurality of sealing components to the one or more first SSPs 100 in the open state within first region 105 of tubular conduit 42.

Positioning the downhole device at 840 may include moving the downhole device to a second region of the tubular conduit that is spaced-apart from the first region of the tubular conduit. The positioning at 840 may be accomplished in any suitable manner and may be performed similarly, or at least substantially similarly, to the positioning at 810. As illustrated in the transition from FIG. 23 to FIG. 24, the positioning at 840 may include moving downhole device 190A in an uphole direction 28 such that the downhole device is within a second region 107 of tubular conduit 42 radially interior of second section 40B of wellbore tubular 40.

Repressurizing the tubular conduit at 845 may include repressurizing with the stimulant fluid 70. The repressurizing at 845 may be performed at least substantially similar to the pressurizing at 805. When the pressurizing at 805 includes flowing and/or providing the stimulant fluid to the tubular conduit, the flowing and/or providing may be performed continuously, or at least substantially continuously, during a remainder of method 800. Under these conditions, the repressurizing at 845 may be responsive to, or a result of, operative sealing engagement between the first portion of the plurality of sealing components and the one or more first SSPs, as accomplished during the actuating at 835.

The repressurizing at 845 may be performed with any suitable timing and/or sequence within method 800. As examples, the repressurizing at 845 may be performed subsequent to the actuating at 835 and prior to the actuating at 855.

Detecting that the downhole device is in the second region of the tubular conduit at 850 may include detecting in any suitable manner. As an example, the detecting at 850 may be similar, or at least substantially similar, to the detecting at 815.

Actuating the second triggering device at 855 may include actuating to initiate explosion of a second explosive charge and/or to generate a second shockwave within the second region of the tubular conduit. The actuating at 855 may be performed in any suitable manner and may be similar, or at least substantially similar, to the actuating at 820 and may be responsive, or at least partially responsive, to the detecting at 850. The actuating at 855 is illustrated in FIG. 26. Therein, downhole device 190A is present within second region 107 of tubular conduit 42 and has initiated explosion of a second explosive charge to generate a second shockwave 194 within wellbore fluid 22 that extends within the tubular conduit 42.

Transitioning the second SSP at 860 may include transitioning one or more second SSPs from respective closed states to respective open states responsive to receipt of the second shockwave with greater than the threshold shockwave intensity by the one or more second SSPs. In general, the transitioning at 860 may be similar, or at least substantially similar, to the transitioning at 825, which is discussed herein. The transitioning at 860 is illustrated in FIG. 26. Therein, one or more second SSPs 100 that are present within second portion 107 of tubular conduit 42 are transitioned to respective open states 122 responsive to receipt of shockwave 194.

Stimulating the second region of the subterranean formation at 865 may include stimulating any suitable second region of the subterranean formation that is proximal to and/or associated with the second region of the tubular conduit. The stimulating at 865 may be at least substantially similar to the stimulating at 830 and may be responsive to, or directly responsive to, the actuating at 855 and/or the transitioning at 860. The stimulating at 865 includes flowing stimulant fluid 70 from tubular conduit 42 into subterranean formation 34 via the one or more second SSPs 100 that are present within second region 107 of the tubular conduit 42.

The stimulating at 865 may be performed with any suitable timing and/or sequence within method 800. As examples, the stimulating at 865 may be performed subsequent to the actuating at 835, subsequent to the positioning at 840 and may or may not include repositioning the downhole device uphole or downhole from the second region prior to stimulating at 865, subsequent to the repressurizing at 845, subsequent to the detecting at 850, and/or prior to the actuating at 870.

Actuating the metering device at 870 may be similar, or at least substantially similar, to the actuating at 835, which is discussed herein. The actuating at 870 includes releasing the second portion of the plurality of sealing components from the downhole device and flowing the second portion of the plurality of sealing components, via the tubular conduit, to and/or into engagement with the one or more second SSPs. Engagement between the second portion of the plurality of sealing components and the one or more second SSPs may restrict fluid flow from the tubular conduit via the one or more second SSPs. This is illustrated in FIGS. 27-28. In FIG. 27, sealing components 182 in the form of ball sealers are depicted as flowing within a flow of stimulant fluid 70 in downhole direction 29 within tubular conduit 42 from the downhole device 190A positioned within a third region 111 of the tubular conduit 42 within a third section (shown as 40C in FIG. 28) of the wellbore tubular 40. In FIG. 28, the ball sealers 182 have engaged with the one or more first SSPs 100 that are present within second region 107 of the tubular conduit and restrict fluid flow there through. The actuating at 870 may be performed with any suitable timing and/or sequence within method 800 to deliver the second portion of the plurality of sealing components to the one or more first SSPs 100 in the open state within second region 107 of tubular conduit 42 within second section 40B of the wellbore tubular 40.

