US20170159419A1

US20170159419A1 - Selective Stimulation Ports, Wellbore Tubulars That Include Selective Stimulation Ports, And Methods Of Operating The Same

Info

Publication number: US20170159419A1
Application number: US15/264,052
Authority: US
Inventors: Randy C. Tolman; P. Matthew Spiecker; Steve Lonnes; Timothy J. Hall
Original assignee: Individual
Current assignee: Individual
Priority date: 2015-12-02
Filing date: 2016-09-13
Publication date: 2017-06-08
Also published as: US20170159418A1; US10221669B2

Abstract

Selective stimulation ports (SSPs), wellbore tubulars that include the SSPs, and methods of operating the same are disclosed herein. The SSPs are configured to be operatively attached to a wellbore tubular and include an SSP body, an isolation device extending within an SSP conduit of the SSP body, a retention device coupling the isolation device to the SSP body, and a sealing device seat. The isolation device is configured to selectively transition from a closed state to an open state responsive to a shockwave, which has greater than a threshold shockwave intensity, within a wellbore fluid that extends within a tubular conduit of the wellbore tubular. The methods include generating the shockwave within the wellbore fluid such that the shockwave has greater than the threshold shockwave intensity. The methods further include transitioning the isolation device from the closed state to the open state responsive to receipt of the shockwave.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser. No. 62/262,034 filed Dec. 2, 2015, entitled, “Selective Stimulation Ports, Wellbore Tubulars That Include Selective Stimulation Ports, and Methods of Operating the Same,” the disclosure of which is incorporated herein by reference in its entirety.
This application is related to U.S. Provisional Application Ser. No. 62/262,036 filed Dec. 2, 2015, entitled, “Wellbore Tubulars Including A Plurality of Selective Ports and Methods of Utilizing the Same,” (Attorney Docket No. 2015EM361); U.S. Provisional Application Ser. No. 62/263,065 filed Dec. 4, 2015, entitled, “Wellbore Ball Sealer and Methods of Utilizing the Same,” (Attorney Docket No. 2015EM369); U.S. Provisional Application Ser. No. 62/263,067 filed Dec. 4, 2015, entitled, “Ball-Sealer Check-Valves for Wellbore Tubulars and Methods of Utilizing the Same,” (Attorney Docket No. 2015EM370); U.S. Provisional Application Ser. No. 62/263,069 filed Dec. 4, 2015, entitled, “Select-Fire, Downhole Shockwave Generation Devices, Hydrocarbon Wells That Include the Shockwave Generation Devices, and Methods of Utilizing the Same,” (Attorney Docket No. 2015EM371); and U.S. Provisional Application Ser. No. 62/329690 filed Apr. 29, 2016, entitled, “System and Method for Autonomous Tools,” (Attorney Docket No. 2016EM104), the disclosures of which are incorporated herein by reference in their entireties.

FIELD OF THE DISCLOSURE

The present disclosure is directed generally to selective stimulation ports, to wellbore tubulars that include selective stimulation ports, and to methods of operating the same.

BACKGROUND OF THE DISCLOSURE

Hydrocarbon wells generally include a wellbore that extends from a surface region and/or that extends within a subterranean formation that includes a 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 to the subterranean formation to acid-treat the subterranean formation and/or to dissolve at least a portion of the subterranean formation. As another example, the stimulation may include fracturing the subterranean formation, such as by supplying a fracturing fluid, which is pumped at a high pressure, to 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/or methods have been developed to facilitate stimulation of subterranean formations, and each of these systems and methods generally has inherent benefits and drawbacks. These systems and methods often utilize a shape charge perforation gun to create perforations within a casing string that extends within the wellbore, and the stimulant fluid then is provided to the subterranean formation via the perforations. However, such systems suffer from a number of limitations. As an example, the perforations may not be round or may have burrs, which may make it challenging to seal the perforations subsequent to stimulating a given region of the subterranean formation. As another example, the perforations often will erode and/or corrode due to flow of the stimulant fluid, flow of proppant, and/or long-term flow of reservoir fluid therethrough. This may make it challenging to seal the perforations and/or may change fluid flow characteristics therethrough. These challenges may occur early in the life of the hydrocarbon well, such as during and/or after completion thereof, and/or later in the life of the hydrocarbon well, such as after production of the reservoir fluid with the hydrocarbon well and/or during and/or after restimulation of the hydrocarbon well. As yet another example, it may be challenging to precisely locate, size, and/or orient perforations, which are created utilizing the shape charge perforation gun, within the casing string. Thus, there exists a need for improved systems and methods for stimulating a subterranean formation, such as may be facilitated utilizing the selective stimulation ports disclosed herein.

SUMMARY OF THE DISCLOSURE

Selective stimulation ports (SSPs), wellbore tubulars that include the SSPs, and methods of operating the same are disclosed herein. The SSPs are configured to be operatively attached to a wellbore tubular that defines a tubular conduit. The wellbore tubular is configured to extend within a wellbore that extends within a subterranean formation. The SSPs include an SSP body, an isolation device extending within an SSP conduit of the SSP body, a retention device coupling the isolation device to the SSP body, and a sealing device seat. The SSP body has a conduit-facing region and a formation-facing region, and the SSP conduit extends between the conduit-facing region and the formation-facing region.
The isolation device is configured to selectively transition from a closed state, in which the isolation device restricts fluid flow through the SSP conduit, to an open state, in which the isolation device permits fluid flow through the SSP conduit. The transition is responsive to a shockwave, which has greater than a threshold shockwave intensity, within a wellbore fluid that extends within a tubular conduit of the wellbore tubular and proximate the SSP.
The retention device retains the isolation device in the closed state prior to receipt of the shockwave. The sealing device seat is defined by the conduit-facing region of the SSP body and is shaped to form a fluid seal with a sealing device, such as a ball sealer, when the sealing device is engaged with the sealing device seat. The fluid seal selectively restricts fluid flow from the tubular conduit to the subterranean formation via the SSP conduit.
The methods include generating the shockwave within the wellbore fluid such that the shockwave has greater than the threshold shockwave intensity in a region of the tubular conduit that is proximal the SSP. The methods further include transitioning the isolation device from the closed state to the open state responsive to receipt of the shockwave and thereafter stimulating the subterranean formation proximate the conduit-facing region of the SSP.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of examples of a hydrocarbon well that may include and/or utilize selective stimulation ports, wellbore tubulars, and/or methods according to the present disclosure.

FIG. 2 is a schematic representation of selective stimulation ports according to the present disclosure.

FIG. 3 is a less schematic cross-sectional view of selective stimulation ports according to the present disclosure.

FIG. 4 is another less schematic cross-sectional view of selective stimulation ports according to the present disclosure.

FIG. 5 is another less schematic cross-sectional view of selective stimulation ports according to the present disclosure.

FIG. 6 is another less schematic cross-sectional view of a selective stimulation port according to the present disclosure installed on a wellbore tubular.

FIG. 7 is a less schematic profile view of a selective stimulation port according to the present disclosure.

FIG. 8 is a view of a formation-facing side of the selective stimulation port of FIG. 7.

FIG. 9 is a cross-sectional view of the selective stimulation port of FIGS. 7-8 taken along line 9-9 of FIG. 8.

FIG. 10 is a flowchart depicting methods, according to the present disclosure, of stimulating a subterranean formation.

FIG. 11 is a schematic cross-sectional view of a portion of a process flow for stimulating a subterranean formation utilizing the selective stimulation ports, wellbore tubulars, and/or methods according to the present disclosure.

FIG. 12 is a schematic cross-sectional view of a portion of the process flow for stimulating the subterranean formation utilizing the selective stimulation ports, wellbore is tubulars, and/or methods according to the present disclosure.

FIG. 13 is a schematic cross-sectional view of a portion of the process flow for stimulating the subterranean formation utilizing the selective stimulation ports, wellbore tubulars, and/or methods according to the present disclosure.

FIG. 14 is a schematic cross-sectional view of a portion of the process flow for stimulating the subterranean formation utilizing the selective stimulation ports, wellbore tubulars, and/or methods according to the present disclosure.

FIG. 15 is a schematic cross-sectional view of a portion of the process flow for stimulating the subterranean formation utilizing the selective stimulation ports, wellbore tubulars, and/or methods according to the present disclosure.

FIG. 16 is a schematic cross-sectional view of a portion of the process flow for stimulating the subterranean formation utilizing the selective stimulation ports, wellbore tubulars, and/or methods according to the present disclosure.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

FIGS. 1-16 provide examples of selective stimulation ports (SSPs) 100, according to the present disclosure, of wellbore tubulars 40 that include and/or utilize the selective stimulation ports, of hydrocarbon wells 10 that include and/or utilize the wellbore tubulars, and/or of methods 200 and/or process flows 300, according to the present disclosure, for stimulating a subterranean formation. Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of FIGS. 1-16, and these elements may not be discussed in detail herein with reference to each of FIGS. 1-16. Similarly, all elements may not be labeled in each of FIGS. 1-16, 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. 1-16 may be included in and/or utilized with any of FIGS. 1-16 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 are 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 examples of a hydrocarbon well 10 that may include and/or utilize selective stimulation ports 100, wellbore tubulars 40, and/or methods 200 according to the present disclosure. Hydrocarbon well 10 includes a wellbore 20 that extends from a surface region 30, within a subsurface region 32, within a subterranean formation 34 of subsurface region 32, and/or between the surface region and the subterranean formation. 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 from the subterranean formation and/or to the surface region.
Hydrocarbon well 10 further includes wellbore tubular 40, which extends within wellbore 20 and defines a tubular conduit 42. Wellbore tubular 40 includes a plurality of selective stimulation ports (SSPs) 100, which are discussed in more detail herein. SSPs 100 are illustrated in dashed lines in FIG. 1 to indicate that the SSPs may be operatively attached to and/or may form a portion of any suitable component of wellbore tubular 40.
Wellbore tubular 40 may include and/or be any suitable tubular that may be present, located, and/or extended within wellbore 20. As examples, wellbore tubular 40 may include and/or be a casing string 50 and/or inter-casing tubing 60, which may be configured to extend within the casing string. SSPs 100 may be configured to be operatively attached to wellbore tubular 40, such as to casing string 50 and/or inter-casing tubing 60, prior to the wellbore tubular being located, placed, and/or installed within wellbore 20.
When wellbore tubular 40 includes casing string 50, SSPs 100 may be operatively attached to any suitable portion of the casing string. As examples, and as illustrated, one or more SSPs 100 may be operatively attached to one or more of a casing segment 52 of the casing string, such as a sub or pup joint of the casing string, a casing collar 54 of the casing string, a blade centralizer 56 of the casing string, and/or a sleeve 58 that extends around the outer surface of the casing string.
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 welded connection, and/or a brazed connection.
As illustrated in dashed lines in FIG. 1, hydrocarbon well 10 also may include and/or have associated therewith an optional shockwave generation device 190. Shockwave generation device 190 may be configured to generate a shockwave 194 within tubular conduit 42, as discussed in more detail herein. Shockwave generation device 190 may include and/or be any suitable structure that may, or may be utilized to, generate the shockwave within tubular conduit 42. As an example, shockwave generation device 190 may be an umbilical-attached shockwave generation device 190 that may be operatively attached to, or may be positioned within tubular conduit 42 via, an umbilical 192, such as a wireline, a tether, tubing, and/or coiled tubing. As another example, shockwave generation device 190 may be an autonomous shockwave generation device that may be flowed into and/or within tubular conduit 42 without an attached umbilical. As yet another example, the shockwave generation device may form a portion of one or more SSPs 100 and may be referred to as a shockwave generation structure 180, as discussed in more detail herein with reference to FIG. 2. As additional examples, shockwave generation device 190 may include an explosive charge, such as a length of primer cord and/or a blast cap. Primer cord also may be referred to herein as detonation cord and/or detonating cord and may be configured to explode and/or detonate.
FIGS. 2-9 provide examples of SSPs 100 according to the present disclosure. FIGS. 2-9 may be more detailed illustrations of SSPs 100 of FIG. 1, and any of the structures, functions, and/or features that are discussed and/or illustrated herein with reference to any of FIGS. 2-9 may be included in and/or utilized with SSPs 100 of FIG. 1 without departing from the scope of the present disclosure. Similarly, any of the structures, functions, and/or features that are discussed and/or illustrated herein with reference to hydrocarbon wells 10 and/or wellbore tubulars 40 of FIG. 1 may be included in and/or utilized with SSPs 100 of FIGS. 2-9 without departing from the scope of the present disclosure.
As illustrated in FIGS. 2-5, SSPs 100 include an SSP body 110 including a conduit-facing region 112, which is configured to face toward tubular conduit 42 when SSP 100 is installed within wellbore tubular 40. SSPs 100 also include a formation-facing region 114, which is configured to face toward subterranean formation 34 when the SSP is installed within the wellbore tubular and the wellbore tubular extends within the subterranean formation. SSP body 110 further includes and/or defines an SSP conduit 116, which extends between conduit-facing region 112 and formation-facing region 114. As discussed in more detail herein, SSP conduit 116 may selectively establish a fluid flow path between tubular conduit 42 and subterranean formation 34.
SSP 100 also includes an isolation device 120. Isolation device 120 extends within and/or across SSP conduit 116 and is configured to selectively transition, or to be selectively transitioned, from a closed state 121, as illustrated in FIGS. 2-4 and 9, to an open state 122, as illustrated in FIGS. 3-6. When isolation device 120 is in closed state 121, the isolation device restricts, blocks, and/or occludes fluid flow within the SSP conduit, through the SSP conduit, and/or between tubular conduit 42 and subterranean formation 34 via the SSP conduit. Conversely, and when isolation device 120 is in open state 122, the isolation device permits, facilitates, does not restrict, does not block, and/or does not occlude the fluid flow within the SSP conduit, through the SSP conduit, and/or between tubular conduit 42 and subterranean formation 34 via the SSP conduit. Transitioning isolation device 120 from the closed state to the open state also may be referred to herein as transitioning SSP 100 from the closed state to the open state and/or as transitioning SSP conduit 116 from the closed state to the open state.
Isolation device 120 is configured to transition from the closed state to the open state responsive to, or responsive to experiencing, a shockwave that has greater than a threshold shockwave intensity. A shockwave that has greater than the threshold shockwave intensity may be referred to herein as a threshold shockwave, a triggering shockwave, and/or a transitioning shockwave. The shockwave may be generated by a shockwave generation structure 180, which may be present within and/or may form a portion of SSP 100 and is illustrated in FIG. 2, and/or by a shockwave generation device 190, which may be separated and/or distinct from SSP 100 and is illustrated in FIG. 1. The shockwave may be generated within a wellbore fluid 22 and may be propagated from the shockwave generation device or the shockwave generation structure to the SSP via the wellbore fluid. Examples of the wellbore fluid include reservoir fluid 36 and/or a stimulant fluid, as discussed in more detail herein.
SSP 100 further includes a retention device 130, as illustrated in FIGS. 2-4 and 9. Retention device 130 is configured to couple, or operatively couple, isolation device 120 to SSP body 110, such as to retain the isolation device in the closed state prior to receipt of the threshold shockwave. Retention device 130 optionally may be configured to permit and/or facilitate transitioning of isolation device 120 from the closed state to the open state responsive to receipt of the threshold shockwave.
SSP 100 also includes a sealing device seat 140, as illustrated in FIGS. 2-5 and 9. Sealing device seat 140 may be defined by conduit-facing region 112 of SSP body 110. In addition, sealing device seat 140 may be shaped to form a fluid seal 144 with a sealing device 142, as illustrated in FIGS. 2 and 9. The sealing device may be positioned on and/or in contact with the sealing device seat, such as to form the fluid seal, by flowing, via tubular conduit 42, into engagement with the sealing device seat. When the sealing device is engaged with the sealing device seat to form the fluid seal, the sealing device restricts, or selectively restricts, fluid flow from tubular conduit 42 to subterranean formation 34 via SSP conduit 116.
As discussed in more detail herein, wellbore tubulars 40 may have one or more SSPs 100 operatively attached thereto prior to the wellbore tubular being located, placed, and/or positioned within the wellbore. The SSPs may be in the closed state during operative attachment to the wellbore tubular and/or while the wellbore tubular is positioned within the wellbore. Subsequently, shockwave generation structure 180 of FIG. 2 and/or shockwave generation device 190 of FIG. 1 may be utilized to generate the shockwave within the wellbore fluid that extends within the tubular conduit and/or that extends in fluid communication with the isolation device. The shockwave may propagate within the wellbore fluid and/or to the SSP and may be received and/or experienced by at least a portion of the one or more SSPs.
However, the shockwave also is attenuated, is dampened, and/or decays as it propagates within the wellbore fluid. Thus, the shockwave will only have greater than the threshold shockwave intensity within a specific region of the wellbore tubular, and the one or more SSPs will only transition from the closed state to the open state if the one or more SSPs is located within this specific region of the wellbore tubular (i.e., if the shockwave has greater than the threshold shockwave intensity when the shockwave reaches, or contacts, the one or more SSPs). Thus, individual, selected, and/or specific SSPs 100 may be transitioned from the closed state to the open state without transitioning, or concurrently transitioning, other SSPs that are outside, or that are not within, the specific region of the wellbore tubular. Such a configuration may permit SSPs 100, according to the present disclosure, to be more selectively actuated, via the shockwave, when compared to more universally applied pressure spikes, which may act upon an entirety of a length of the wellbore tubular.