The actuating at 870 may be performed with any suitable timing and/or sequence within method 800. As an example, the actuating at 870 may be performed subsequent to the positioning at 840 and may or may not include repositioning the downhole device proximal to or within the second region prior to actuating at 870, subsequent to the repressurizing at 845, subsequent to the detecting at 850, subsequent to the actuating at 855, subsequent to the transitioning at 860, and/or subsequent to the stimulating at 865.

It is understood that the methods for providing sealing components within a hydrocarbon well may be used in connection with fracturing applications and/or re-fracturing applications using a perforation gun. FIG. 29 is a flowchart depicting method 900, according to the present disclosure, of providing sealing components within a hydrocarbon well to be re-fractured. It is understood that the process with respect to re-fracturing the wellbore tubular may additionally or alternatively be used in the original fracturing of the wellbore tubular. Method 900 may include identifying an area of interest within the hydrocarbon well to be re-fractured at 910. The hydrocarbon well to be re-fractured may be a well previously perforated at spaced-apart intervals along the length of the wellbore tubular within the area of interest for re-fracturing. It is understood that the refracturing method may also be used with respect to a wellbore with SSPs in both the opened and closed state at spaced-apart intervals along the length of the wellbore tubular within the area of interest for re-fracturing. The opened SSPs to be sealed with sealing components and the closed SSPs to be opened for re-fracturing operations.

Method 900 includes positioning the downhole device proximal to or within a first region within the tubular conduit radially interior of a first section of the wellbore tubular at 920. Method 900 includes actuating the metering device at 930 to displace a first internal volume of the sealing component holder to discharge a first portion of the plurality of sealing components through the opening of the sealing component holder into the tubular conduit to sealing engage with the previous perforations within the first section of the wellbore tubular. Method 900 includes positioning the downhole device proximal to or within a second region within the tubular conduit radially interior of a second section of the wellbore tubular at 940. Method 900 includes actuating the metering device at 950 to displace a second internal volume of the sealing component holder to discharge a second portion of the plurality of sealing components through the opening of the sealing component holder into the tubular conduit to sealing engage with the previous perforations within the second section of the wellbore tubular.

Method 900 may further include pressurizing the tubular conduit with a wellbore fluid at 915 and at 935; detecting that the downhole device is proximal to or within a first region of the tubular conduit at 925 or a second region of the tubular conduit at 945; repeating the process of sealing the previous perforations (e.g., 910-950) within additional sections of the wellbore tubular until the previous perforations within the area of interest for re-fracturing have been sealed with the sealing components at 955.

Once the previous perforations within the area of interest for re-fracturing have been sealed with the sealing components, method 900 may include positioning a perforation gun within a region of the tubular conduit radially interior of an unperforated section of the wellbore tubular within the area of interest for re-fracturing at 960; positioning the downhole device within the tubular conduit or removing the downhole device from the tubular conduit such that detonation of the perforation gun does not significantly damage the downhole device at 965; detonating the perforation gun to form new perforations within the wellbore tubular at 970; positioning the downhole device proximal to or within the region of the tubular conduit radially interior of the newly perforated section of the wellbore tubular (a first newly perforated section) at 975; displacing an additional internal volume of the sealing component holder of the downhole device to discharge an additional portion of the plurality of sealing components from within an additional region of the sealing component holder through the opening of the sealing component holder to seal the new perforations within the newly perforated section of the wellbore tubular (first newly perforated section) at 980; and repeating the perforation process for re-fracturing (e.g., 960-980) until the re-fracturing of the wellbore tubular within the area of interest has been completed at 985. FIG. 30 illustrates a configuration for re-fracturing using the perforation gun 162 (depicted after detonation showing damage) to provide new perforations 163 within region 161 of the tubular conduit 42 radially interior of the newly perforated section 40D of the wellbore tubular 40 with the downhole device 190 positioned uphole of the perforation gun 162. Sealing components 182 are shown within the previously formed perforations. Although not depicted, alternatively the downhole device 190 may be integral with the perforation gun 162 forming a single device having the downhole device 190 section positioned on top of the perforation gun 162 section. The opening to the sealing component holder may be located in the side or top of the device. This embodiment allows a single unit to be utilized with perforation operations.

As an example, sealing the previous perforations during re-fracturing a hydrocarbon well may include using a sealing component holder including at least a first plurality of degradable sealing components within a first region of the sealing component holder occupying the first internal volume and a second plurality of degradable sealing components within a second region of the sealing component holder occupying the second internal volume. The sealing component holder may have additional regions occupying additional internal volumes of the sealing component holder and including additional pluralities of degradable sealing components. The first plurality of sealing components, the second plurality of sealing components, and any additional pluralities of sealing components may have different degradation rates. As an example, the first region proximal the opening of the sealing component holder contains a first plurality of degradable sealing components with the greatest rate of degradation and the region within the sealing component holder furtherest from the opening contains a plurality of degradable sealing components with the lesser rate of degradation. As an example, the first plurality of degradable sealing components may have a different rate of degradation than the second plurality of degradable sealing components.

It is understood that the methods for providing sealing components within a well may be used within an injection well used in connection with hydrocarbon production. An injection well may be used to assist in sustaining formation pressure within the reservoir and provide fluid to sweep the subterranean formation and push hydrocarbons within the reservoir (reservoir fluid) towards a neighboring hydrocarbon production well. FIG. 31 is a flowchart depicting method 1100, according to the present disclosure, of providing sealing components within an injection well to temporarily seal portions of the subterranean formation to divert the wellbore fluid within the injection well to other areas within the well and surrounding subterranean formation. Method 1100 may include identifying sections of an injection well for which a wellbore fluid, such as an injection fluid may be diverted to one or more other sections of such well at 1110. The injection fluid may be predominantly water, predominantly carbon dioxide, as well as other suitable fluids. As an example, the identified injection well may include at least two sections of the wellbore tubular that are ineffectively providing injection fluid into the subterranean formation to provide pressure. Each of the at least two sections are spaced apart from each other along the length of the wellbore tubular. Such sections may be identified using core samples, tracers, and/or production logs to determine where the injection fluid is exiting the wellbore such that the injection fluid is well swept and ineffective in providing pressure to the reservoir. Associated with each section of the wellbore tubular is a radially interior region within the conduit, such as a first region within the tubular conduit associated with the first section of the wellbore tubular and a second region within the tubular conduit associated with the second section of the wellbore tubular. The injection well also includes at least a third region within the tubular conduit associated with the third section of the wellbore tubular. Each section of the wellbore tubular is also associated with a radially exterior region of the subterranean formation.

Method 1100 includes positioning the downhole device proximal to or within a region (e.g., the first region or the second region) of the tubular conduit at 1105 and providing a first portion of the plurality of sealing components, such as chemical diverters or ball sealers, into the tubular conduit of the wellbore tubular, and sealing the subterranean formation proximate the section with chemical diverters or openings within the wellbore tubular with ball sealers at 1120. The sealing includes actuating a metering device to displace a first internal volume of the sealing component holder to discharge a first portion of the plurality of sealing components, such as chemical diverters or ball sealers, through the opening within the sealing component holder into the tubular conduit. Method 1100 includes positioning the downhole device proximal to or within another region of the tubular conduit at 1125 and sealing another of the sections (e.g., other of the first region or the second region not yet sealed) of the wellbore tubular with a second portion or the plurality of sealing components as 1130. Additional ineffective sections of the injection well may be identified and provided additional portions of the plurality of sealing components to divert the injection fluid into other sections not taking in sufficient injection fluid to strategically increase the pressure within the reservoir and maintain production.

FIG. 32 illustrates an injection well 11. The wellbore tubular 40 includes a first section 40A of the wellbore tubular 40, a second section 40B of the wellbore tubular 40, and a third section 40C of the wellbore tubular 40. A first region 105 within the tubular conduit 42 is radially interior of the first section 40A of the wellbore tubular 40, a second region 107 within the tubular conduit 42 is radially interior of the second section 40B of the wellbore tubular 40, and a third region 111 within the tubular conduit 42 is radially interior of the third section 40C of the wellbore tubular 40. The first section 40A, the second section 40B, and the third section 40C of the wellbore tubular 40 contain perforations 163. Downhole device 190 is positioned within the tubular conduit 42 proximate the second region 107 of the tubular conduit 42 proximal the first section 40A of the wellbore tubular 40 and used to seal off the subterranean formation 34 proximate the first section 40A of the wellbore tubular 40 from the tubular conduit 42 and the injection fluid.