The shockwave may be attenuated, within the wellbore fluid, at any suitable (non-zero) shockwave attenuation rate. As examples, the shockwave attenuation rate may be 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, or at least 20 MPa/m.
The shockwave also may have any suitable (non-zero) shockwave intensity, which also may be referred to herein as a peak shockwave pressure and/or as a maximum shockwave pressure. As examples, the shockwave intensity may be 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.
Similarly, the shockwave may have any suitable duration, which also may be referred to herein as a maximum duration, a shockwave duration, and/or a maximum shockwave duration. Examples of the maximum duration include durations 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 has greater than the threshold shockwave intensity within the wellbore tubular. 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 wellbore tubular.
With the above in mind, the shockwave may exhibit greater than the threshold shockwave intensity over only a fraction of a length of the wellbore tubular and only for a brief period of time. As examples, the shockwave may exhibit greater than the threshold shockwave intensity over a maximum effective distance of 1 meter, 2 meters, 3 meters, 4 meters, 5 meters, 6 meters, 7 meters, 8 meters, 10 meters, 15 meters, 20 meters, or 30 meters along a length of the tubular conduit. Stated another way, the shockwave may have a peak shockwave intensity proximate an origination point thereof (i.e., proximate the shockwave generation device, the shockwave generation structure, and/or a shockwave generation source thereof). The threshold shockwave intensity may be less than, or less than a threshold fraction of, the peak shockwave intensity, and an intensity of the shockwave may be less than the threshold shockwave intensity at distances that are greater than the maximum effective distance from the origination point.
The shockwave generation structure and/or the shockwave generation device may be configured such that the shockwave emanates symmetrically, or at least substantially symmetrically, therefrom. Stated another way, the shockwave generation structure and/or the shockwave generation device may be configured such that the shockwave emanates isotropically, or at least substantially isotropically, therefrom. Stated yet another way, the shockwave generation structure and/or the shockwave generation device may be configured such that the shockwave is symmetric, or at least substantially symmetric, within a given transverse cross-section of the wellbore tubular.
SSP body 110 may include any suitable structure that may have, include, and/or define conduit-facing region 112, formation-facing region 114, and/or SSP conduit 116. In addition, SSP body 110 may be formed from any suitable material, and the SSP body may be formed from a different material than a material of wellbore tubular 40, than a material of a majority of wellbore tubular 40, and/or than a material that comprises a portion of wellbore tubular 40 that is operatively attached to SSP body 110.
It is within the scope of the present disclosure that SSP body 110 may be a single-piece, or monolithic, SSP body 110. Alternatively, it also is within the scope of the present disclosure that SSP body 110 may be a composite SSP body 110 that may be formed from a plurality of distinct, separate, and/or chemically different components.
As illustrated in dashed lines in FIG. 2, SSP body 110 may be separate from, distinct from, and/or may be formed from a different material than wellbore tubular 40. Under these conditions, SSP body 110 may be configured to be operatively attached to the wellbore tubular with the SSP body extending through a tubular aperture 48 that may be defined within the wellbore tubular and/or that may extend between tubular conduit 42 and an external surface 41 of the wellbore tubular. In such a configuration, SSP 100 and/or SSP body 110 thereof may include a projecting region 150 that may be configured to project past tubular aperture 48. The projecting region may project transverse, or perpendicular to, a central axis 118 of SSP conduit 116. Stated another way, at least a portion of SSP 100 and/or SSP body 110 thereof may have a maximum outer diameter that is greater than an inner diameter of tubular aperture 48. In such a configuration, wellbore tubular 40 may define a recess 46 that may be configured to receive projecting region 150.
Additionally or alternatively, SSP body 110 also may be at least partially defined by wellbore tubular 40 and/or by any suitable component thereof. As examples, SSP body 110 may be partially, or even completely, defined by casing string 50, casing segment 52, casing collar 54, blade centralizer 56, sleeve 58, and/or inter-casing tubing 60 of FIG. 1.
As illustrated in FIG. 2, SSP 100 and/or SSP body 110 thereof may be configured such that the SSP does not extend into tubular conduit 42 and/or such that the SSP does not extend, or project, past an internal surface 43 of wellbore tubular 40 that defines tubular conduit 42. Stated another way, conduit-facing region 112 of SSP body 110 and/or sealing device seat 140 of SSP 100 may be flush with internal surface 43 and/or may be recessed within tubular aperture 48, when present. Thus, SSP 100 may not block and/or restrict fluid flow within tubular conduit 42 and/or the presence of SSP 100 may not change a transverse cross-sectional area for fluid flow within tubular conduit 42.
Stated yet another way, a transverse cross-sectional area of a portion of the tubular conduit that includes one or more SSPs may be at least a threshold fraction of a transverse cross-sectional area of a portion of the tubular conduit that does not include an SSP, or any SSPs. Examples of the threshold fraction of the transverse cross-sectional area include threshold fractions of at least 80 percent, at least 85 percent, at least 90 percent, at least 92.5 percent, at least 95 percent, at least 96 percent, at least 97 percent, at least 98 percent, or at least 99 percent of the transverse cross-sectional area.
As discussed in more detail herein, conventional stimulation methods may utilize a shape charge perforation device to create, generate, and/or define one or more perforations within a casing string that extends within a subterranean formation. As also discussed, such perforations may not be symmetrical, may not be round, and/or may not form a fluid-tight seal with a sealing device, such as a ball sealer. In addition, and as also discussed, stimulation of the subterranean formation may include flowing a stimulant fluid that may include particulate material through the perforations, which may be abrasive to the perforations, and/or flowing a stimulant fluid that may include a corrosive material through the perforations, which may corrode the perforations. Additionally or alternatively, long-term flow of the reservoir fluid through the perforations also may corrode the perforations. Thus, flow of the stimulant fluid through the perforations further may change the shape of the perforations. This change in shape further may decrease an ability for the perforations to form a fluid-tight seal with the sealing device and/or may cause an increase in a cross-sectional area for fluid flow through the perforations, thereby increasing a flow rate of the stimulant fluid through the perforations for a given pressure drop thereacross. Either situation may be detrimental to, may decrease a reliability of, and/or may increase a complexity of stimulation operations that utilize perforations created by shape charge perforation devices.
With this in mind, SSPs 100 according to the present disclosure may include an SSP body 110 that is at least partially erosion-resistant and/or corrosion-resistant, or at least more erosion-resistant and/or corrosion-resistant than wellbore tubular 40. As an example, SSP body 110 may include and/or be an erosion-resistant SSP body that may be configured to resist erosion by the particulate material. As a more specific example, the SSP body may include an erosion-resistant material that is more resistant to erosion than a material forming a portion of the wellbore tubular to which the SSP is attached. The erosion-resistant material may form at least a portion of any suitable region and/or component of SSP body 110. As examples, the erosion-resistant material may form at least a portion of conduit-facing region 112, formation-facing region 114, sealing device seat 140, and/or an internal portion of SSP body 110 that defines SSP conduit 116.
It is within the scope of the present disclosure that the erosion-resistant material may form and/or define the entire, or an entirety of, SSP body 110. Alternatively, it also is within the scope of the present disclosure that the erosion-resistant material may form only a portion, a subset, or less than an entirety of the SSP body and/or that the erosion-resistant material may be different from a material of a remainder of the SSP body. As an example, the erosion-resistant material may include and/or be an erosion-resistant sleeve 111 that is operatively attached to the SSP body and/or an erosion-resistant coating 113 that covers at least a portion of the SSP body. As another example, the erosion-resistant material may include and/or be an erosion-resistant layer, coating, and/or ring that is operatively attached to and/or forms all or a portion of sealing device seat 140.
As another example, SSP body 110 may include and/or be a corrosion-resistant SSP body that may be configured to resist corrosion by, within, or while in contact with, the stimulant fluid, such as a stimulant fluid that includes, or is, an acid. As a more specific example, the SSP body may include a corrosion-resistant material that is more resistant to corrosion than a material forming a portion of the wellbore tubular to which the SSP is attached. The corrosion-resistant material may form at least a portion of any suitable region and/or component of SSP body 110. As examples, the corrosion-resistant material may form at least a portion of conduit-facing region 112, formation-facing region 114, sealing device seat 140, and/or an internal portion of SSP body 110 that defines SSP conduit 116.