In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, it is within the scope of the present disclosure that the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently. It is also within the scope of the present disclosure that the blocks, or steps, may be implemented as logic, which also may be described as implementing the blocks, or steps, as logics. In some applications, the blocks, or steps, may represent expressions and/or actions to be performed by functionally equivalent circuits or other logic devices. The illustrated blocks may, but are not required to, represent executable instructions that cause a computer, processor, and/or other logic device to respond, to perform an action, to change states, to generate an output or display, and/or to make decisions.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

As used herein, the phrase, “for example,” the phrase, “as an example,” and/or simply the term “example,” when used with reference to one or more components, features, details, structures, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, embodiment, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, embodiments, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, embodiments, and/or methods, are also within the scope of the present disclosure.

INDUSTRIAL APPLICABILITY

The downhole devices, wells, and methods disclosed herein are applicable to the oil and gas industry.

It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.

Claims

1. A downhole device for providing sealing components within a well comprising: a core;a sealing component holder positioned within the core including an opening to an external surface of the core;a plurality of sealing components positioned within the sealing component holder;a metering device constructed and arranged to displace an internal volume of the sealing component holder and discharge through the opening a portion of the plurality of sealing components contained within the sealing component holder; anda cover positioned over the opening, the cover constructed and arranged to allow the portion of the sealing components to exit the opening upon displacement of the internal volume of the sealing component holder.

2. The device of claim 1, wherein the sealing component holder is positioned at least proximal the distal end of the core.

3. The device of claim 1, wherein the plurality of sealing components are ball sealers or chemical diverters.

4. The device of claim 1, wherein the plurality of sealing components are ball sealers.

5. The device of claim 4, wherein the sealing component holder includes a plurality of spaced-apart regions, each region including a plurality of ball sealers, the plurality of ball sealers within one region having a substantially different rate of degradation than the plurality of ball sealers in each adjacent region.

6. The device of claim 4, wherein the well includes a wellbore tubular forming a tubular conduit having in inner diameter in the range of from 90 mm to 178 mm, and wherein the sealing component holder and metering device are placed proximal the distal end of the core and a portion of the plurality of the ball sealers have a maximum outer dimension greater than 32 mm.

7. The device of claim 6, wherein a portion of the plurality of the ball sealers have a maximum outer dimension of less than 15 mm.

8. The device of claim 4, wherein a portion of the plurality of the ball sealers have a maximum outer dimension of less than 15 mm.

9. The device of claim 1, wherein the plurality of sealing components are chemical diverters which are selected from benzoic acid flakes, polyglycolic acid polymer beads, and polylactic acid polymer beads.

10. The device of claim 1, wherein the metering device includes a pump or a motor operatively connected to a member positioned within the sealing component holder such that, upon actuation of the pump or motor, the member displaces an internal volume of the sealing component holder.

11. The device of claim 1, wherein the metering device includes a pump operatively connected to the sealing component holder such that, upon actuation of the pump, a displacement fluid is introduced into an inlet of the sealing component holder displacing an internal volume of the sealing component holder.

12. The device of claim 11, wherein the metering device includes a pump and the pump is a solid state, piezoelectric pump.

13. A method for providing sealing components within a well including a wellbore and a wellbore tubular extending within the wellbore, the wellbore tubular defining a tubular conduit, the method comprising: positioning a downhole device proximal to or within a first region within the tubular conduit radially interior of a first section of the wellbore tubular, the downhole device comprising:a core,a sealing component holder positioned within the core including an opening to an external surface of the core,a plurality of sealing components positioned within the sealing component holder,a metering device constructed and arranged to displace an internal volume of the sealing component holder and discharge sealing components through the opening, anda cover positioned over the opening, the cover constructed and arranged to allow the sealing components to exit the opening upon displacement of the internal volume of the sealing component holder;actuating the metering device to displace a first internal volume of the sealing component holder to discharge a first portion of the plurality of sealing components through the opening into the tubular conduit;positioning the downhole device proximal to or within a second region within the tubular conduit radially interior of a second section of the wellbore tubular, the second region spaced apart from the first region along the length of the wellbore tubular; andactuating the metering device to displace a second internal volume of the sealing component holder to discharge a second portion of the plurality of sealing components through the opening into the tubular conduit.