It is within the scope of the present disclosure that the corrosion-resistant material may form and/or define the entire, or an entirety of, the SSP body. Alternatively, it is also within the scope of the present disclosure that the corrosion-resistant material may form only a portion, a subset, or less than an entirety of the SSP body and/or that the corrosion-resistant material may be different from a material of a remainder of the SSP body. As an example, the corrosion-resistant material may include and/or be a corrosion-resistant sleeve 111 that is operatively attached to the SSP body and/or a corrosion-resistant coating 113 that covers at least a portion of the SSP body. As another example, the corrosion-resistant material may include and/or be a corrosion-resistant layer, coating, and/or ring that is operatively attached to and/or forms all or a portion of sealing device seat 140.
Examples of the erosion-resistant material, of the corrosion-resistant material, and/or of other materials that may be included within SSP body 110 include one or more of a nitride, a nitride coating, a boride, a boride coating, a carbide, a carbide coating, a tungsten carbide, a tungsten carbide coating, a self-hardening alloy, a work-hardening alloy, high manganese work-hardening steel, a ceramic, a high strength steel, a diamond-like material, a diamond-like coating, a heat-treated material, a magnetic material, and/or a radioactive material. When SSP body 110 includes and/or is formed from the magnetic material and/or the radioactive material, shockwave generation device 190 of FIG. 1 may be configured to detect and/or determine a proximity between SSP 100 and the shockwave generation device by detecting the presence of, or proximity to, the magnetic material and/or the radioactive material.
SSP conduit 116 may include and/or be any suitable fluid conduit that extends between the conduit-facing region and the formation-facing region and/or that may be configured to convey a fluid between the tubular conduit and the subterranean formation when isolation device 120 is in the open state. In addition, SSP conduit 116 may have any suitable inner diameter, cross-sectional area, and/or transverse cross-sectional area. As an example, SSP conduit 116 may include and/or be a cylindrical, or at least substantially cylindrical, SSP conduit. The cylindrical SSP conduit may have a diameter of at least 0.1 centimeter (cm), at least 0.15 cm, at least 0.2 cm, at least 0.25 cm, at least 0.5 cm, at least 0.75 cm, at least 1 cm, at least 1.5 cm, at least 2 cm, at least 2.5 cm, at least 3 cm, or at least 3.5 cm. Additionally or alternatively, the cylindrical SSP conduit may have a diameter of less than 6 cm, less than 5.5 cm, less than 5 cm, less than 4.5 cm, less than 4 cm, less than 3.5 cm, less than 3 cm, or less than 2.5 cm.
Additionally or alternatively, the SSP conduit may have a diameter that is less than an average tubular conduit diameter of tubular conduit 42. As examples, the SSP conduit may have a diameter that is less than 20 percent, less than 15 percent, less than 10 percent, or less than 5 percent of the average tubular conduit diameter of tubular conduit 42.
When SSP conduit 116 is not the cylindrical SSP conduit, a transverse cross-sectional area of the SSP conduit may be comparable, or equal, to the cross-sectional areas of cylindrical SSP conduits that have any of the above-listed diameters and/or diameter ranges. In addition, and when SSP conduits 116 of the plurality of SSPs 100 have different and/or varying diameters, the plurality of SSPs may define an average SSP conduit diameter, and the average SSP conduit diameter may include any of the above-listed diameters.
Isolation device 120 may include and/or be any suitable structure that may extend within SSP conduit 116, that may selectively restrict fluid flow through the SSP conduit, and/or that may be configured to selectively transition from the closed state to the open state responsive to the threshold shockwave. In general, isolation device 120 may be adapted, configured, designed, and/or constructed only to exhibit a single, or irreversible, transition from the closed state to the open state. As examples, and as discussed in more detail herein, isolation device 120 may be configured to break apart, to be destroyed, to be displaced from, and/or to irreversibly separate from a remainder of SSP 100 and/or from SSP body 110 upon transitioning from the closed state to the open state.
Isolation device 120 may include and/or be formed from any suitable material. As examples, the isolation device may include and/or be formed from a magnetic material, a radioactive material, and/or an acid-soluble material. Additional examples of materials of isolation device 120 are disclosed herein. When isolation device 120 includes and/or is formed from the magnetic material and/or the radioactive material, these materials may be detected by shockwave generation device 190, as discussed herein.
As discussed, isolation device 120 may be configured to transition from the closed state to the open state responsive to the threshold shockwave, and examples of the threshold shockwave and the threshold shockwave intensity are disclosed herein. Isolation device 120 also may be configured to remain in the closed state, or to resist transitioning from the closed state to the open state, during, or despite, a static pressure differential thereacross. This static pressure differential may have a significant magnitude, and examples of the static pressure differential, which also may be referred to herein as a threshold static pressure differential, include pressure differentials of at least 40 MPa, at least 45 MPa, at least 50 MPa, at least 55 MPa, at least 60 MPa, at least 65 MPa, at least 68 MPa, at least 68.9 MPa, at least 70 MPa, at least 75 MPa, at least 80 MPa, at least 85 MPa, at least 90 MPa, at least 95 MPa, or at least 100 MPa.
Isolation device 120 may be positioned, located, and/or present at any suitable location within SSP 100 and/or within SSP conduit 116 thereof. As an example, and as illustrated in FIG. 2, isolation device 120 may be positioned within a central portion of SSP conduit 116, proximal a midpoint of a length of SSP conduit 116, and/or such that the isolation device is offset from conduit-facing region 112 and also from formation-facing region 114. As another example, and as illustrated in FIG. 3, isolation device 110 may be aligned with and/or proximal formation-facing region 114. As yet another example, and as illustrated in FIG. 4, isolation device 110 may be aligned with and/or proximal conduit-facing region 112.
Isolation device 120 also may have any suitable isolation device thickness 127, as illustrated in FIG. 2. As an example, isolation device thickness 127 may be less than a wellbore tubular thickness 44 of wellbore tubular 40. Both isolation device thickness 127 and wellbore tubular thickness 44 may be measured in a direction that is parallel to central axis 118 of SSP conduit 116.
As illustrated in FIGS. 2-4, SSP body 110 may include and/or define an isolation device recess 119, which may be configured to receive isolation device 120. Isolation device recess 119 may extend from conduit-facing region 112 of SSP body 110, as illustrated schematically in FIG. 2 and less schematically in FIG. 4. Additionally or alternatively, isolation device recess 119 also may extend from formation-facing region 114 of SSP body 110, as illustrated schematically in FIG. 2 and less schematically in FIG. 3. When SSP body 110 includes isolation device recess 119, retention device 130 may be configured to at least temporarily retain the isolation device within the isolation device recess, as also illustrated in FIGS. 2-4.
Isolation device 120 also may have and/or define any suitable shape. As an example, a shape of an outer perimeter of isolation device 120 may be complementary to, or may correspond to, a transverse cross-sectional shape of isolation device recess 119, when present, and/or to a transverse cross-sectional shape of SSP conduit 116. As another example, and as illustrated in FIG. 2, isolation device 120 may include a conduit-facing side 128 and a formation-facing side 129, and the conduit-facing side and/or the formation-facing side may be planar, at least substantially planar, arcuate, partially spherical, partially parabolic, partially cylindrical, and/or partially hyperbolic. Stated another way, isolation device 120 may have a non-constant thickness as measured in a direction that extends between conduit-facing region 112 and formation-facing region 114 of SSP body 110 and/or as measured in a direction that is parallel to central axis 118.
In general, the shape of the isolation device may be selected such that the isolation device is shaped to resist at least a threshold static pressure differential between conduit-facing side 128 and formation-facing side 129 without damage thereto. Examples of the threshold static pressure differential are disclosed herein.
An example of isolation device 120 is an isolation disk 126, as illustrated in FIGS. 2-3. As illustrated in dashed lines in FIG. 3, isolation disk 126 may be configured to be retained within SSP 100 by retention device 130 when the isolation device is in closed state 121. However, and as illustrated in dash-dot lines, isolation disk 120 may be configured separate from a remainder of SSP 100 and/or to be displaced or otherwise conveyed into subterranean formation 34 in an intact, or at least substantially intact, state when the isolation device transitions to open state 122. This may include the isolation disk being conveyed from formation-facing region 114 of SSP body 110 and/or being conveyed from a formation-facing end of SSP conduit 116, with the formation-facing end of the SSP conduit being defined by formation-facing region 114. Isolation disk 126 may include any suitable material and/or materials of construction, examples of which include a metallic isolation disk that may be formed from one or more of steel, stainless steel, cast iron, a metal alloy, brass, and/or copper. When SSPs 100 include isolation disk 126 of FIGS. 2-3, and as discussed in more detail herein, retention device 130 may be configured to selectively release the isolation disk from the SSP responsive to the threshold shockwave.
Another example of isolation device 120 is a frangible isolation device 120 that is formed from a frangible material. The frangible material may be configured to break apart, to be destroyed, and/or to disintegrate responsive to, responsive to experiencing, and/or responsive to receipt of the threshold shockwave. Such an isolation device also may be referred to herein as a frangible disk 125 and/or as a frangible isolation disk 125 and is illustrated in FIGS. 2 and 4. Examples of the frangible material include a glass, a tempered glass, a ceramic, a frangible magnetic material, a frangible radioactive material, a frangible ceramic magnet, a frangible alloy, and/or an acrylic.
Additionally or alternatively, isolation device 120 may include and/or be formed from an explosive material that is configured to detonate and/or explode responsive to, responsive to experiencing, and/or responsive to receipt of the threshold shockwave. An isolation device 120 with this explosive material may be referred to as an explosive isolation device 120. Examples of explosive material that may be utilized include a solid explosive material, a brittle explosive material, a frangible explosive material, and/or a solid rocket fuel. The explosive material also may be referred to herein as an accelerant that accelerates stimulation of the subterranean formation due to the resulting explosion and generation of gases that promote greater fracture initiation and/or stimulation of the subterranean formation.
As discussed, frangible isolation devices 120, such as frangible disks 125, may be configured to break apart responsive to receipt of the threshold shockwave. As an example, and as illustrated in FIG. 4, such isolation devices may comprise a single piece prior to receipt of the threshold shockwave (as illustrated in dashed lines) and may comprise a plurality of spaced-apart pieces subsequent to receipt of the threshold shockwave (as illustrated in dash-dot lines). As another example, and when the isolation device is in closed state 121 (i.e., prior to receipt of the threshold shockwave), the isolation device may define a first maximum dimension 156, such as an outer diameter 124. Conversely, and when the isolation device is in open state 122 (i.e., subsequent to receipt of the threshold shockwave), the isolation device may define a second maximum dimension 158 that is less than the first maximum dimension. As further illustrated in FIG. 4, and while in closed state 121, outer diameter 124 of isolation device 120 may be greater than a minimum outer diameter 159 of SSP conduit 116. However, when in open state 122, second maximum dimension 158 may be less than minimum outer diameter 159.
Returning to FIG. 2, and as illustrated in dashed lines, SSP 100 may include a sealing structure 196. Sealing structure 196 may be configured to restrict fluid flow within SSP conduit 116 and past isolation device 120 when the isolation device is in closed state 121. As examples, sealing structure 196 may be configured to form a fluid seal between isolation device 120 and SSP body 110 and/or between isolation device 120 and retention device 130. Examples of sealing structure 196 include any suitable elastomeric sealing structure, polymeric sealing structure, compliant sealing structure, flexible sealing structure, compressible sealing structure, a resin, an epoxy, an adhesive, a gasket, and/or an O-ring.
It is within the scope of the present disclosure that SSP 100 may include a single isolation device 120 or a plurality of isolation devices 120. As an example, SSP 100 may include a first isolation device 120, which may be configured to restrict fluid flow from conduit-facing region 112 and through SSP conduit 116, and a second isolation device 120, which may be configured to restrict fluid flow from formation-facing region 114 and through SSP conduit 116.
When SSP 100 includes the first isolation device and the second isolation device, an intermediate portion of SSP conduit 116 may extend between, or separate, the first isolation device and the second isolation device. Under these conditions, the first isolation device may be configured to resist at least a first threshold static pressure differential between the tubular conduit and the intermediate portion of the SSP conduit. Similarly, the second isolation device may be configured to resist at least a second threshold static pressure differential between the subterranean formation and the intermediate portion of the SSP conduit. Examples of the first threshold static pressure differential and of the second threshold static pressure differential are disclosed herein with reference to the threshold static pressure differential of isolation devices 120.
Retention device 130 may include and/or be any suitable structure that may be adapted, configured, shaped, and/or selected to couple the isolation device to the SSP body and/or to retain the isolation device in the closed state prior to receipt of the threshold shockwave. It is within the scope of the present disclosure that, responsive to receipt of the threshold shockwave, retention device 130 may be configured to release isolation device 120 from SSP 100, such as when isolation device 120 includes isolation disk 126 of FIGS. 2-3. Under these conditions, retention device 130 may change, transition, and/or be deformed upon receipt of the threshold shockwave. As an example, retention device 130 may include at least one shear pin that shears, upon receipt of the threshold shockwave, to release the isolation device. As another example, retention device 130 may include at least one snap ring and corresponding groove, and the snap ring may be displaced from the groove, upon receipt of the threshold shockwave, to release the isolation device. As yet another example, retention device 130 may include a threaded retainer, and the threaded retainer may fail, upon receipt of the threshold shockwave, to release the isolation device.
Additionally or alternatively, it also is within the scope of the present disclosure that retention device 130 may be rigid, may be fixed, may be nonresponsive to (i.e. not damaged by) receipt of the threshold shockwave, and/or may not respond to the threshold shockwave, such as when isolation device 120 includes frangible disk 125 of FIGS. 2 and 4. Under these conditions, isolation device 120 may fragment, fail, or otherwise be displaced from the retention device and the SSP body upon transitioning from the closed state to the open state, as illustrated in FIG. 4.
At least a portion of retention device 130 may be separate and/or distinct from SSP body 110. Additionally or alternatively, at least a portion of retention device 130 may be defined by SSP body 110. As an example, isolation device recess 119 of FIGS. 2-4 may form a portion of retention device 130 and/or may at least partially retain isolation device 120 within SSP 100.
Retention device 130 may include and/or be formed from any suitable material and/or materials, including a magnetic material and/or a radioactive material. Such materials may be detected by shockwave generation device 190, as discussed herein.
Sealing device seat 140 may include any suitable structure that may be defined by conduit-facing region 112 of SSP body 110 and/or that may be adapted, configured, designed, constructed, and/or shaped to form the fluid seal with the sealing device. In addition, sealing device seat 140 may have a preconfigured, pre-established, and/or preselected geometry, such as when the geometry of the sealing device seat is established prior to SSP 100 being operatively attached to wellbore tubular 40 and/or prior to the wellbore tubular being located, installed, and/or positioned within the subterranean formation. Sealing device seat 140 may be erosion-resistant, may be formed from the erosion-resistant material, may be corrosion-resistant, and/or may be formed from the corrosion-resistant material, as discussed herein. Additionally or alternatively, sealing device seat 140 may be defined by a seat body, which may form a portion of SSP body 110 and/or may be erosion-resistant, may be formed from the erosion-resistant material, may be corrosion-resistant, and/or may be formed from the corrosion-resistant material.
Sealing device seat 140 may have, define, and/or include any suitable shape, and the sealing device seat is illustrated in dashed lines in FIGS. 2-3 to illustrate several of these potential shapes. In general, sealing device seat 140 may include and/or be a symmetrical sealing device seat. Examples of the sealing device seat and/or of a shape thereof include a partially spherical sealing device seat, a truncated spherical cap sealing device seat, a conic section sealing device seat, an at least partially cone-shaped sealing device seat, an at least partially funnel-shaped sealing device seat, and/or a tapered sealing device seat. It is within the scope of the present disclosure that the shape of the sealing device seat of each of the plurality of SSPs may be similar, or at least substantially similar. However, this is not required.
As an additional example, and as illustrated in FIG. 2, the sealing device seat may converge, within SSP body 110, from a first diameter 148, which is defined in conduit-facing region 112 of SSP body 110, to a second diameter 149, which is defined within SSP body 110. The first diameter may be greater than the second diameter, and the second diameter may approach, or be, an outer diameter 117 of SSP conduit 116, which also may be referred to herein as an SSP conduit diameter 117. However, this is not required to all embodiments.
As illustrated in FIG. 2, sealing device 142 may be operatively positioned and/or engaged with sealing device seat 140 to form fluid seal 144. An example of sealing device 142 includes a ball sealer 143. When sealing device 142 includes ball sealer 143, sealing device seat 140 also may be referred to herein as a ball sealer seat 141, and ball sealer seat 141 may have a ball sealer seat radius of curvature that is equal, or at least substantially equal, to a ball sealer radius of ball sealer 143.
As discussed, SSPs 100 may include and/or be associated with shockwave generation structure 180, which may be adapted, configured, designed, and/or constructed to generate the shockwave. Shockwave generation structure 180 may include and/or be any suitable structure. As examples, shockwave generation structure 180 may include a mechanical shockwave generation structure, such as may be configured to mechanically generate the shockwave, a chemical shockwave generation structure, such as may be configured to chemically generate the shockwave, and/or an explosive shockwave generation structure, and such as may be configured to explosively generate the shockwave. When SSPs 100 include shockwave generation structure 180, the SSPs further may include a triggering device 182, which may be configured to actuate the shockwave generation structure, such as to cause the shockwave generation structure to generate the shockwave. Examples of triggering device 182 include any suitable wireless, or wirelessly actuated, triggering device, remote, or remotely actuated, triggering device, and/or wired triggering device.
As illustrated in dashed lines in FIG. 2, SSP 100 further may include a transition assist structure 186. Transition assist structure 186 may be configured to assist and/or facilitate isolation device 120 transitioning from the closed state to the open state responsive to experiencing the threshold shockwave and may include any suitable structure. As an example, transition assist structure 186 may include and/or be a point load, on isolation device 120, that is configured to initiate failure of the isolation device responsive to receiving the threshold shockwave. As another example, transition assist structure 186 may include and/or be a weak point on and/or within isolation device 120 that is configured to initiate failure of the isolation device responsive to receiving the threshold shockwave.