14. The method of claim 13, wherein the downhole device includes a plurality of explosive charges arranged on an external surface of the core and a plurality of triggering devices, each of the plurality of triggering devices is constructed and arranged to selectively initiate explosion of a selected portion of the plurality of explosive charges; and wherein the wellbore tubular includes a plurality of selective stimulation ports disposed along a length of the wellbore tubular; and wherein the method further comprises: actuating a first triggering device of the plurality of triggering devices to initiate explosion of a first portion of the plurality of explosive charges to generate a first shockwave within the first region of the tubular conduit to transition a first portion of the selective stimulation ports to an open state; andactuating a second triggering device of the plurality of triggering devices to initiate explosion of a second portion of the plurality of explosive charges to generate a second shockwave within the second region of the tubular conduit to transition a second portion of the selective stimulation ports to an open state, wherein the first portion of the plurality of sealing components seal the first portion of the selective stimulation ports and the second portion of the plurality of sealing components seal the second portion of the selective stimulation ports.

15. The method of claim 13, wherein the sealing component holder forms a majority of an internal volume of the core, the wellbore tubular has been previously perforated at spaced-apart intervals along its length, and at least a portion of the plurality of the sealing components are used to seal the previously perforated spaced-apart intervals within a re-fracturing area of interest along the length of the wellbore tubular.

16. The method of claim 15, wherein the plurality of sealing components includes at least a first plurality of degradable sealing components within a first region of the sealing component holder occupying the first internal volume and a second plurality of degradable sealing components within a second region of the sealing component holder occupying the second internal volume, the first plurality of degradable sealing components having a different rate of degradation than the second plurality of degradable sealing components, and wherein the first section of the wellbore tubular is one of the previously perforated spaced-apart intervals along the length of the wellbore tubular and the second section of the wellbore tubular is another of the previous spaced-apart intervals along the length of the wellbore tubular.

17. The method of claim 16, further comprising: positioning a perforation gun within a region of the tubular conduit radially interior of an unperforated section of the wellbore tubular within the re-fracturing area of interest after the previously perforated spaced-apart intervals have been sealed with degradable sealing components,positioning the downhole device such that detonation of the perforation gun does not significantly damage the downhole device;detonating the perforation gun to form new perforations within the unperforated section of the wellbore tubular,positioning the downhole device proximal to or within the region of the tubular conduit radially interior of newly perforated section of the wellbore tubular,displacing an additional internal volume of the sealing component holder to discharge an additional portion of the plurality of sealing components through the opening, wherein the additional internal volume includes a plurality of non-degradable sealing components within an additional region of the sealing component holder.

18. The method of claim 17, wherein the positioning, detonating, and displacing are continued until the re-fracturing of the wellbore tubular within the area of interest is completed.

19. The method of claim 13, wherein the well is an injection well and includes at least three sections of the wellbore tubular that are passing injection fluid into the subterranean formation to create pressure and displace hydrocarbons within the reservoir to assist a hydrocarbon well producing hydrocarbons, the at least three sections include the first section, the second section, and a third section of the wellbore tubular, each of the at least three sections spaced apart from each other along the length of the wellbore tubular, and wherein the subterranean formation proximate the first section and the second section is sealed such that the injection fluid is diverted to the subterranean formation proximate the third section of the wellbore tubular.

20. The method of claim 19, the method further comprises: identifying locations of the first section and the second section using production logs to determine the sections of the injection well that are ineffective in creating pressure within the reservoir.

21. A well comprising: a wellbore;a wellbore tubular extending within the wellbore, the wellbore tubular defining a tubular conduit; anda downhole device disposed within the tubular conduit, the downhole device comprising:a core;a sealing component holder positioned within the core including an opening to an external surface of the core;a plurality of sealing components positioned within the sealing component holder;a metering device constructed and arranged to displace an internal volume of the sealing component holder and discharge through the opening a portion of the plurality of sealing components contained within the sealing component holder; anda cover positioned over the opening, the cover constructed and arranged to allow the portion of the sealing components to exit the opening upon displacement of the internal volume of the sealing component holder.