As also illustrated in dashed lines in FIG. 2, SSP 100 may include a barrier material 170. Barrier material 170 may extend at least partially within SSP conduit 116 and may be configured to remain within the SSP conduit during installation of wellbore tubular 40 into the subterranean formation. Such a configuration may protect SSP 100 and/or isolation device 120 thereof from damage during the installation and/or may prevent foreign material from entering at least a portion of the SSP conduit during the installation. In addition, barrier material 170 also may be configured to automatically separate, such as by dissolving, from SSP 100 and/or from SSP conduit 116 thereof responsive, or subsequent, to fluid contact with the wellbore fluid.
Barrier material 170 may be placed and/or present within any suitable portion of SSP conduit 116. As an example, the barrier material may extend between isolation device 120 and conduit-facing region 112 of SSP body 110. As another example, the barrier material may extend between isolation device 120 and formation-facing region 114 of SSP body 110.
Barrier material 170 may include any suitable material and/or materials. As an example, the barrier material may be selected to be, or may be, soluble within the wellbore fluid. More specific examples of barrier material 170 include polyglycolic acid and/or polylactic acid. As another example, barrier material 170 may include and/or be an explosive material. The explosive material may be configured to detonate and/or explode responsive to, responsive to experiencing, and/or responsive to receipt of the threshold shockwave. Examples of the explosive material are disclosed herein.
As illustrated in dashed lines in FIG. 2 and in solid lines in FIGS. 5-6, SSP 100 also may include a nozzle 160. Nozzle 160 may be configured to generate a fluid jet 166, as illustrated in FIGS. 5-6, at formation-facing region 114 of SSP body 110 and/or at a formation-facing end of SSP conduit 116. The fluid jet may be generated responsive to fluid flow from tubular conduit 42 and/or into subterranean formation 34 via the SSP conduit.
Nozzle 160 may include any suitable structure. As an example, nozzle 160 may include and/or be a jet nozzle. As another example, nozzle 160 may include a restriction, or a restriction region, 161 that may be configured to accelerate the fluid flow, as illustrated in FIG. 2. Similarly, nozzle 160 may be formed from any suitable material, examples of which are disclosed herein with reference to the erosion-resistant materials and/or the corrosion-resistant materials of SSP body 110.
As illustrated in FIG. 5, nozzle 160 may include a gimbal structure 162. Gimbal structure 162 may be configured to permit rotation of nozzle 160 and/or of fluid jet 166. This may include rotation of nozzle 160 and/or of fluid jet 166 about and/or around central axis 118, such as at an angle of rotation 164. This rotation of nozzle 160 and/or of fluid jet 166 may be responsive to and/or powered by the fluid flow through SSP conduit 116.
As illustrated in FIG. 6, nozzle 160 additionally or alternatively may include a rotation structure 168. Rotation structure 168 may be configured to permit rotation of nozzle 160 about an outer circumference of wellbore tubular 40. Under these conditions, and as illustrated, nozzle 160 may be oriented at an angle such that fluid jet 166 generates a torque that provides a motive force for the rotation of the nozzle about and/or around the outer circumference of the wellbore tubular. Such motion of the nozzle may create a groove, slot, and/or channel within the subterranean formation. This groove, slot, and/or channel may extend away from the wellbore tubular and/or may extend perpendicularly, or at least substantially perpendicularly, from the wellbore tubular.
Returning more generally to FIGS. 2 and 5-6, nozzle 160 may be present within any suitable portion of SSP 100 and/or within wellbore tubulars 40 that include SSP 100. As an example, nozzle 160 may be proximal, or may form a portion of, formation-facing region 114 of SSP body 110 and/or may be proximal, or may form a portion of, the formation-facing end of SSP conduit 116. As another example, nozzle 160 may be distal, or relatively distal, conduit-facing region 112 of SSP body 110 and/or a conduit-facing end of SSP conduit 116. As yet another example, nozzle 160 may extend outward from an outer surface of wellbore tubular 40.
FIG. 7 is a less schematic profile view of a selective stimulation port (SSP) 100 according to the present disclosure, while FIG. 8 is a view of a formation-facing side of the SSP of FIG. 7 and FIG. 9 is a cross-sectional view of the SSP of FIGS. 7-8 taken along line 9-9 of FIG. 8. SSP 100 of FIGS. 7-9 may include and/or be a more detailed illustration of SSPs 100 of FIGS. 1-6, and any of the structures, functions, and/or features discussed herein with reference to any of FIGS. 1-6 may be included in and/or utilized with SSP 100 of FIGS. 7-9 without departing from the scope of the present disclosure. Similarly, any of the structures, functions, and/or features of SSP 100 of FIGS. 7-9 may be included in and/or utilized with SSPs 100 of FIGS. 1-6 without departing from the scope of the present disclosure.
As illustrated in FIGS. 7-9, SSP 100 includes an SSP body 110 that defines an SSP conduit 116. SSP body 110 has a conduit-facing region 112 and an opposed formation-facing region 114. SSP body 110 also has a projecting region 150, 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 100 also includes a tool-receiving portion 176, which may be configured to receive a tool during operative attachment of the SSP to a wellbore tubular, and an attachment region 178, which may be configured to interface with the wellbore tubular when the SSP is operatively attached to the wellbore tubular. As an example, attachment region 178 may include threads, and SSP 100 may be configured to be rotated, via receipt of the tool within tool-receiving portion 176, to permit threading of the SSP into the wellbore tubular.
As perhaps illustrated most clearly in FIG. 9, SSP 100 further includes a sealing device seat 140, which may be configured to receive a sealing device 142, and an isolation device 120. In FIG. 9, isolation device 120 is illustrated in closed state 121.
FIG. 10 is flowchart depicting methods 200, according to the present disclosure, of stimulating a subterranean formation, while FIGS. 11-16 are schematic cross-sectional views of steps in a process flow 300 for stimulating a subterranean formation. Process flow 300 may be an illustration of methods 200, and methods 200 and/or process flow 300 may be performed utilizing selective stimulation ports 100 according to the present disclosure, such as SSPs 100 of FIGS. 1-9, and/or wellbore tubulars 40 that include the selective stimulation ports.
Methods 200 may include positioning a shockwave generation device at 205 and/or changing a pressure within a tubular conduit at 210. Methods 200 include generating a shockwave at 215 and may include propagating the shockwave at 220 and/or attenuating the shockwave at 225. Methods 200 further include transitioning an isolation device at 230 and may include flowing a stimulant fluid into a subterranean formation at 235, stimulating the subterranean formation at 240, flowing a sealing device at 245, repeating at least a portion of the methods at 250, and/or producing a reservoir fluid from the subterranean formation at 255.
Positioning the shockwave generation device at 205 may include positioning the shockwave generation device within the tubular conduit and/or proximal to a selective stimulation port (SSP) that includes the isolation device. As an example, and as illustrated in FIG. 11, a tubular conduit 42 of a wellbore tubular 40 that extends within a subterranean formation 34 may not have and/or include a shockwave generation device prior to the positioning at 205. Additionally or alternatively, the shockwave generation device may not be positioned near and/or proximal an SSP 100 that is to be transitioned during the transitioning at 230 and/or responsive to the generating at 215. However, and as illustrated in FIG. 12, the tubular conduit may include shockwave generation device 190 and/or shockwave generation device 190 may be oriented near and/or proximal the SSP 100 subsequent to the positioning at 205.
The positioning at 205 may be accomplished in any suitable manner. As an example, the positioning at 205 may include flowing the shockwave generation device into proximity with the SSP. This may include flowing from a surface region, such as surface region 30 of FIG. 1, and/or flowing along the tubular conduit. The positioning at 205 further may include detecting a proximity of the shockwave generation device to the SSP. This may include detecting one or more properties of the SSP, detecting a material of the SSP, and/or detecting one or more properties of a portion of the wellbore tubular to which the SSP is operatively attached. As an example, the detecting may include detecting a casing collar, such as via and/or utilizing a casing collar locator. As another example, and as discussed, the SSP may include a magnetic material and/or a radioactive material, and the detecting may include detecting the magnetic material and/or the radioactive material.
As discussed herein with reference to FIG. 1, SSPs 100 according to the present disclosure may include a built-in shockwave generation structure 180. Under these conditions, methods 200 may be performed without performing the positioning at 205.
Changing the pressure within the tubular conduit at 210 may include increasing a pressure within the tubular conduit. Additionally or alternatively, the changing at 210 may include decreasing the pressure within the tubular conduit.
When the changing at 210 includes increasing the pressure within the tubular conduit, the increasing may include pressurizing with a stimulant fluid and/or pressurizing to at least a threshold stimulation pressure. As an example, the increasing the pressure may include increasing to permit and/or facilitate the stimulating at 240. Examples of the threshold stimulation pressure include pressures, static pressures, or static stimulation pressures of at least 10 MPa, at least 15 MPa, at least 20 MPa, at least 25 MPa, at least 30 MPa, at least 35 MPa, at least 40 MPa, at least 45 MPa, at least 50 MPa, at least 55 MPa, or at least 60 MPa. Examples of the stimulant fluid include a water-based stimulant fluid, an oil-based stimulant fluid, an acid, and/or a fracturing fluid. The stimulant fluid may include a proppant.
When the changing at 210 includes decreasing the pressure within the tubular conduit, the decreasing may include at least partially evacuating the tubular conduit and/or removing at least a portion, a majority, or even substantially all liquid from the tubular conduit. As an example, decreasing the pressure may include decreasing to permit and/or facilitate an inrush of reservoir fluid into the tubular conduit subsequent to the transitioning at 230. Such an inrush of reservoir fluid may flush, clear, and/or otherwise remove debris and/or particulate matter from the subterranean formation, thereby decreasing a resistance to fluid flow through the subterranean formation.
As discussed in more detail herein, the SSPs may be configured to remain in a closed state and/or to resist transitioning from the closed state to an open state when a pressure differential across an isolation device thereof is less than a threshold static pressure differential. In general, the threshold static pressure differential is greater than the threshold stimulation pressure and/or is greater than a pressure differential across the isolation device that may be generated during the changing at 210 and/or prior to the generating at 215. Examples of pressure differentials that may be generated prior to the generating at 215 include external pressure swings during running of the wellbore tubular, pressure differentials generated during wellbore tubular pressure testing, pressure differentials generated during stimulation of the subterranean formation, and/or pressure differentials generated during evacuation of all fluids from the wellbore tubular, such as to generate an underbalanced condition. As such, methods 200 further may include retaining the isolation device in the closed state during the changing at 210 and/or prior to the generating at 215. Examples of the threshold static pressure differential are disclosed herein.
Generating the shockwave at 215 may include generating the shockwave within a wellbore fluid that extends within the tubular conduit. In addition, the generating at 215 may include generating within a region of the tubular conduit that is proximal the SSP such that a magnitude of the shockwave is greater than a threshold shockwave intensity that is sufficient to transition the isolation device of the SSP from the closed state to the open state (i.e., such that the SSP receives and/or experiences the threshold shockwave). This is illustrated in FIG. 13 by the generation of a shockwave 194 with shockwave generation device 190.
The generating at 215 may be accomplished in any suitable manner. As an example, the generating at 215 may include detonating an explosive charge within the tubular conduit. The explosive charge may be associated with and/or may form a portion of the shockwave generation device, which is separate from the SSP, and/or may be associated with and/or may form a portion of the shockwave generation structure, which forms a portion of the SSP. As another example, the generating at 215 may include actuating a triggering device, such as a blast cap. The actuating may include remotely actuating and/or wirelessly actuating the triggering device.
When the generating at 215 includes generating with the shockwave generation device, the shockwave generation device may be located within the tubular conduit such that the shockwave has greater than the threshold shockwave intensity within the wellbore fluid that extends within the tubular conduit and in contact with the isolation device. In addition, the shockwave may have less, may have decayed to less, and/or may have been attenuated to less than the threshold shockwave intensity at a distance that is greater than a maximum effective distance from the shockwave generation device. Examples of the maximum effective distance are disclosed herein.
It is within the scope of the present disclosure that the generating at 215 may include generating such that the shockwave emanates at least substantially symmetrically from the shockwave generation device and/or such that the shockwave emanates at least substantially isotropically from the shockwave generation device. Additionally or alternatively, the generating at 215 may include generating such that the shockwave is symmetrical, or at least substantially symmetrical, within a given transverse cross-section of the tubular conduit and/or such that the shockwave has a constant, or at least substantially constant, magnitude within the given transverse cross-section of the tubular conduit at a given point in time.
The shockwave may have any suitable maximum shockwave pressure and/or maximum shockwave duration that is sufficient to transition the isolation device from the closed state to the open state but insufficient to cause damage to the wellbore tubular. Examples of the maximum shockwave pressure and/or of the maximum shockwave duration are disclosed herein.
Propagating the shockwave at 220 may include propagating in any suitable manner. As examples, the propagating at 220 may include propagating the shockwave from the shockwave generation device, propagating the shockwave to the SSP, propagating the shockwave to the isolation device of the SSP, and/or propagating the shockwave in and/or within the wellbore fluid.
Attenuating the shockwave at 225 may include attenuating the shockwave in any suitable manner. As examples, the attenuating at 225 may include attenuating by and/or within the wellbore fluid. This may include dissipating at least a portion of the shockwave within the wellbore fluid and/or absorbing energy from the shockwave with the wellbore fluid. The attenuating at 225 may include attenuating at any suitable attenuation rate, examples of which are disclosed herein.
Transitioning the isolation device at 230 may include transitioning the isolation device from the closed state to the open state and/or transitioning to permit fluid communication between the tubular conduit and the subterranean formation via the SSP conduit. The transitioning at 230 may be at least partially responsive to the generating at 215. As an example, the transitioning may be initiated and/or triggered by receipt of the threshold shockwave with and/or by the isolation device.
The transitioning at 230 may be accomplished in any suitable manner. As an example, the transitioning at 230 may include shattering a frangible disk that defines at least a portion of the isolation device. As another example, the transitioning at 230 may include displacing an isolation disk, which defines at least a portion of the isolation device, from the SSP conduit. The displacing may include shearing a pin that retains the isolation disk within the SSP conduit and/or defeating a clip that retains the isolation device within the SSP conduit.
Flowing the stimulant fluid into the subterranean formation at 235 may include flowing subsequent to the transitioning at 230 and/or responsive to the transitioning at 230. In addition, the flowing at 235 may include flowing to permit and/or facilitate the stimulating at 240.
As an example, and when methods 200 include the changing at 210 and the changing at 210 includes pressurizing the tubular conduit, the stimulation pressure within the tubular conduit may provide a motive force for the flowing at 235, and the transitioning at 230 may provide a fluid pathway for flow of the stimulant fluid. This is illustrated in FIG. 14, with SSP 100 in open state 122 and stimulant fluid 70 flowing from wellbore tubular 42 into subterranean formation 34 via SSP conduit 116 of the SSP.
As discussed herein, SSP 100 may include a nozzle, such as nozzle 160 of FIGS. 2 and 5-6. Under these conditions, the flowing at 235 further may include accelerating the stimulant fluid with the nozzle.
Stimulating the subterranean formation at 240 may include stimulating the subterranean formation via the SSP conduit. As an example, and as discussed herein with reference to the flowing at 235, the stimulant fluid may flow from the tubular conduit into the subterranean formation via the SSP conduit. The stimulating at 240 may include stimulating in any suitable manner. As examples, the stimulating at 240 may include fracturing the subterranean formation, propping the subterranean formation, flushing the subterranean formation, acid treating the subterranean formation, and/or increasing a surface area, a surface contact area, and/or a permeability of the subterranean formation, as indicated in FIG. 14 at 38.
Flowing the sealing device at 245 may include flowing any suitable sealing device via and/or along the tubular conduit and into contact and/or engagement with a sealing device seat of the SSP. This may include flowing to form a fluid seal between the sealing device and the sealing device seat and/or flowing to selectively restrict fluid flow from the tubular conduit and into the subterranean formation via the SSP conduit. This is illustrated in FIG. 15. Therein, a sealing device 142 is illustrated as flowing into contact and engaging with a sealing device seat 140 of SSP 100. The flowing at 245 may include flowing within and/or via the stimulant fluid and/or may be performed subsequent to performing the flowing at 235 for at least a threshold stimulation time.
Repeating at least the portion of the methods at 250 may include repeating any suitable portion of methods 200, such as to transition another isolation device that may be operatively attached to the wellbore tubular and/or to stimulate another portion, zone, and/or region of the subterranean formation. As an example, the wellbore tubular may include a plurality of spaced-apart SSPs, and the repeating at 250 may include repeating at least the changing at 210, the generating at 215, the transitioning at 230, the flowing at 235, and the flowing at 245 to stimulate a portion of the subterranean formation that is proximal a second SSP of the plurality of SSPs. Additionally or alternatively, the repeating at 250 also may include repeating a plurality of times to stimulate a plurality of portions of the subterranean formation, with each of the plurality of portions of the subterranean formation associated with a respective SSP of the plurality of SSPs.
Producing the reservoir fluid from the subterranean formation at 255 may include producing in any suitable manner. As an example, the producing at 255 may include flowing the reservoir fluid from the subterranean formation and into the tubular conduit via the SSP conduit. As another example, the producing at 255 may include flowing the reservoir fluid via the tubular conduit, from the subterranean formation, and/or to the surface region. The producing at 255 is illustrated in FIG. 16. Therein, reservoir fluid 36 flows from subterranean formation 34 and into tubular conduit 42 via SSP conduit 116 of SSP 100.
In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, process flows, 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.
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 selective stimulation ports, wellbore tubulars, and methods disclosed herein are applicable to the oil and gas industries.
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 selective stimulation port (SSP) configured to be operatively attached to a wellbore tubular that defines a tubular conduit and is configured to extend within a wellbore that extends within a subterranean formation, the SSP comprising:

an SSP body having a conduit-facing region and a formation-facing region, wherein the SSP body is configured to be positioned within the wellbore tubular such that the conduit-facing region faces toward the tubular conduit and also such that the formation-facing region faces away from the tubular conduit, and further wherein the SSP body defines an SSP conduit that extends between the conduit-facing region and the formation-facing region;

an isolation device extending within the SSP conduit and configured to selectively transition from a closed state, in which the isolation device restricts fluid flow through the SSP conduit, and an open state, in which the isolation device permits fluid flow through the SSP conduit, responsive to a shockwave, within a wellbore fluid extending within the tubular conduit, that has greater than a threshold shockwave intensity;

a retention device coupling the isolation device to the SSP body to retain the isolation device in the closed state prior to receipt of the shockwave that has greater than the threshold shockwave intensity; and

a sealing device seat defined by the conduit-facing region of the SSP body, wherein the sealing device seat is shaped to form a fluid seal with a sealing device, which flows, via the tubular conduit, into engagement with the sealing device seat, and to selectively restrict fluid flow from the tubular conduit to the subterranean formation, via the SSP conduit, when the sealing device forms the fluid seal therewith.

2. The SSP of claim 1, wherein at least a portion of the isolation device is configured to separate from the SSP body upon transitioning from the closed state to the open state.

3. The SSP of claim 1, wherein the isolation device is formed from a frangible material configured to break apart upon experiencing the shockwave that has greater than the threshold shockwave intensity.

4. The SSP of claim 1, wherein the SSP further includes a nozzle configured to generate a fluid jet at a formation-facing end of the SSP conduit responsive to fluid flow from the tubular conduit via the SSP conduit.

5. The SSP of claim 1, wherein the SSP further includes a barrier material extending at least partially within the SSP conduit, wherein the barrier material is configured to remain within the SSP conduit during installation of the wellbore tubular into the subterranean formation and to automatically separate from the SSP conduit responsive to fluid contact with the wellbore fluid, and further wherein the barrier material is configured to prevent foreign material from entering at least a portion of the SSP conduit during installation of the wellbore tubular into the subterranean formation.

6. The SSP of claim 1, wherein the SSP further includes a shockwave generation structure configured to generate the shockwave that has greater than the threshold shockwave intensity.

7. The SSP of claim 1, wherein the sealing device seat is a symmetrical sealing device seat.

8. The SSP of claim 1, wherein the SSP body is formed from a different material than a material of the wellbore tubular.

9. The SSP of claim 1, wherein, prior to experiencing the shockwave that has greater than the threshold shockwave intensity, the isolation device is configured to remain in the closed state during a static pressure differential of at least 68 megapascals thereacross.

10. The SSP of claim 1, wherein the shockwave is attenuated by the wellbore fluid at an attenuation rate of at least 10 megapascals per meter.

11. The SSP of claim 1, wherein the shockwave includes a maximum pressure of at least 170 megapascals and a maximum duration of less than 0.1 seconds.

12. The SSP of claim 1, wherein the shockwave exhibits greater than the threshold shockwave intensity within the tubular conduit over a maximum effective distance of 4 meters along a length of the tubular conduit.

13. The SSP of claim 1, wherein the shockwave is generated by a shockwave generation device, wherein the shockwave has a peak shockwave intensity proximate the shockwave generation device, wherein the threshold shockwave intensity is less than a threshold fraction of the peak shockwave intensity, wherein an intensity of the shockwave at a distance of 4 meters from the shockwave generation device is less than the threshold shockwave intensity, and further wherein the shockwave propagates, from the shockwave generation device and to the SSP, within the wellbore fluid.

14. A casing string including the SSP of claim 1.

15. A method of stimulating a subterranean formation, the method comprising:

generating a shockwave within a wellbore fluid that extends within a tubular conduit, wherein the tubular conduit is defined by a wellbore tubular that extends within the subterranean formation and includes the SSP of claim 1, wherein the generating includes generating within a region of the tubular conduit that is proximal the SSP such that a magnitude of the shockwave, as received by the SSP, is greater than the threshold shockwave intensity that is sufficient to transition the isolation device of the SSP from the closed state to the open state; and

responsive to receipt of the shockwave that has greater than the threshold shockwave intensity, transitioning the isolation device from the closed state to the open state to permit fluid communication, via the SSP conduit, between the tubular conduit and the subterranean formation.

16. The method of claim 15, wherein the generating includes detonating an explosive charge within the tubular conduit.

17. The method of claim 16, wherein the explosive charge is associated with a shockwave generation device that is present within the tubular conduit, wherein, prior to the generating, the method further includes positioning the shockwave generation device within the tubular conduit and proximal the SSP.

18. The method of claim 17, wherein the positioning includes detecting a proximity of the shockwave generation device to the SSP.

19. The method of claim 17, wherein the shockwave has a peak shockwave intensity proximate the shockwave generation device, wherein the threshold shockwave intensity is less than a threshold fraction of the peak shockwave intensity, and further wherein an intensity of the shockwave at a distance of 4 meters from the shockwave generation device is less than the threshold shockwave intensity.

20. The method of claim 15, wherein the method further includes propagating the shockwave, from the shockwave generation device to the SSP, within the wellbore fluid.

21. The method of claim 15, wherein the method further includes attenuating the shockwave by the wellbore fluid at an attenuation rate of at least 10 megapascals per meter.

22. The method of claim 15, wherein the generating the shockwave includes generating with a maximum shockwave pressure of at least 170 megapascals and a maximum shockwave duration of less than 0.1 seconds.

23. The method of claim 15, wherein the transitioning includes shattering a frangible disk that defines at least a portion of the isolation device.

24. The method of claim 15, wherein the method further includes stimulating the subterranean formation via the SSP conduit.